ex99-1.htm


		News Release
Copano Energy, L.L.C.

	Contacts:		Carl A. Luna, SVP and 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

COPANO ENERGY REPORTS SECOND QUARTER 2010 RESULTS

Total Distributable Cash Flow Increases 8% Over First Quarter

HOUSTON, August 5, 2010 — Copano Energy, L.L.C. (NASDAQ: CPNO) today announced its financial results for the three and six months ended June 30, 2010.

“We are pleased with the sequential improvement in our second quarter distributable cash flow,” said Bruce Northcutt, Copano Energy’s President and Chief Executive Officer. “Despite declining NGL prices during the quarter, second quarter distribution coverage was higher than first quarter coverage primarily due to the successful start up of the fractionation facility at our Houston Central plant and continued volume growth behind our Saint Jo plant.”

“As we move into the second half of the year, we believe producer activity behind our pipelines in the Eagle Ford Shale, Barnett Shale Combo Play and Woodford Shale will drive growth in our distributable cash flow and distribution coverage,” Northcutt added.

Second Quarter Financial Results

Revenue for the second quarter of 2010 increased 28% to $230.1 million compared to $180.2 million for the second quarter of 2009. Total segment gross margin increased to $56.8 million for the second quarter of 2010 compared to $51.1 million for the first quarter of 2010 and to $52.3 million for the second quarter of 2009, increases of 11% and 9%, respectively.

Adjusted EBITDA for the second quarter of 2010 increased to $39.7 million compared to $35.7 million for the first quarter of 2010 and to $39.0 million for the second quarter of 2009. Non-cash amortization expense relating to the option component of Copano’s risk management portfolio, which is not added back in determining adjusted EBITDA, totaled $8.1 million, $8.0 million and $9.3 million, respectively, for the second quarter of 2010, the first quarter of 2010 and the second quarter of 2009.

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Total distributable cash flow for the second quarter of 2010 increased to $33.5 million from $30.9 million in the first quarter, an increase of 8%, and from $32.9 million for the second quarter of 2009, an increase of 2%. Second quarter 2010 total distributable cash flow represents 87% coverage of the second quarter distribution of $0.575 per unit, based on total common units outstanding on the distribution record date.

Net loss for the second quarter of 2010 totaled $21.1 million, or $0.32 per unit on a diluted basis, and includes a non-cash impairment charge of $25.0 million related to Copano’s investment in its unconsolidated affiliate, Bighorn Gas Gathering, L.L.C. (Bighorn). Net income was $6.0 million, or $0.10 per unit on a diluted basis, for the second quarter of 2009. Drivers of the $27.1 million decrease primarily included:

a $25.8 million decrease in equity in earnings of unconsolidated affiliates as a result of the non-cash impairment charge mentioned above. The non-cash impairment charge primarily resulted from a continued weak Rocky Mountains pricing environment for natural gas, lack of drilling activity in Wyoming’s Powder River Basin and a downward shift in the Colorado Interstate Gas forward price curve;

·	a $2.2 million decrease in earnings related to additional depreciation and amortization expenses primarily related to expanded operations in Texas;

·	a $2.4 million increase in general and administrative expenses ($1.6 million), property and other taxes ($0.5 million) and operations and maintenance expenses ($0.3 million);

·	a $1.3 million increase in interest and other financing costs primarily related to (i) an unrealized gain on interest rate swaps for 2010 of $0.9 million compared to a $2.1 million gain in 2009 and (ii) an increase of $0.1 million in interest expense related to Copano’s senior credit facility;

offset by:

a $4.6 million increase in total segment gross margin consisting of a $13.2 million increase in combined operating segment gross margins primarily reflecting average NGL price increases of 42% on the Conway index and 43% on the Mt. Belvieu index, offset in part by lower overall service throughput volumes and a decrease of $8.6 million from Copano’s commodity risk management activities.

Weighted average diluted units outstanding totaled 65.5 million for the second quarter of 2010 as compared to 57.9 million for the same period in 2009.

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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 reconciled to the most directly comparable GAAP measures at the end of this news release.

Second 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 of 51% and in Fort Union Gas Gathering, L.L.C. (Fort Union) of 37.04%.

Oklahoma

Segment gross margin for Oklahoma increased 25% for the second quarter of 2010 to $21.8 million, compared to $17.5 million for the second quarter of 2009. The increase resulted primarily from a 28% increase in realized margins on service throughput compared to the second quarter of 2009 ($0.92 per MMBtu in 2010 compared to $0.72 per MMBtu in 2009), reflecting higher NGL and natural gas prices. During the second quarter of 2010, weighted-average NGL prices on the Conway index, based on Copano’s product mix for the period, were $36.34 per barrel compared to $25.57 per barrel during the second quarter of 2009, an increase of 42%. During the second quarter of 2010, natural gas prices on the CenterPoint East index averaged $3.86 per MMBtu compared to $2.70 per MMBtu during the second quarter of 2009, an increase of 43%.

The Oklahoma segment gathered an average of 259,972 MMBtu/d of natural gas, processed an average of 156,204 MMBtu/d of natural gas and produced an average of 16,653 Bbls/d of NGLs at its own plants and third-party plants during the second quarter of 2010. In comparison to the second quarter of 2009, this represents a 3% decrease in service throughput, a 6% decrease in plant inlet volumes and a 4% increase in NGLs produced. The decrease in service throughput is primarily attributable to reduced drilling in rich gas areas, normal production declines and weather related issues during 2010.

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Texas

Segment gross margin for Texas increased 36% for the second quarter of 2010 to $31.8 million, compared to $23.3 million for the second quarter of 2009. The increase resulted primarily from a 51% increase in realized margins on service throughput compared to the second quarter of 2009 ($0.62 per MMBtu in 2010 compared to $0.41 per MMBtu in 2009), reflecting higher NGL prices and the impact of the start up of Copano’s fractionation facilities. During the second quarter of 2010, weighted-average NGL prices on the Mt. Belvieu index, based on Copano’s product mix for the period, were $43.14 per barrel compared to $30.12 per barrel during the second quarter of 2009, an increase of 43%. During the second quarter of 2010, natural gas prices on Houston Ship Channel index averaged $4.04 per MMBtu compared to $3.44 per MMBtu during the second quarter of 2009, an increase of 17%.

The increase in realized margins for the Texas segment was offset by decreased service throughput and processing volumes. During the second quarter of 2010, the Texas segment provided gathering, transportation and processing services for an average of 559,876 MMBtu/d of natural gas compared to 630,674 MMBtu/d for the second quarter of 2009, a decrease of 11%. The Texas segment gathered an average of 327,839 MMBtu/d of natural gas, processed an average of 469,019 MMBtu/d of natural gas at its plants and third-party plants and produced an average of 18,382 Bbls/d of NGLs at its plants and third-party plants during the second quarter of 2010, representing an increase of 13% of volumes gathered, a decrease of 16% of volumes processed and flat NGL production as compared to the second quarter of 2009. Volumes originating from the Texas segment and delivered to the Houston Central plant decreased 6% from the second quarter of 2009. Lower margin volumes delivered to the Houston Central plant and originating from sources other than the Texas segment decreased 29% from the second quarter of 2009 primarily as a result of a third party pipeline diverting volumes away from the Houston Central plant during the quarter.

Rocky Mountains

Segment gross margin for Rocky Mountains totaled $1.1 million in the second quarter of 2010 compared to $0.7 million for the second quarter of 2009. The increase in segment gross margin was the result of higher compressor rental income from Bighorn, which began during the second quarter of 2009.

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 in Copano’s financial statements under “Equity in earnings from unconsolidated affiliates.” Average pipeline throughput for Bighorn and Fort Union on a combined basis decreased 8% to 900,047 MMBtu/d in the second quarter of 2010 as compared to 980,694 MMBtu/d in the second quarter of 2009 as the weak Rocky Mountains pricing environment has continued to delay drilling activity.

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Corporate and Other

Corporate and other gross margin includes Copano’s commodity risk management activities. These activities contributed a gain of $2.1 million for the second quarter of 2010 compared to $10.8 million for the second quarter of 2009. The gain for the second quarter of 2010 included $8.1 million of non-cash amortization expense relating to the option component of Copano’s risk management portfolio offset by $9.5 million of net cash settlements received for expired commodity derivative instruments and $0.7 million of unrealized gains on undesignated economic hedges. The second quarter 2009 gain included $20.8 million of net cash settlements received for expired commodity derivative instruments offset by $0.7 million of unrealized mark-to-market losses on undesignated economic hedges and $9.3 million of non-cash amortization expense relating to the option component of Copano’s risk management portfolio.

Year to Date Financial Results

Revenue for the six months ended June 30, 2010 increased 30% to $496.7 million compared to $381.3 million for the same period last year. Total segment gross margin was $108.0 million for the first six months of 2010 compared to $104.0 million for the same period in 2009.

Adjusted EBITDA for the six months ended June 30, 2010 decreased 5% to $75.3 million compared to $79.5 million for the same period last year. Non-cash amortization expense relating to the option component of Copano’s risk management portfolio, which is not added back in determining adjusted EBITDA, totaled $16.0 million and $18.5 million, respectively, for the six months ended June 30, 2010 and 2009.

Total distributable cash flow for the first six months of 2010 decreased to $64.3 million from $68.0 million for the same period in 2009, primarily because 2009 results included a $3.9 million gain on the retirement of debt in 2009.

Net loss for the six months ended June 30, 2010 totaled $22.4 million, or $0.36 per unit on a diluted basis, and includes a non-cash impairment charge of $25.0 million related to Copano’s investment in Bighorn. Net income was $11.9 million, or $0.21 per unit on a diluted basis, for the six months ended June 30, 2009. Drivers of the $34.3 million decrease primarily included:

·	a $25.4 million decrease in equity in earnings of unconsolidated affiliates as a result of the non-cash impairment charge mentioned above;

·	a $3.9 million decrease in earnings related to the gain on the retirement of debt in 2009;

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·	$4.3 million of additional depreciation and amortization expenses primarily related to expanded operations in Texas;

·	a $2.0 million increase in general and administrative expenses and property and other taxes;

·	a $0.8 million decrease in discontinued operations and taxes;

a $1.8 million increase in interest and other financing costs primarily related to (i) an unrealized gain on interest rate swaps for 2010 of $0.8 million compared to a $2.2 million gain in 2009 and (ii) a decrease of capitalized interest of $1.0 million, offset in part by a decrease in interest expense ($0.2 million) and amortization of debt issuance costs ($0.4 million) related to Copano’s senior unsecured notes;

offset by:

a $3.9 million increase in total segment gross margin consisting of a $30.1 million increase in combined operating segment gross margins primarily reflecting average NGL price increases of 62% on the Conway index and 61% on the Mt. Belvieu index, offset in part by lower overall service throughput volumes and a decrease of $26.2 million from Copano’s commodity risk management activities.

Weighted average diluted units outstanding totaled 61.9 million for the six months ended June 30, 2010 as compared to 57.9 million for the same period in 2009.

Cash Distributions

On July 14, 2010, Copano announced its second quarter 2010 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 2010 and will be paid on August 12, 2010 to common unitholders of record at the close of business on August 2, 2010.

Conference Call Information

Copano will hold a conference call to discuss its second quarter 2010 financial results and recent developments on August 6, 2010 at 10:00 a.m. Eastern Time (9:00 a.m. Central Time). To participate in the call, dial (480) 629-9821 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.

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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 13, 2010 by calling (303) 590-3030 and using the pass code 4334792#.

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 (loss), operating income (loss), income (loss) 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, liquidity position 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 core profitability, liquidity position or financial performance.

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 6,400 miles of active natural gas gathering and transmission pipelines, 250 miles of NGL pipelines and eight natural gas processing plants, with more than one billion cubic feet per day of combined processing capacity and 22,000 barrels per day of fractionation capacity. For more information, please visit www.copanoenergy.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 the 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 and producers’ ability to drill and successfully complete and attach new natural gas supplies and the availability of downstream transportation systems and other facilities for natural gas and NGLs; 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 filings with the Securities and Exchange Commission.

– financial statements to follow –

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended June 30,		Six Months Ended June 30,
	2010	2009	2010	2009
	(In thousands, except per unit information)
Revenue:
Natural gas sales	$ 84,819	$ 64,517	$205,035	$159,496
Natural gas liquids sales	114,802	91,463	234,120	172,294
Transportation, compression and processing fees	16,516	13,913	29,630	28,912
Condensate and other	13,914	10,290	27,932	20,559
Total revenue	230,051	180,183	496,717	381,261

Costs and expenses:
Cost of natural gas and natural gas liquids (1)	167,613	122,178	377,478	265,497
Transportation (1)	5,603	5,744	11,279	11,728
Operations and maintenance	13,230	12,890	25,333	25,562
Depreciation and amortization	15,583	13,389	30,784	26,494
General and administrative	10,900	9,321	21,442	20,046
Taxes other than income	1,181	727	2,343	1,513
Equity in loss (earnings) from unconsolidated affiliates	23,632	(2,099)	21,837	(3,583))
Total costs and expenses	237,742	162,150	490,496	347,257

Operating (loss) income	(7,691))	18,033	6,221	34,004

Other income (expense):
Interest and other income	37	7	44	53
Gain on retirement of unsecured debt	—	—	—	3,939
Interest and other financing costs	(13,351))	(12,001))	(28,296))	(26,449))
(Loss) income before income taxes and discontinued operations	(21,005))	6,039	(22,031))	11,547
Provision for income taxes	(106))	(571))	(340))	(735))
(Loss) income from continuing operations	(21,111))	5,468	(22,371))	10,812
Discontinued operations, net of tax	—	570	—	1,131

Net (loss) income	$ (21,111))	$ 6,038	$ (22,371))	$ 11,943

Basic net (loss) income per common unit:
(Loss) income per common unit from continuing operations	$ (0.32))	$ 0.10	$ (0.36))	$ 0.20
Income per common unit from discontinued operations	—	0.01	—	0.02
Net (loss) income per common unit	$ (0.32))	$ 0.11	$ (0.36))	$ 0.22
Weighted average number of common units	65,516	54,356	61,941	54,185

Diluted net (loss) income per common unit:
(Loss) income per common unit from continuing operations	$ (0.32))	$ 0.09	$ (0.36))	$ 0.19
Income per common unit from discontinued operations	—	0.01	—	0.02
Net (loss) income per common unit	$ (0.32))	$ 0.10	$ (0.36))	$ 0.21
Weighted average number of common units	65,516	57,946	61,941	57,933

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

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2010	2009
	(In thousands)
Cash Flows From Operating Activities:
Net (loss) income	$ (22,371))	$ 11,943
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization	30,784	27,000
Amortization of debt issue costs	1,790	2,165
Equity in loss (earnings) from unconsolidated affiliates	21,837	(3,583))
Distributions from unconsolidated affiliates	10,993	11,439
Gain on retirement of unsecured debt	—	(3,939))
Non-cash gain on risk management activities, net	(1,049))	(1,636))
Equity-based compensation	4,688	4,317
Deferred tax provision	(98)	373
Other non-cash items	(369)	296
Changes in assets and liabilities:
Accounts receivable	12,231	24,805
Prepayments and other current assets	2,605	2,080
Risk management activities	6,002	18,479
Accounts payable	(3,151))	(12,338))
Other current liabilities	1,522	(1,773))
Net cash provided by operating activities	65,414	79,628

Cash Flows From Investing Activities:
Additions to property, plant and equipment	(59,438))	(37,380))
Additions to intangible assets	(930))	(698))
Acquisitions	—	(2,840))
Investment in unconsolidated affiliates	(1,538))	(2,774))
Distributions from unconsolidated affiliates	1,997	2,788
Proceeds from the sale of assets	266	—
Other	523	(995))
Net cash used in investing activities	(59,120))	(41,899))

Cash Flows From Financing Activities:
Proceeds from long-term debt	80,000	50,000
Repayment of long-term debt	(170,000))	—
Retirement of unsecured debt	—	(14,286))
Distributions to unitholders	(69,430))	(62,505))
Proceeds from public offering of common units, net of underwriting discounts and commissions of $7,223	164,786	—
Equity offering costs	(531))	—
Proceeds from option exercises	991	61
Net cash provided by (used in) financing activities	5,816	(26,730))

Net increase in cash and cash equivalents	12,110	10,999
Cash and cash equivalents, beginning of year	44,692	63,684
Cash and cash equivalents, end of period	$ 56,802	$ 74,683

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

	As of
	June 30, 2010	December 31, 2009
	(In thousands, except unit information)
ASSETS
Current assets:
Cash and cash equivalents	$ 56,802		$ 44,692
Accounts receivable, net	79,267		91,156
Risk management assets	34,506		36,615
Prepayments and other current assets	2,332		4,937
Total current assets	172,907		177,400

Property, plant and equipment, net	890,533		841,323
Intangible assets, net	185,357		190,376
Investment in unconsolidated affiliates	584,870		618,503
Escrow cash	1,859		1,858
Risk management assets	25,097		15,381
Other assets, net	20,523		22,571
Total assets	$1,881,146		$1,867,412

LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable	$ 116,894		$ 111,021
Accrued interest	10,645		11,921
Accrued tax liability	456		672
Risk management liabilities	5,169		9,671
Other current liabilities	18,695		9,358
Total current liabilities	151,859		142,643

Long-term debt (includes $588 and $628 bond premium as of June 30, 2010 and December 31, 2009, respectively)	762,778		852,818
Deferred tax provision	1,763		1,862
Risk management and other noncurrent liabilities	6,019		10,063

Members’ capital:
Common units, no par value, 65,563,244 and 54,670,029 units issued and outstanding as of June 30, 2010 and December 31, 2009, respectively	1,157,201		879,504
Class D units, no par value, 0 and 3,245,817 units issued and outstanding as of June 30, 2010 and December 31, 2009, respectively	—		112,454
Paid-in capital	47,379		42,518
Accumulated deficit	(250,675))		(158,267))
Accumulated other comprehensive income (loss)	4,822		(16,183))
	958,727		860,026
Total liabilities and members’ capital	$1,881,146		$1,867,412

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

OPERATING STATISTICS

(Unaudited)

	Three Months Ended June 30,		Six Months Ended June 30,
	2010	2009	2010	2009
	($ in thousands)

Total segment gross margin(1) (2)	$ 56,835	$52,261	$107,960	$104,036
Operations and maintenance expenses(2)	13,230	12,890	25,333	25,562
Depreciation and amortization(2)	15,583	13,389	30,784	26,494
General and administrative expenses	10,900	9,321	21,442	20,046
Taxes other than income	1,181	727	2,343	1,513
Equity in loss (earnings) from unconsolidated affiliates(3) (4) (5) (6)	23,632	(2,099))	21,837	(3,583))
Operating (loss) income(2) (3)	(7,691))	18,033	6,221	34,004
Gain on retirement of unsecured debt	—	—	—	3,939
Interest and other financing costs, net	(13,314))	(11,994))	(28,252))	(26,396))
Provision for income taxes	(106))	(571))	(340))	(735))
Discontinued operations, net of tax	—	570	—	1,131
Net (loss) income	$(21,111))	$ 6,038	$(22,371))	$ 11,943
Total segment gross margin:
Oklahoma(2)	$ 21,821	$17,473	$ 46,096	$ 31,773
Texas	31,751	23,320	58,916	43,900
Rocky Mountains(7)	1,148	711	2,251	1,510
Segment gross margin(2)	54,720	41,504	107,263	77,183
Corporate and other(8)	2,115	10,757	697	26,853
Total segment gross margin(1) (2)	$ 56,835	$52,261	$107,960	$104,036
Segment gross margin per unit:
Oklahoma:
Service throughput ($/MMBtu) (2)	$ 0.92	$ 0.72	$ 1.00	$ 0.65
Texas:
Service throughput ($/MMBtu)	$ 0.62	$ 0.41	$ 0.57	$ 0.38

Volumes:
Oklahoma: (9)
Service throughput (MMBtu/d) (10)	259,972	267,576	254,386	269,389
Plant inlet volumes (MMBtu/d)	156,204	166,846	154,208	163,532
NGLs produced (Bbls/d)	16,653	15,981	15,994	15,647
Texas: (11)
Service throughput (MMBtu/d) (10)	559,876	630,674	571,358	637,565
Pipeline throughput (MMBtu/d)	327,839	290,005	322,423	296,932
Plant inlet volumes (MMBtu/d)	469,019	559,597	463,158	558,900
NGLs produced (Bbls/d)	18,382	18,425	16,869	17,667

Capital expenditures:
Maintenance capital expenditures	$ 1,649	$ 3,895	$ 3,080	$ 6,046
Expansion capital expenditures	51,536	14,301	71,942	24,836
Total capital expenditures	$ 53,185	$18,196	$ 75,022	$ 30,882
Operations and maintenance expenses:
Oklahoma(2)	$ 5,670	$ 5,608	$ 11,103	$ 11,224
Texas	7,497	7,280	14,066	14,334
Rocky Mountains	63	2	164	4
Total operations and maintenance expenses(2)	$ 13,230	$12,890	$ 25,333	$ 25,562

[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 (loss), please read “Non-GAAP Financial Measures.”

(2)

Excludes results attributable to Copano’s crude oil pipeline and related assets for the three and six months ended June 30, 2009 as these amounts are shown under the caption “Discontinued operations.”

(3)During the three months ended June 30, 2010, Copano recorded a $25 million non-cash impairment charge relating to our investment in Bighorn primarily as a result of a continued weak Rocky Mountains pricing environment for natural gas, lack of drilling activity in the Wyoming’s Powder River Basin and a downward shift in the Colorado Interstate Gas forward price curve.

(4)

Includes results and volumes associated with Copano’s interests in Bighorn and Fort Union. Combined volumes gathered by Bighorn and Fort Union were 900,047 MMBtu/d and 980,694 MMBtu/d for the three months ended June 30, 2010 and 2009, respectively. Combined volumes gathered by Bighorn and Fort Union were 915,596 MMBtu/d and 993,275 MMBtu/d for the six months ended June 30, 2010 and 2009, respectively.

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(5)

Includes results and volumes associated with Copano’s interest in Southern Dome. For the three months ended June 30, 2010, plant inlet volumes for Southern Dome averaged 12,689 MMBtu/d and NGLs produced averaged 456 Bbls/d. For the three months ended June 30, 2009, plant inlet volumes for Southern Dome averaged 15,412 MMBtu/d and NGLs produced averaged 578 Bbls/d. For the six months ended June 30, 2010, plant inlet volumes for Southern Dome averaged 13,406 MMBtu/d and NGLs produced averaged 477 Bbls/d. For the six months ended June 30, 2009, plant inlet volumes for Southern Dome averaged 13,023 MMBtu/d and NGLs produced averaged 473 Bbls/d.

(6)

Includes results and volumes associated with Copano’s interest in Webb Duval. Gross volumes transported by Webb Duval, net of intercompany volumes, were 54,747 MMBtu/d and 84,452 MMBtu/d for the three months ended June 30, 2010 and 2009, respectively. Gross volumes transported by Webb Duval, net of intercompany volumes, were 57,405 MMBtu/d and 86,584 MMBtu/d for the six months ended June 30, 2010 and 2009, respectively.

(7)

Rocky Mountains segment gross margin includes results from producer services, including volumes purchased for resale, volumes gathered under firm capacity gathering agreements with Fort Union and volumes transported using Copano’s firm capacity agreements with WIC and compressor rental services provided to Bighorn. Excludes results and volumes associated with Copano’s interests in Bighorn and Fort Union.

(8)

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

(9)

Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Oklahoma segment at all plants, including plants owned by the Oklahoma segment and plants owned by third parties. For the three months ended June 30, 2010, plant inlet volumes averaged 119,030 MMBtu/d and NGLs produced averaged 13,289 Bbls/d for plants owned by the Oklahoma segment. For the three months ended June 30, 2009, plant inlet volumes averaged 128,390 MMBtu/d and NGLs produced averaged 12,956 Bbls/d for plants owned by the Oklahoma segment. For the six months ended June 30, 2010, plant inlet volumes averaged 118,320 MMBtu/d and NGLs produced averaged 12,881 Bbls/d for plants owned by the Oklahoma segment. For the six months ended June 30, 2009, plant inlet volumes averaged 125,661 MMBtu/d and NGLs produced averaged 12,747 Bbls/d for plants owned by the Oklahoma segment. Excludes volumes associated with Copano’s interest in Southern Dome.

(10)

“Service throughput” means the volume of natural gas delivered to Copano’s wholly owned processing plants by third-party pipelines plus Copano’s “pipeline throughput,” which is the volume of natural gas transported or gathered through Copano’s pipelines.

(11)

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 461,880 MMBtu/d and NGLs produced averaged 17,864 Bbls/d for the three months ended June 30, 2010 for plants owned by the Texas segment. Plant inlet volumes averaged 539,946 MMBtu/d and NGLs produced averaged 16,759 Bbls/d for the three months ended June 30, 2009 for plants owned by the Texas segment. Plant inlet volumes averaged 456,180 MMBtu/d and NGLs produced averaged 16,366 Bbls/d for the six months ended June 30, 2010 for plants owned by the Texas segment. Plant inlet volumes averaged 537,528 MMBtu/d and NGLs produced averaged 15,920 Bbls/d for the six months ended June 30, 2009 for plants owned by the Texas segment. Excludes volumes associated with Copano’s interest in Webb Duval.

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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 (loss), (ii) EBITDA and adjusted EBITDA to the GAAP financial measures of net income (loss) and cash flows from operating activities and (iii) total distributable cash flow to the GAAP financial measure of net income (loss), for each of the periods indicated (in thousands).

		Three Months Ended June 30,		Six Months Ended June 30,
		2010	2009	2010	2009
		($ in thousands)
Reconciliation of total segment gross margin to operating (loss) income:
Operating (loss) income		$ (7,691)	$18,033	$ 6,221	$ 34,004
Add: Operations and maintenance expenses		13,230	12,890	25,333	25,562
Depreciation and amortization		15,583	13,389	30,784	26,494
General and administrative expenses		10,900	9,321	21,442	20,046
Taxes other than income		1,181	727	2,343	1,513
Equity in loss (earnings) from unconsolidated affiliates		23,632	(2,099)	21,837	(3,583)
Total segment gross margin		$ 56,835	$52,261	$107,960	$104,036

Reconciliation of EBITDA and adjusted EBITDA to net (loss) income:
Net (loss) income		$(21,111)	$ 6,038	$ (22,371)	$ 11,943
Add: Depreciation and amortization(1)		15,583	13,835	30,784	27,000
Interest and other financing costs		13,351	12,001	28,296	26,449
Provision for income taxes		106	571	340	735
EBITDA		7,929	32,445	37,049	66,127
Add: Amortization of difference between the carried investment and the underlying equity in net assets of equity investments and impairment		29,645	4,785	34,290	9,603
Copano’s share of depreciation and amortization included in equity in earnings from unconsolidated affiliates		1,603	1,776	3,140	3,333
Copano’s share of interest and other financing costs incurred by equity method investments		494	(30)	865	478
Adjusted EBITDA		$ 39,671	$38,976	$ 75,344	$ 79,541

Reconciliation of EBITDA and adjusted EBITDA to cash flows from operating activities:
Cash flow provided by operating activities		$ 36,250	$44,230	$ 65,414	$ 79,628
Add: Cash paid for interest and other financing costs		12,455	11,106	26,505	24,284
Equity in (loss) earnings from unconsolidated affiliates		(23,632)	2,099	(21,837)	3,583
Distributions from unconsolidated affiliates		(5,228)	(6,068)	(10,993)	(11,439)
Risk management activities		(5,405)	(9,291)	(6,002)	(18,479)
Changes in working capital and other		(6,511)	(9,631)	(16,038)	(11,450)
EBITDA		7,929	32,445	37,049	66,127
Add: Amortization of difference between the carried investment and the underlying equity in net assets of equity investments and impairment		29,645	4,785	34,290	9,603
Copano’s share of depreciation and amortization included in equity in earnings from unconsolidated affiliates		1,603	1,776	3,140	3,333
Copano’s share of interest and other financing costs incurred by equity method investments		494	(30)	865	478
Adjusted EBITDA		$ 39,671	$38,976	$ 75,344	$ 79,541

Reconciliation of net (loss) income to total distributable cash flow:
Net (loss) income		$(21,111)	$ 6,038	$(22,371)	$ 11,943
Add: Depreciation and amortization(1)		15,583	13,835	30,784	27,000
Amortization of commodity derivative options		8,070	9,291	16,048	18,479
Amortization of debt issue costs		895	895	1,790	2,165
Equity-based compensation		2,686	2,296	5,401	4,255
Distributions from unconsolidated affiliates		6,254	7,296	12,991	14,227
Unrealized loss associated with line fill contributions and gas imbalances		756	361	2,338	527
Unrealized gain on derivatives		(1,582)	(1,396)	(1,049)	(1,636)
Deferred taxes and other		(68)	325	(369)	672
Less: Equity in loss (earnings) from unconsolidated affiliates		23,632	(2,099)	21,837	(3,583)
Maintenance capital expenditures		(1,649)	(3,895)	(3,080)	(6,046)
Total distributable cash flow(2)		$ 33,466	$32,947	$ 64,320	$ 68,003

Actual quarterly distribution (“AQD”)		$ 38,295	$31,869
Total distributable cash flow coverage of AQD		87%	103%
________________________
(1)	Includes depreciation and amortization related to the discontinued operations.
(2)	Prior to any retained cash reserves established by Copano’s Board of Directors.

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