Edgar Filing: Copano Energy, L.L.C.

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended June 30, 2009
OR
o		TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-32329

Copano Energy, L.L.C.

(Exact Name of Registrant as Specified in Its Charter)


Delaware		51-0411678
(State or Other Jurisdiction of Incorporation or Organization)		(I.R.S. Employer Identification No.)

2727 Allen Parkway, Suite 1200

Houston, Texas 77019

(Address of Principal Executive Offices)

(713) 621-9547

(Registrant’s Telephone Number, Including Area Code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes þ No o

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes o No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See the definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):


Large accelerated filer þ	Accelerated filer o	Non-accelerated filer o	Smaller reporting company o

(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes o No þ

There were 54,556,675 common units of Copano Energy, L.L.C. outstanding at August 3, 2009. Copano Energy, L.L.C.’s common units trade on The NASDAQ Stock Market LLC under the symbol “CPNO.”

TABLE OF CONTENTS


			Page

PART I — FINANCIAL INFORMATION
	Item 1.	Financial Statements		3
		Unaudited Consolidated Balance Sheets as of June 30, 2009 and December 31, 2008		3
		Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2009 and 2008		4
		Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2009 and 2008		5
		Unaudited Consolidated Statement of Members’ Capital and Comprehensive Income (Loss) for the Six Months Ended June 30, 2009 and 2008		6
		Notes to Unaudited Consolidated Financial Statements		7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		38
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		58
	Item 4.	Controls and Procedures		62

PART II — OTHER INFORMATION
	Item 1.	Legal Proceedings		63
	Item 1A.	Risk Factors		63
	Item 4.	Submission of Matters to a Vote of Security Holders		65
	Item 6.	Exhibits		66
EX-31.1
EX-31.2
EX-32.1
EX-32.2


Item 1.	*Financial Statements.*

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS


	June 30,			December 31,
	2009			2008
	(In thousands, except unit information)

ASSETS
Current assets:
Cash and cash equivalents	$	74,683		$	63,684
Accounts receivable, net		71,644			96,028
Risk management assets		44,270			76,440
Prepayments and other current assets		2,924			5,004

Total current assets		193,521			241,156

Property, plant and equipment, net		833,198			823,574
Intangible assets, net		193,779			198,974
Investment in unconsolidated affiliates		631,741			640,598
Escrow cash		1,858			1,858
Risk management assets		37,138			82,892
Other assets, net		23,004			24,613

Total assets	$	1,914,239		$	2,013,665


LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable	$	88,092		$	103,849
Accrued interest		11,380			11,904
Accrued tax liability		356			784
Risk management liabilities		7,774			6,272
Other current liabilities		8,479			16,787

Total current liabilities		116,081			139,596

Long-term debt (includes $666 and $704 bond premium as of June 30, 2009 and December 31, 2008, respectively)		852,856			821,119
Deferred tax provision		2,091			1,718
Risk management and other noncurrent liabilities		12,882			13,274
Commitments and contingencies (Note 9)
Members’ capital:
Common units, no par value, 54,520,170 units and 53,965,288 units issued and outstanding as of June 30, 2009 and December 31, 2008, respectively		878,901			865,343
Class C units, no par value, 0 units and 394,853 units issued and outstanding as of June 30, 2009 and December 31, 2008		—			13,497
Class D units, no par value, 3,245,817 units issued and outstanding as of June 30, 2009 and December 31, 2008		112,454			112,454
Paid-in capital		38,907			33,734
Accumulated deficit		(105,900	)		(54,696	)
Accumulated other comprehensive income		5,967			67,626

		930,329			1,037,958

Total liabilities and members’ capital	$	1,914,239		$	2,013,665

The accompanying notes are an integral part of these unaudited consolidated financial statements.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2009			2008			2009			2008
	(In thousands, except per unit information)

Revenue:
Natural gas sales	$	64,517		$	235,000		$	159,496		$	415,887
Natural gas liquids sales		91,463			179,031			172,294			333,112
Crude oil sales		22,730			57,183			38,068			98,365
Transportation, compression and processing fees		13,913			16,442			28,912			29,124
Condensate and other		10,290			13,622			20,559			26,538

Total revenue		202,913			501,278			419,329			903,026

Costs and expenses:
Cost of natural gas and natural gas liquids⁽¹⁾		122,415			369,766			265,873			667,234
Cost of crude oil purchases⁽¹⁾		21,340			56,021			35,768			95,863
Transportation⁽¹⁾		5,744			3,416			11,728			6,537
Operations and maintenance		13,028			13,065			25,850			24,895
Depreciation and amortization		13,835			12,767			27,000			24,337
General and administrative		9,321			10,936			20,046			22,786
Taxes other than income		727			729			1,513			1,470
Equity in earnings from unconsolidated affiliates		(2,099	)		(4,788	)		(3,583	)		(5,184	)

Total costs and expenses		184,311			461,912			384,195			837,938

Operating income		18,602			39,366			35,134			65,088
Other income (expense):
Interest and other income		8			278			54			734
Gain on retirement of unsecured debt		—			—			3,939			—
Interest and other financing costs		(12,001	)		(16,077	)		(26,449	)		(27,469	)

Income before income taxes		6,609			23,567			12,678			38,353
Provision for income taxes		(571	)		(365	)		(735	)		(649	)

Net income	$	6,038		$	23,202		$	11,943		$	37,704

Basic net income per common unit:
Net income per common unit	$	0.11		$	0.49		$	0.22		$	0.79
Weighted average number of common units		54,356			47,672			54,185			47,524
Diluted net income per common unit:
Net income per common unit	$	0.10		$	0.40		$	0.21		$	0.65
Weighted average number of common units		57,946			58,010			57,933			57,967


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

The accompanying notes are an integral part of these unaudited consolidated financial statements.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS


	Six Months Ended
	June 30,
	2009			2008
	(In thousands)

Cash Flows From Operating Activities:
Net income	$	11,943		$	37,704
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		27,000			24,337
Amortization of debt issue costs		2,165			1,619
Equity in earnings from unconsolidated affiliates		(3,583	)		(5,184	)
Distributions from unconsolidated affiliates		11,439			11,718
Gain on retirement of unsecured debt (Note 5)		(3,939	)		—
Non-cash (gain) loss on risk management activities, net		(1,636	)		10,000
Equity-based compensation		4,317			1,808
Deferred tax provision		373			253
Other non-cash items		296			(85	)
Changes in assets and liabilities:
Accounts receivable		24,805			(44,258	)
Prepayments and other current assets		2,080			753
Risk management activities		18,479			(26,320	)
Accounts payable		(12,338	)		62,605
Other current liabilities		(1,773	)		3,035

Net cash provided by operating activities		79,628			77,985

Cash Flows From Investing Activities:
Additions to property, plant and equipment		(37,380	)		(76,995	)
Additions to intangible assets		(698	)		(3,849	)
Acquisitions		(2,840	)		(77	)
Investment in unconsolidated affiliates		(2,774	)		(18,809	)
Distributions from unconsolidated affiliates		2,788			877
Other		(995	)		(2,701	)

Net cash used in investing activities		(41,899	)		(101,554	)

Cash Flows From Financing Activities:
Proceeds from long-term debt		50,000			364,000
Repayment of long-term debt		—			(314,000	)
Retirement of unsecured debt		(14,286	)		—
Deferred financing costs		—			(6,350	)
Distributions to unitholders		(62,505	)		(49,585	)
Capital contributions from pre-IPO investors		—			4,103
Equity offering costs		—			(47	)
Proceeds from option exercises		61			524

Net cash used in financing activities		(26,730	)		(1,355	)

Net increase (decrease) in cash and cash equivalents		10,999			(24,924	)
Cash and cash equivalents, beginning of year		63,684			72,665

Cash and cash equivalents, end of period	$	74,683		$	47,741

The accompanying notes are an integral part of these unaudited consolidated financial statements.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENT OF MEMBERS’ CAPITAL AND COMPREHENSIVE INCOME (LOSS)


																								Accumulated
	Common				Class C						Class D				Class E						Accumulated			Other						Total
	Number		Common		Number			Class C			Number		Class D		Number		Class E		Paid-in		Earnings			Comprehensive						Comprehensive
	of Units		Units		of Units			Units			of Units		Units		of Units		Units		Capital		(Deficit)			Income (Loss)			Total			Income (Loss)
													(In thousands)

Balance, December 31, 2008		53,965	$	865,343		395		$	13,497			3,246	$	112,454		—	$	—	$	33,734	$	(54,696	)	$	67,626		$	1,037,958
Conversion of Class C Units into common unitss		395		13,497		(395	)		(13,497	)		—		—		—		—		—		—			—			—		$	—
Distributions to unitholders		—		—		—			—			—		—		—		—		—		(63,147	)		—			(63,147	)		—
Option exercises		6		61		—			—			—		—		—		—		—		—			—			61
Equity-based compensation		—		—		—			—			—		—		—		—		3,722		—			—			3,722			—
Vested restricted units		6		—		—			—			—		—		—		—				—			—			—			—
Vested phantom units		26		—		—			—			—		—		—		—		—		—			—			—			—
Vested unit awards		122		—		—			—			—		—		—		—		1,451		—			—			1,451			—
Net income				—		—			—			—		—		—		—		—		11,943			—			11,943			11,943
Derivative settlements reclassified to income		—		—		—			—			—		—		—		—		—		—			(25,507	)		(25,507	)		(25,507	)
Unrealized loss-change in fair value of derivatives		—		—		—			—			—		—		—		—		—		—			(36,152	)		(36,152	)		(36,152	)

Comprehensive loss																														$	(49,716	)

Balance, June 30, 2009		54,520	$	878,901		—		$	—			3,246	$	112,454		—	$	—	$	38,907	$	(105,900	)	$	5,967		$	930,329


Balance, December 31, 2007		47,366	$	661,585		1,184		$	40,492			3,246	$	112,454		5,599	$	175,634	$	23,773	$	(7,867	)	$	(111,935	)	$	894,136
Capital contributions from Pre-IPO Investors		—		—		—			—			—		—		—		—		4,103		—			—			4,103		$	—
Conversion of Class C units into common units		394		13,497		(394	)		(13,497	)		—		—		—		—		—		—			—			—			—
Distributions to unitholders		—		—		—			—			—		—		—		—		—		(49,840	)		—			(49,840	)		—
Option exercises		32		524		—			—			—		—		—		—		—		—			—			524			—
Equity-based compensation		—		—		—			—			—		—		—		—		1,808		—			—			1,808			—
Vested restricted units		16		—		—			—			—		—		—		—		—		—			—			—			—
Vested phantom units		12		—		—			—			—		—		—		—		—		—			—			—			—
Net income		—		—		—			—			—		—		—		—		—		37,704			—			37,704			37,704
Derivative settlements reclassified to income		—		—		—			—			—		—		—		—		—		—			23,915			23,915			23,915
Unrealized loss-change in fair value of derivatives		—		—		—			—			—		—		—		—		—		—			(44,314	)		(44,314	)		(44,314	)

Comprehensive income																														$	17,305

Balance, June 30, 2008		47,820	$	675,606		790		$	26,995			3,246	$	112,454		5,599	$	175,634	$	29,684	$	(20,003	)	$	(132,334	)	$	868,036

The accompanying notes are an integral part of these unaudited consolidated financial statements.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


Note 1 —	Organization and Basis of Presentation

Organization

Copano Energy, L.L.C., a Delaware limited liability company, was formed in August 2001 to acquire entities owning businesses operating under the Copano name since 1992. We, through our subsidiaries, provide midstream services to natural gas producers, including natural gas gathering, compression, dehydration, treating, marketing, transportation, processing, conditioning and fractionation services. Our assets are located in Oklahoma, Texas, Wyoming and Louisiana. Unless the context requires otherwise, references to “Copano,” “we,” “our,” “us” or like terms refer to Copano Energy, L.L.C., its subsidiaries and entities it manages or operates.

Our natural gas pipelines collect natural gas from designated points near producing wells and transport these volumes to third-party pipelines, our gas processing plants, third-party processing plants, local distribution companies and power generation facilities. Natural gas delivered to our gas processing plants, either on our pipelines or third-party pipelines, is treated to remove contaminants, conditioned or processed to extract mixed natural gas liquids (“NGLs”), and the NGLs are fractionated or separated, to the extent commercially desirable, into select component NGL products, including ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate. In addition to our natural gas pipelines, we operate three NGL pipelines and a crude oil pipeline. We refer to our operations (i) conducted through our subsidiaries operating in Oklahoma, including our crude oil pipeline, collectively as our “Oklahoma” segment, (ii) conducted through our subsidiaries operating in Texas and Louisiana collectively as our “Texas” segment and (iii) conducted through our subsidiaries operating in Wyoming collectively as our “Rocky Mountains” segment.

Basis of Presentation and Principles of Consolidation

The accompanying unaudited consolidated financial statements and related notes include our assets, liabilities and results of operations for each of the periods presented. All intercompany accounts and transactions are eliminated in our consolidated financial statements. Certain prior period information has been reclassified to conform to the current period’s presentation. As of the year ended December 31, 2008, we changed our presentation for our derivative activities on our statement of cash flows to present separately (i) the non-cash loss attributable to our risk management activities that did not qualify for hedge accounting and (ii) under the caption “Risk management activities,” the net changes in our current and long-term risk management assets and liabilities. As of June 30, 2009, we added additional information to our presentation in Note 11 of the reconciliation of changes in fair value of derivatives classified as Level 3 to separately present the effects of the non-cash amortization of option premiums and cash settlements of expired derivatives positions. As such, the three and six months ended June 30, 2008 has been reclassified to conform to the current periods’ presentation.

We own a 62.5% equity investment in Webb/Duval Gatherers (“Webb Duval”), a Texas general partnership, a majority interest in Southern Dome, LLC (“Southern Dome”), a Delaware limited liability company, a 51% interest in Bighorn Gas Gathering, L.L.C. (“Bighorn”), a Delaware limited liability company, and a 37.04% interest in Fort Union Gas Gathering, L.L.C. (“Fort Union”), a Delaware limited liability company. Although we are the managing partner or member in each of these equity investments and own a majority interest in some of these equity investments, we account for these investments using the equity method of accounting because the remaining general partners or members have substantive participating rights with respect to the management of each of these equity investments. Equity in earnings from our unconsolidated affiliates is included in income from operations as the operations of each of our unconsolidated affiliates are integral to our operations. See Note 4.

The accompanying unaudited consolidated financial statements have been prepared without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, our financial statements reflect all normal and recurring adjustments that are, in the opinion of our management, necessary for a fair presentation of our results of operations for the interim periods. Certain information and notes normally included in financial statements prepared in accordance with generally accepted accounting principles have been condensed or omitted pursuant to such rules and regulations.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 1 —	Organization and Basis of Presentation — (Continued)

However, our management believes that the disclosures are adequate to make the information presented not misleading. In the preparation of these financial statements, we evaluated subsequent events through the issuance date of the financial statements, August 7, 2009. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2008.


Note 2 —	New Accounting Pronouncements

GAAP Codification

In June 2009, the Financial Accounting Standards Board (“FASB”) issued Statement of Financial Accounting Standards (“SFAS”) No. 168, “Accounting Standards Codification (“ASC”) and the Hierarchy of Generally Accepted Accounting Principles (“GAAP”),” which amends the hierarchy of U.S. GAAP to establish the ASC and SEC rules and interpretive releases as the source of authoritative GAAP recognized by the FASB for SEC registrants. The ASC does not change GAAP but rather combines various existing sources into a single authoritative source. SFAS No. 168 will be effective for financial statements issued for periods ending after September 15, 2009. On the effective date, all non-SEC (non-grandfathered) accounting and reporting standards will be superseded, and all non-SEC accounting literature not included in the ASC will be deemed non-authoritative. SFAS No. 168 is not expected to change our disclosures or underlying accounting upon adoption. Where we refer to existing GAAP standards in our financial statements, we have also included citations to the corresponding ASC standards using the reference “FASB ASC.”

Subsequent Events

On July 1, 2009, we adopted SFAS No. 165, “Subsequent Events” (FASB ASC 855), which clarifies FASB’s requirements for the recognition and disclosure of significant events occurring subsequent to the balance sheet date. The standard does not change our current recognition but does require that we disclose that our policy is to evaluate subsequent events through the date we issue our financial statements.

Interim Disclosures about Fair Value of Financial Instruments

In April 2009, the FASB issued FASB Staff Position (“FSP”) 107-1 and Accounting Principles Board Opinion 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FASB ASC 825) which requires us to provide additional fair value information for certain financial instruments in interim financial statements, similar to disclosure in our annual financial statements. The standard does not require disclosures for periods prior to initial adoption. We adopted this standard at June 30, 2009, and the adoption did not have a material impact on our financial condition or results of operations (see Note 12).

Business Combinations

On January 1, 2009, we adopted SFAS No. 141 (Revised), “Business Combinations” (FASB ASC 805), which revises how companies recognize and measure financial assets and liabilities acquired, goodwill acquired and the required disclosure subsequent to an acquisition. As a result of our adoption of this statement, we expensed $418,000 in January 2009 related to pending acquisition activities, which was included in other assets on our consolidated balance sheets as of December 31, 2008.

Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133

On January 1, 2009, we adopted SFAS No. 161, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (FASB ASC 815-10). SFAS No. 161 establishes the

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	New Accounting Pronouncements (Continued)

disclosure requirements for derivative instruments and hedging activities and amends and expands the disclosure requirements of SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended, (FASB ASC 815) with the intent to provide users of financial statements with an enhanced understanding of how and why an entity uses derivative instruments, how derivative instruments and related hedged items are accounted for under SFAS No. 133 and its related interpretations and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. SFAS No. 161 requires qualitative disclosures about objectives and strategies for using derivatives, quantitative disclosures about fair value amounts of gains and losses on derivative instruments and disclosures about credit-risk-related contingent features in derivative agreements. Upon adoption of this statement, we modified our disclosure of the derivative and hedging activities as presented in our consolidated financial statements issued subsequent to adoption. See Note 11 for additional information with respect to our adoption of SFAS No. 161.

Useful Life of Intangible Assets

On January 1, 2009, we adopted FSP No. 142-3, “Determination of the Useful Life of Intangible Assets” (FASB ASC 350-30), which amends the factors that should be considered in developing renewal or extension assumptions used to determine the useful life of recognized intangible assets under SFAS No. 142, “Goodwill and Other Intangible Assets,” (FASB ASC 350). This change is intended to improve consistency between the useful life of a recognized intangible asset under SFAS No. 142 and the period of expected cash flows used to measure the fair value of such assets under SFAS No. 142 and other accounting guidance. The requirement for determining useful lives must be applied prospectively to all intangible assets recognized as of, and subsequent to, January 1, 2009. Our adoption of the provisions of FSP No. 142-3 did not have a material impact on reported intangible assets or amortization expense.


Note 3 —	Intangible Assets

Our intangible assets consist of rights-of-way, easements, contracts and acquired customer relationships. We amortize existing intangible assets and any costs incurred to renew or extend the terms of existing intangible assets over the contract term or estimated useful life, as applicable, using the straight-line method. Upon adoption of FSP No. 142-3 (FASB ASC 350-30), initial costs of acquiring new intangible assets are amortized over the estimated useful life of the intangible asset and renewals or extension costs of intangible assets are expensed over the contract term using the straight-line method. Amortization expense was $2,756,000 and $2,659,000 for the three months ended June 30, 2009 and 2008, respectively. Amortization expense was $5,507,000 and $5,301,000 for the six months ended June 30, 2009 and 2008, respectively. Estimated aggregate amortization expense remaining for 2009 and each of the five succeeding fiscal years is approximately: 2009 — $5,465,000; 2010 — $10,905,000; 2011 — $10,889,000; 2012 — $10,825,000; 2013 — $10,705,000 and 2014 — $10,560,000.

Intangible assets consisted of the following (in thousands):


	June 30,			December 31,
	2009			2008

Rights-of-way and easements, at cost	$	114,007		$	113,309
Less accumulated amortization for rights-of-way and easements		(15,753	)		(11,926	)
Contracts		107,916			107,916
Less accumulated amortization for contracts		(16,410	)		(14,901	)
Customer relationships		4,864			5,318
Less accumulated amortization for customer relationships		(845	)		(742	)

Intangible assets, net	$	193,779		$	198,974

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 3 —	Intangible Assets — (Continued)

As of June 30, 2009, the weighted average amortization period for all of our intangible assets was 21 years. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 23 years, 19 years and 13 years, respectively, as of June 30, 2009. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 24 years, 20 years and 14 years, respectively, as of June 30, 2008.


Note 4 —	Investment in Unconsolidated Affiliates

No restrictions exist under Webb Duval’s, Southern Dome’s, Bighorn’s or Fort Union’s partnership or operating agreements that limit these entities’ ability to pay distributions to their respective partners or members after consideration of their respective debt covenants, if any, and current and anticipated cash needs, including debt service obligations. Our investments in unconsolidated affiliates totaled $631,741,000 as of June 30, 2009.

The summarized financial information for our equity investments as of and for the six months ended June 30, 2009 is as follows (in thousands):


	Bighorn			Fort Union			Southern Dome			Webb Duval

Operating revenue	$	17,287		$	30,501		$	8,237		$	1,025
Operating expenses		(6,863	)		(3,184	)		(6,853	)		(823	)
Depreciation and amortization		(2,640	)		(3,996	)		(374	)		(394	)
Interest income (expense) and other		3			(1,283	)		4			—

Net income (loss)		7,787			22,038			1,014			(192	)
Ownership %		51	%		37.04	%		69.5	%		62.5	%

		3,971			8,163			705			(120	)
Priority allocation of earnings and other		320			(286	)		—			—
Copano’s share of management fees charged		222			42			87			69
Amortization of difference between the carried investment and the underlying equity in net assets		(6,396	)		(3,212	)		(5	)		10

Equity in (loss) earnings from unconsolidated affiliates	$	(1,883	)	$	4,707		$	787		$	(41	)

Distributions	$	5,855		$	6,426		$	1,321		$	563

Current assets	$	7,952		$	13,727		$	3,452		$	586
Noncurrent assets		99,915			213,886			16,038			6,577
Current liabilities		(1,396	)		(18,219	)		(4,275	)		(797	)
Noncurrent liabilities		—			(96,986	)		—			(56	)

Net assets	$	106,471		$	112,408		$	15,215		$	6,310

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 4 —	Investment in Unconsolidated Affiliates (Continued)

The summarized financial information for our equity investments for the six months ended June 30, 2008 is as follows (in thousands):


	Bighorn			Fort Union			Southern Dome			Webb Duval

Operating revenue	$	17,303		$	24,023		$	17,959		$	1,759
Operating expenses		(6,544	)		(2,133	)		(14,475	)		(300	)
Depreciation and amortization		(2,056	)		(2,814	)		(367	)		(387	)
Interest income (expense) and other		63			(3,174	)		3			17

Net income		8,766			15,902			3,120			1,089
Ownership %		51	%		37.04	%		69.5	%		62.5	%

		4,471			5,890			2,168			681
Priority allocation of earnings and other		701			225			—			—
Copano’s share of management fees charged		117			18			88			67
Amortization of difference between the carried investment and the underlying equity in net assets		(5,995	)		(3,212	)		(5	)		10

Equity in (loss) earnings from unconsolidated affiliates	$	(706	)	$	2,921		$	2,251		$	758

Distributions	$	5,867		$	3,778		$	2,189		$	688


Note 5 —	Long-Term Debt

A summary of our debt follows (in thousands):


	June 30,		December 31,
	2009		2008

Long-term debt:
Credit Facility	$	270,000	$	220,000
Senior Notes:
8.125% senior notes due 2016		332,665		332,665
Unamortized bond premium-senior notes due 2016		666		704
7.75% senior notes due 2018		249,525		267,750

Total Senior Notes		582,856		601,119

Total	$	852,856	$	821,119

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt (Continued)

Senior Secured Revolving Credit Facility

As of June 30, 2009, we had $270 million of outstanding borrowings under our $550 million senior secured revolving credit facility (the “Credit Facility”) with Bank of America, N.A., as Administrative Agent. The Credit Facility matures on October 18, 2012. Future borrowings under the Credit Facility are available for acquisitions, capital expenditures, working capital and general corporate purposes, and the facility may be drawn on and repaid without restrictions so long as we are in compliance with its terms, including the financial covenants described below. The Credit Facility provides for up to $50 million in standby letters of credit. As of June 30, 2009 and 2008, we had no letters of credit outstanding.

The effective average interest rate on borrowings under the Credit Facility for the six months ended June 30, 2009 and 2008 was 4.7% and 6.2%, respectively, and the quarterly commitment fee on the unused portion of the Credit Facility for those periods was 0.25%. Interest and other financing costs related to the Credit Facility totaled $4,169,000 and $7,110,000 for the six months ended June 30, 2009 and 2008, respectively. Costs incurred in connection with the establishment of this credit facility are being amortized over the term of the Credit Facility, and as of June 30, 2009, the unamortized portion of debt issue costs totaled $7,090,000.

The Credit Facility contains covenants (including certain subjective representations and warranties), including financial covenants that require us and our subsidiary guarantors, on a consolidated basis, to maintain specified ratios as follows:


	•	a minimum EBITDA to interest expense ratio (using four quarters’ EBITDA as defined under the Credit Facility) of 2.5 to 1.0;

	•	a maximum total debt to EBITDA ratio of 5.0 to 1.0 (with no future reductions) with the option to increase the total debt to EBITDA ratio to not more than 5.5 to 1.0 for a period of up to nine months following an acquisition or a series of acquisitions totaling $50 million in a 12-month period (subject to an increased applicable interest rate margin and commitment fee rate).

At June 30, 2009, our ratio of EBITDA to interest expense was 3.5x, and our ratio of total debt to EBITDA was 3.9x. Based on our ratio of total debt to EBITDA, our remaining available borrowing capacity under the Credit Facility as of June 30, 2009 was approximately $280,000,000. If we failed to meet these ratios or experienced a material adverse effect on our operations, business, properties, liabilities or financial or other condition, we would be unable to borrow under our Credit Facility, and could be in default after specified notice and cure periods. If an event of default exists under the Credit Facility, our lenders could terminate their commitments to lend to us and accelerate the maturity of our outstanding obligations under the Credit Facility.

We are in compliance with the financial covenants under the Credit Facility as of June 30, 2009.

Senior Notes

8.125% Senior Notes Due 2016. At June 30, 2009, the aggregate principal amount of our 8.125% senior unsecured notes due 2016 (the “2016 Notes”) outstanding was $332,665,000.

Interest and other financing costs related to the 2016 Notes totaled $13,905,000 and $14,634,000 for the six months ended June 30, 2009 and 2008, respectively. Interest on the 2016 Notes is payable each March 1 and September 1. Costs of issuing the 2016 Notes are being amortized over the term of the 2016 Notes and, as of June 30, 2009, the unamortized portion of debt issue costs totaled $5,703,000.

7.75% Senior Notes Due 2018. At June 30, 2009, the aggregate principal amount of our 7.75% senior unsecured notes due 2018 (the “2018 Notes” and, together with the 2016 Notes, the “Senior Notes”) outstanding was $249,525,000.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt (Continued)

Interest and other financing costs relating to the 2018 Notes totaled $10,493,000 and $3,052,000 for the six months ended June 30, 2009 and 2008, respectively. Interest on the 2018 Notes is payable each June 1 and December 1. Costs of issuing the 2018 Notes are being amortized over the term of the 2018 Notes and, as of June 30, 2009, the unamortized portion totaled $4,852,000.

General. The indentures governing our Senior Notes restrict our ability to pay cash distributions. Before we can pay a distribution to our unitholders, we must demonstrate that our ratio of EBITDA to fixed charges (as defined in the Senior Notes indentures) is at least 1.75x. At June 30, 2009, our ratio of EBITDA to fixed charges was 3.4x.

We are in compliance with the financial covenants under the Senior Notes as of June 30, 2009.

Condensed consolidating financial information for Copano and its wholly owned subsidiaries is presented below. Separate financial statements of our guarantor subsidiaries are not provided because we do not believe that such information would be material to our investors or lenders.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (continued)

CONDENSED CONSOLIDATING BALANCE SHEETS


	June 30, 2009																	December 31, 2008
										Investment in																	Investment in
							Guarantor			Non-Guarantor														Guarantor			Non-Guarantor
	Parent			Co-Issuer			Subsidiaries			Subsidiaries		Eliminations			Total			Parent			Co-Issuer			Subsidiaries			Subsidiaries		Eliminations			Total
	(In thousands)

ASSETS
Current assets:
Cash and cash equivalents	$	29,235		$	—		$	45,448		$	—	$	—		$	74,683		$	20,417		$	—		$	43,267		$	—	$	—		$	63,684
Accounts receivable, net		1			—			71,643			—		—			71,644			1			—			96,027			—		—			96,028
Intercompany receivable		56,338			(1	)		(56,337	)		—		—			—			110,551			—			(110,551	)		—		—			—
Risk management assets		—			—			44,270			—		—			44,270			—			—			76,440			—		—			76,440
Prepayments and other current assets		428			—			2,496			—		—			2,924			911			—			4,093			—		—			5,004

Total current assets		86,002			(1	)		107,520			—		—			193,521			131,880			—			109,276			—		—			241,156

Property, plant and equipment, net		116			—			833,082			—		—			833,198			136			—			823,438			—		—			823,574
Intangible assets, net		—			—			193,779			—		—			193,779			—			—			198,974			—		—			198,974
Investment in unconsolidated affiliates		—			—			631,741			631,741		(631,741	)		631,741			—			—			640,598			640,598		(640,598	)		640,598
Investment in consolidated subsidiaries		1,695,289			—			—			—		(1,695,289	)		—			1,723,814			—			—			—		(1,723,814	)		—
Escrow cash		—			—			1,858			—		—			1,858			—			—			1,858			—		—			1,858
Risk management assets		—			—			37,138			—		—			37,138			—			—			82,892			—		—			82,892
Other assets, net		17,644			—			5,360			—		—			23,004			19,809			—			4,804			—		—			24,613

Total assets	$	1,799,051		$	(1	)	$	1,810,478		$	631,741	$	(2,327,030	)	$	1,914,239		$	1,875,639		$	—		$	1,861,840		$	640,598	$	(2,364,412	)	$	2,013,665


LIABILITIES AND MEMBERS’/PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	—		$	—		$	88,092		$	—	$	—		$	88,092		$	2		$	—		$	103,847		$	—	$	—		$	103,849
Accrued interest		10,781			—			599			—		—			11,380			11,878			—			26			—		—			11,904
Accrued tax liability		356			—			—			—		—			356			784			—			—			—		—			784
Risk management liabilities		—			—			7,774			—		—			7,774			—			—			6,272			—		—			6,272
Other current liabilities		2,255			—			6,224			—		—			8,479			1,731			—			15,056			—		—			16,787

Total current liabilities		13,392			—			102,689			—		—			116,081			14,395			—			125,201			—		—			139,596

Long-term debt		852,856			—			—			—		—			852,856			821,119			—			—			—		—			821,119
Deferred tax provision		2,091			—			—			—		—			2,091			1,718			—			—			—		—			1,718
Risk management and other noncurrent liabilities		383			—			12,499			—		—			12,882			449			—			12,825			—		—			13,274
Members’/Partners’ capital:
Common units		878,901			—			—			—		—			878,901			865,343			—			—			—		—			865,343
Class C units		—			—			—			—		—			—			13,497			—			—			—		—			13,497
Class D units		112,454			—			—			—		—			112,454			112,454			—			—			—		—			112,454
Paid-in capital		38,907			1			1,544,059			610,030		(2,154,090	)		38,907			33,734			1			1,544,237			629,359		(2,173,597	)		33,734
Accumulated (deficit) earnings		(105,900	)		(2	)		145,264			21,711		(166,973	)		(105,900	)		(54,696	)		(1	)		111,951			11,239		(123,189	)		(54,696	)
Accumulated other comprehensive income (loss)		5,967			—			5,967			—		(5,967	)		5,967			67,626			—			67,626			—		(67,626	)		67,626

		930,329			(1	)		1,695,290			631,741		(2,327,030	)		930,329			1,037,958			—			1,723,814			640,598		(2,364,412	)		1,037,958

Total liabilities and members’/partners’ capital	$	1,799,051		$	(1	)	$	1,810,478		$	631,741	$	(2,327,030	)	$	1,914,239		$	1,875,639		$	—		$	1,861,840		$	640,598	$	(2,364,412	)	$	2,013,665

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS


	Three Months Ended June 30,
	2009																	2008
									Investment in																	Investment in
						Guarantor			Non-Guarantor														Guarantor			Non-Guarantor
	Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total			Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total
															(In thousands)

Revenue:
Natural gas sales	$	—		$	—	$	64,517		$	—		$	—		$	64,517		$	—		$	—	$	235,000		$	—		$	—		$	235,000
Natural gas liquids sales		—			—		91,463			—			—			91,463			—			—		179,031			—			—			179,031
Crude oil sales		—			—		22,730			—			—			22,730			—			—		57,183			—			—			57,183
Transportation, compression and processing fees		—			—		13,913			—			—			13,913			—			—		16,442			—			—			16,442
Condensate and other		—			—		10,290			—			—			10,290			—			—		13,622			—			—			13,622

Total revenue		—			—		202,913			—			—			202,913			—			—		501,278			—			—			501,278

Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		122,415			—			—			122,415			—			—		369,766			—			—			369,766
Cost of crude oil		—			—		21,340			—			—			21,340			—			—		56,021			—			—			56,021
Transportation		—			—		5,744			—			—			5,744			—			—		3,416			—			—			3,416
Operations and maintenance		—			—		13,028			—			—			13,028			553			—		12,512			—			—			13,065
Depreciation and amortization		10			—		13,825			—			—			13,835			11			—		12,756			—			—			12,767
General and administrative		4,261			—		5,060			—			—			9,321			5,961			—		4,975			—			—			10,936
Taxes other than income		—			—		727									727			—			—		729									729
Equity in (earnings) loss from unconsolidated affiliates		—			—		(2,099	)		(2,099	)		2,099			(2,099	)		—			—		(4,788	)		(4,788	)		4,788			(4,788	)

Total costs and expenses		4,271			—		180,040			(2,099	)		2,099			184,311			6,525			—		455,387			(4,788	)		4,788			461,912

Operating (loss) income		(4,271	)		—		22,873			2,099			(2,099	)		18,602			(6,525	)		—		45,891			4,788			(4,788	)		39,366
Interest and other income		—			—		8			—			—			8			3			—		275			—			—			278
Interest and other financing costs		(12,802	)		—		801			—			—			(12,001	)		(12,200	)		—		(3,877	)		—			—			(16,077	)

(Loss) income before income taxes and equity in earnings from consolidated subsidiaries		(17,073	)		—		23,682			2,099			(2,099	)		6,609			(18,722	)		—		42,289			4,788			(4,788	)		23,567
Provision for income taxes		(571	)		—		—			—			—			(571	)		(365	)		—		—			—			—			(365	)

(Loss) income before equity in earnings from consolidated subsidiaries		(17,644	)		—		23,682			2,099			(2,099	)		6,038			(19,087	)		—		42,289			4,788			(4,788	)		23,202
Equity in earnings (loss) from consolidated subsidiaries		22,475			—		—			—			(22,475	)		—			42,289			—		—			—			(42,289	)		—

Net income (loss)	$	4,831		$	—	$	23,682		$	2,099		$	(24,574	)	$	6,038		$	23,202		$	—	$	42,289		$	4,788		$	(47,077	)	$	23,202

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (continued)


	Six Months Ended June 30,
	2009																	2008
									Investment in																	Investment in
						Guarantor			Non-Guarantor														Guarantor			Non-Guarantor
	Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total			Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total
															(In thousands)

Revenue:
Natural gas sales	$	—		$	—	$	159,496		$	—		$	—		$	159,496		$	—		$	—	$	415,887		$	—		$	—		$	415,887
Natural gas liquids sales		—			—		172,294			—			—			172,294			—			—		333,112			—			—			333,112
Crude oil sales		—			—		38,068			—			—			38,068			—			—		98,365			—			—			98,365
Transportation, compression and processing fees		—			—		28,912			—			—			28,912			—			—		29,124			—			—			29,124
Condensate and other		—			—		20,559			—			—			20,559			—			—		26,538			—			—			26,538

Total revenue		—			—		419,329			—			—			419,329			—			—		903,026			—			—			903,026

Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		265,873			—			—			265,873			—			—		667,234			—			—			667,234
Cost of crude oil		—			—		35,768			—			—			35,768			—			—		95,863			—			—			95,863
Transportation		—			—		11,728			—			—			11,728			—			—		6,537			—			—			6,537
Operations and maintenance		—			—		25,850			—			—			25,850			1,064			—		23,831			—			—			24,895
Depreciation and amortization		20			—		26,980			—			—			27,000			23			—		24,314			—			—			24,337
General and administrative		9,919			—		10,127			—			—			20,046			13,423			—		9,363			—			—			22,786
Taxes other than income		—			—		1,513			—			—			1,513			—			—		1,470									1,470
Equity in (earnings) loss from unconsolidated affiliates		—			—		(3,583	)		(3,583	)		3,583			(3,583	)		—			—		(5,184	)		(5,184	)		5,184			(5,184	)

Total costs and expenses		9,939			—		374,256			(3,583	)		3,583			384,195			14,510			—		823,428			(5,184	)		5,184			837,938

Operating (loss) income		(9,939	)		—		45,073			3,583			(3,583	)		35,134			(14,510	)		—		79,598			5,184			(5,184	)		65,088
Interest and other income		—			—		54			—			—			54			25			—		709			—			—			734
Gain on retirement of unsecured debt		3,939			—		—			—			—			3,939			—			—		—						—			—
Interest and other financing costs		(26,220	)		—		(229	)		—			—			(26,449	)		(23,373	)		—		(4,096	)		—			—			(27,469	)

(Loss) income before income taxes and equity in earnings from consolidated subsidiaries		(32,220	)		—		44,898			3,583			(3,583	)		12,678			(37,858	)		—		76,211			5,184			(5,184	)		38,353
Provision for income taxes		(735	)		—		—			—			—			(735	)		(649	)		—		—			—			—			(649	)

(Loss) income before equity in earnings from consolidated subsidiaries		(32,955	)		—		44,898			3,583			(3,583	)		11,943			(38,507	)		—		76,211			5,184			(5,184	)		37,704
Equity in earnings (loss) from consolidated subsidiaries		44,898			—		—			—			(44,898	)		—			76,211			—		—			—			(76,211	)		—

Net income (loss)	$	11,943		$	—	$	44,898		$	3,583		$	(48,481	)	$	11,943		$	37,704		$	—	$	76,211		$	5,184		$	(81,395	)	$	37,704

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


	Six Months Ended June 30,
	2009																2008
									Investment in																Investment in
						Guarantor			Non-Guarantor													Guarantor			Non-Guarantor
	Parent			Co-Issuer		Subsidiaries			Subsidiaries		Eliminations			Total			Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total
														(In thousands)

Cash Flows From Operating Activities:
Net cash provided by (used in) operating activities	$	23,787		$	—	$	55,841		$	11,438	$	(11,438	)	$	79,628		$	(46,127	)	$	—	$	124,112		$	11,718		$	(11,718	)	$	77,985

Cash Flows From Investing Activities:
Net cash provided by (used in) investing activities		11,760			—		(41,899	)		16		(11,776	)		(41,899	)		38,859			—		(101,554	)		(17,932	)		(20,927	)		(101,554	)

Cash Flows From Financing Activities:
Net cash provided by (used in) financing activities		(26,730	)		—		(11,760	)		2,774		8,986			(26,730	)		(1,355	)		—		(38,859	)		18,809			20,050			(1,355	)

Net increase (decrease) in cash and cash equivalents		8,817			—		2,182			14,228		(14,228	)		10,999			(8,623	)		—		(16,301	)		12,595			(12,595	)		(24,924	)
Cash and cash equivalents, beginning of year		20,417			—		43,267			30,212		(30,212	)		63,684			10,018			—		62,647			4,382			(4,382	)		72,665

Cash and cash equivalents, end of period	$	29,234		$	—	$	45,449		$	44,440	$	(44,440	)	$	74,683		$	1,395		$	—	$	46,346		$	16,977		$	(16,977	)	$	47,741

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 6 —	Members’ Capital and Distributions

Class C Units

In accordance with their terms, all remaining Class C units converted into common units on May 1, 2009.

Class D Units

As of June 30, 2009, 3,245,817 Class D units were outstanding. The Class D units are convertible into our common units on a one-for-one basis upon the earlier of (i) payment of our common unit distribution with respect to the fourth quarter of 2009 or (ii) our payment of $6.00 in cumulative distributions per common unit (beginning with our distribution with respect to the fourth quarter of 2007) to common unitholders. The Class D units are not entitled to receive quarterly cash distributions. The Class D units otherwise have the same terms and conditions as our common units, including with respect to voting rights. The Class D units are not listed for trading on The NASDAQ Stock Market LLC or any other securities exchange.

Distributions

The following table summarizes our quarterly cash distributions during 2009:


	Distribution
Quarter Ending	Per unit	Date Declared	Record Date	Payment Date	Amount

December 31, 2008	$0.5750	January 14, 2009	February 2, 2009	February 13, 2009	$31,466,000
March 31, 2009	$0.5750	April 15, 2009	May 1, 2009	May 15, 2009	$31,748,000
June 30, 2009	$0.5750	July 15, 2009	August 3, 2009	August 13, 2009	$31,871,000

Accounting for Equity-Based Compensation

We use SFAS No. 123(R) (FASB ASC 718) to account for equity-based compensation expense related to awards issued under our long-term incentive plan (“LTIP”) discussed below. As of June 30, 2009, the number of units available for grant under our LTIP totaled 1,697,218, of which up to 1,128,188 units were eligible to be issued as restricted common units, phantom units or unit awards.

Restricted Common Units. The aggregate intrinsic value of a restricted common unit award, net of anticipated forfeitures, is amortized into expense over the vesting period of the award. We recognized non-cash compensation expense of $744,000 and $896,000 related to the amortization of restricted common units outstanding during the six months ended June 30, 2009 and 2008, respectively.

A summary of restricted common unit activity for the six months ended June 30, 2009 is provided below:


				Weighted
	Number of			Average
	Restricted			Grant-Date
	Units			Fair Value

Outstanding at beginning of year		169,769		$	22.35
Vested		(5,945	)		16.57
Forfeited		(3,726	)		29.75

Outstanding at end of period		160,098		$	22.39

As of June 30, 2009, unrecognized compensation costs related to outstanding restricted common units totaled $1,973,000. The expense is expected to be recognized over an approximate weighted average period of two years. The total fair value of restricted common units vested during the three months ended June 30, 2009 was $92,000.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 6 —	Members’ Capital and Distributions (Continued)

Phantom Units. The aggregate intrinsic value of a phantom unit award, net of anticipated forfeitures, is amortized into expense over the vesting period of the award. We recognized non-cash compensation expense of $2,277,000 and $581,000 related to the amortization of phantom units outstanding during the six months ended June 30, 2009 and 2008, respectively.

A summary of phantom unit activity for the six months ended June 30, 2009 is provided below:


				Weighted
	Number of			Average
	Phantom			Grant-Date
	Units			Fair Value

Outstanding at beginning of year		588,910		$	34.18
Granted		212,700			15.09
Vested		(38,424	)		38.67
Forfeited		(19,821	)		24.12

Outstanding at end of period		743,365		$	28.76

As of June 30, 2009, unrecognized compensation expense related to outstanding phantom units totaled $18,869,000. The expense is expected to be recognized over an approximate weighted average period of four years.

Unit Options. The fair value of a unit option award, net of anticipated forfeitures, is amortized into expense over the option’s vesting period. We recognized non-cash compensation expense of $460,000 and $515,000 related to unit options, net of anticipated forfeitures, for the six months ended June 30, 2009 and 2008, respectively.

A summary of unit option activity for the six months ended June 30, 2009 is provided below:


	Number of
	Units			Weighted
	Underlying			Average
	Options			Exercise Price

Outstanding at beginning of year		1,411,006		$	23.78
Granted		29,000			14.72
Exercised		(6,160	)		10.00
Cancelled		(3,676	)		29.84
Forfeited		(27,384	)		31.82

Outstanding at end of period		1,402,786		$	23.48

The fair value of each unit option granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions. The risk-free rate of periods within the expected life of the option is based on the U.S. Treasury yield curve in effect at the time of grant. The expected volatility and distribution yield rates are based on the average of our historical unit prices and distribution rates and those of similar companies. The expected term of unit options is based on the simplified method and represents the period of time that unit options granted are expected to be outstanding.


	Six Months
	Ended June 30,
	2009			2008

Weighted average exercise price		$14.72			$35.17
Expected volatility		29.8%-32.3	%		20.1%-20.7	%
Distribution yield		6.7%-6.9	%		6.18%-6.24	%
Risk-free interest rate		1.7%-3.3	%		2.7%-3.9	%
Expected term (in years)		6.5			6.5
Weighted average grant-date fair value of options granted		$2.04			$3.22
Total intrinsic value of options exercised		$34,000			$613,000

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 6 —	Members’ Capital and Distributions (Continued)

As of June 30, 2009, unrecognized compensation costs related to outstanding unit options totaled $1,993,000. The expense is expected to be recognized over a weighted average period of approximately seven years.

Unit Appreciation Rights. The fair value of a unit appreciation right (“UAR”) award, net of anticipated forfeitures, is amortized into expense over the UAR’s vesting period. We recognized non-cash compensation expense of $72,000 and $0 related to UARs, net of anticipated forfeitures, for the six months ended June 30, 2009 and 2008, respectively.

A summary of UAR activity for the six months ended June 30, 2009 is provided below:


	Number of
	Units		Weighted
	Underlying		Average
	UARs		Exercise Price

Outstanding at beginning of year		—	$	—
Granted		296,000		15.09

Outstanding at end of period		296,000	$	15.09

The fair value of each UAR granted is estimated on the date of grant using the Black-Scholes option-pricing model with the following assumptions. The risk-free rate of periods within the expected life of the UAR is based on the U.S. Treasury yield curve in effect at the time of grant. The expected volatility and distribution yield rates are based on the average of our historical unit prices and distribution rates and those of similar companies. The expected term of unit appreciation rights is based on the simplified method and represents the period of time that UARs granted are expected to be outstanding.


	Six Months Ended
	June 30, 2009

Weighted average exercise price		$15.09
Expected volatility		31.68%-64.76	%
Distribution yield		6.76%-8.47	%
Risk-free interest rate		0.90%-2.35	%
Expected term (in years)		1.8 - 5.8
Weighted average grant-date fair value of appreciation rights granted		$3.04
Total intrinsic value of appreciation rights exercised		$—

As of June 30, 2009, unrecognized compensation costs related to outstanding UARs totaled $739,000. The expense is expected to be recognized over a weighted average period of approximately three years.

Liability Awards. In November 2008, we amended our Management Incentive Compensation Plan (“MICP”) and Employee Incentive Compensation Program (“EICP”) to provide our Compensation Committee with the discretion to approve bonus payments using equity grants under our LTIP, as an alternative to cash payments. Since SFAS No. 150 (FASB ASC 480), “Accounting for Certain Financial Instruments With Characteristics of Both Liabilities and Equity,” requires unconditional obligations in the form of units that the issuer must or may settle by issuing a variable number of units to be classified as a liability, the LTIP awards issued to settle the EICP and the MICP obligations are classified as liability awards. As of June 30, 2009, we accrued $483,000 and $491,000 for the second quarter 2009 EICP bonuses and an estimate of the 2009 MICP incentive bonuses, respectively.

In February 2009, we amended our LTIP to provide for unit awards, which are awards of common units that are not subject to vesting or forfeiture. For the six months ended June 30, 2009, we granted 189,593 unit awards under our LTIP with a weighted average fair value of $14.78 to settle MICP and EICP obligations.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 6 —	Members’ Capital and Distributions (Continued)

As of June 30, 2009, the estimated unrecognized compensation costs related to outstanding liability awards totaled $1,029,000 and $655,000 for the EICP and MICP, respectively, which are expected to be recognized as expense on a straight-line basis through December 2009 for EICP awards and through February 2010 for MICP awards.


Note 7 —	Net Income Per Unit

Net income per unit is calculated in accordance with SFAS No. 128, “Earnings Per Share” (FASB ASC 260). Basic net income per unit excludes dilution and is computed by dividing net income attributable to each respective class of units by the weighted average number of units outstanding for each respective class during the period. Dilutive net income per unit reflects potential dilution that could occur if convertible securities were converted into common units or contracts to issue common units were exercised except when the assumed conversion or exercise would have an anti-dilutive effect on net income per unit. Dilutive net income per unit is computed by dividing net income attributable to each respective class of units by the weighted average number of units outstanding for each respective class of units during the period increased by the number of additional units that would have been outstanding if the dilutive potential units had been issued.

Basic and diluted net income per unit is calculated as follows (in thousands, except per unit information):


	Three Months Ended June 30,				Six Months Ended June 30,
	2009		2008		2009		2008

Net income available — basic and diluted	$	6,038	$	23,202	$	11,943	$	37,704

Basic weighted average units		54,356		47,672		54,185		47,524
Dilutive weighted average units⁽¹⁾⁽²⁾		57,946		58,010		57,933		57,967
Basic net income per unit	$	0.11	$	0.49	$	0.22	$	0.79

Diluted net income per unit⁽¹⁾⁽²⁾	$	0.10	$	0.40	$	0.21	$	0.65


(1)		Our potentially dilutive common equity includes the following:


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
	(In thousands)

Employee options		97		492		86		512
Unit appreciation rights		—		—		—		—
Restricted units		34		126		24		121
Phantom units		17		—		67		—
Contingent incentive plan unit awards		61		—		61		—
Class C units		135		876		264		963
Class D units		3,246		3,246		3,246		3,246
Class E units		—		5,599		—		5,599

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 7 —	Net Income Per Unit (Continued)


(2)		The following potentially dilutive common equity was excluded from the dilutive net income per unit calculation because to include these equity securities would have been anti-dilutive:


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008
	(In thousands)

Employee options		1,306		952		1,317		931
Unit appreciation rights		296		—		296		—
Restricted units		126		98		136		103
Phantom units		726		231		676		231


Note 8 —	Related Party Transactions

Operations Services

Pursuant to our administrative and operating services agreement, as amended, with Copano/Operations, Inc. (“Copano Operations”), Copano Operations provides certain management, operations and administrative support services to us. Copano Operations is controlled by John R. Eckel, Jr., our Chairman of the Board of Directors and Chief Executive Officer. We reimburse Copano Operations for its direct and indirect costs of providing these services. Specifically, Copano Operations charges us, without markup, based upon total monthly expenses incurred by Copano Operations less (i) a fixed allocation to reflect expenses incurred by Copano Operations for the benefit of certain entities controlled by Mr. Eckel and (ii) any costs to be retained by Copano Operations or charged directly to an entity for which Copano Operations performed services. Our management believes that this methodology is reasonable. For the three months ended June 30, 2009 and 2008, we reimbursed Copano Operations $649,000 and $799,000, respectively, for administrative and operating costs, including payroll and benefits expense for certain of our field and administrative personnel. For the six months ended June 30, 2009 and 2008, we reimbursed Copano Operations $1,287,000 and $1,680,000, respectively, for administrative and operating costs, including payroll and benefits expense for certain of our field and administrative personnel. These costs are included in operations and maintenance expenses and general and administrative expenses on our consolidated statements of operations. As of June 30, 2009, amounts payable by us to Copano Operations were $11,000. In addition, certain of our subsidiaries are co-lessors of office space with Copano Operations. Pursuant to our services agreement with Copano Operations, we reimburse Copano Operations for lease payments that it makes for our benefit.

Our management estimates that these expenses on a stand alone basis (that is, the cost that would have been incurred by us to conduct our current operations if we had obtained these services from an unaffiliated entity) would not be significantly different from the amounts we recorded in our consolidated financial statements for each of the three and six month periods ended June 30, 2009 and 2008.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 8 —	Related Party Transactions (Continued)

Natural Gas and Related Transactions

The following table summarizes transactions between us and affiliated entities (in thousands):


	Three Months				Six Months
	Ended June 30,				Ended June 30,
	2009		2008		2009		2008

Affiliates of Mr. Eckel:
Natural gas sales⁽¹⁾	$	1	$	51	$	1	$	74
Gathering and compression services⁽²⁾		5		7		10		14
Natural gas purchases⁽³⁾		216		322		565		714
Payable by us as of June 30, 2009⁽⁴⁾						71
Webb Duval:
Natural gas sales⁽¹⁾		226		—		595		—
Natural gas purchases⁽³⁾		19		555		233		1,103
Transportation costs⁽⁵⁾		83		101		183		202
Management fees⁽⁶⁾		55		54		110		107
Reimbursable costs⁽⁶⁾		151		160		300		323
Payable to us as of June 30, 2009⁽⁷⁾						503
Payable by us as of June 30, 2009⁽⁴⁾						2
Southern Dome:
Management fees⁽⁶⁾		63		63		125		125
Reimbursable costs⁽⁶⁾		81		91		155		186
Payable to us as of June 30, 2009⁽⁷⁾						363
Bighorn:
Gathering costs⁽⁵⁾		88		142		195		316
Compressor rental fees⁽⁸⁾		165		—		165		—
Management fees⁽⁶⁾		135		68		271		137
Reimbursable costs⁽⁶⁾		577		46		1,256		149
Payable to us as of June 30, 2009⁽⁷⁾						770
Payable by us as of June 30, 2009⁽⁴⁾						27
Fort Union:
Gathering costs⁽⁵⁾		2,031		2,230		4,040		4,106
Treating costs⁽³⁾		152		298		336		351
Management fees⁽⁶⁾		57		22		114		44
Reimbursable costs⁽⁶⁾		157		—		167		—
Payable to us as of June 30, 2009⁽⁷⁾						233
Payable by us as of June 30, 2009⁽⁴⁾						52
Other:
Natural gas sales⁽¹⁾		58		118		97		177
Payable to us as of June 30, 2009⁽⁷⁾						346


(1)		Revenues included in natural gas sales on our consolidated statements of operations.

(2)		Revenues included in transportation, compression and processing fees on our consolidated statements of operations.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 8 —	Related Party Transactions (Continued)


(3)		Included in costs of natural gas and natural gas liquids on our consolidated statements of operations.

(4)		Included in accounts payable on the consolidated balance sheets.

(5)		Costs included in transportation on our consolidated statements of operations.

(6)		Management fees and reimbursable costs received from our unconsolidated affiliates comprise the total compensation paid to us by our unconsolidated affiliates and is included in general and administrative expense on our consolidated statements of operations.

(7)		Included in accounts receivable on the consolidated balance sheets.

(8)		Revenues included in condensate and other on our consolidated statements of operations.

Our management believes these transactions were on terms no less favorable than those that could have been achieved with an unaffiliated entity.

Other

Certain of our operating subsidiaries paid operating subsidiaries of Exterran Holdings, Inc. (“Exterran Holdings”) for the purchase and installation of compressors, compression services and compressor repairs. We paid Exterran Holdings $989,000 and $763,000 for the three months ended June 30, 2009 and 2008, respectively, and $2,134,000 and $3,341,000 for the six months ended June 30, 2009 and 2008, respectively, for their services. Ernie L. Danner, a member of our Board of Directors, serves on the Board of Directors of Exterran Holdings and as its President and Chief Executive Officer.


Note 9 —	Commitments and Contingencies

Commitments

For the three months ended June 30, 2009 and 2008, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $2,147,000 and $1,774,000, respectively. For the six months ended June 30, 2009 and 2008, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $4,586,000 and $3,088,000, respectively.

We have both fixed and variable quantity contractual commitments arising in the ordinary course of our natural gas marketing activities. As of June 30, 2009, we had fixed contractual commitments to purchase 822,740 million British thermal units (“MMBtu”) of natural gas in July 2009. As of June 30, 2009, we had fixed contractual commitments to sell 2,945,000 MMBtu of natural gas in July 2009. All of these contracts are based on index-related market pricing. Using index-related market prices as of June 30, 2009, total commitments to purchase natural gas related to such agreements equaled $3,036,00 and total commitments to sell natural gas under such agreements equaled $10,289,000. Our commitments to purchase variable quantities of natural gas at index-based prices range from contract periods extending from one month to the life of the dedicated production. During June 2009, natural gas volumes purchased under such contracts equaled 11,441,110 MMBtu. Our commitments to sell variable quantities of natural gas at index-based prices range from contract periods extending from one month to 2012. During June 2009, natural gas volumes sold under such contracts equaled 5,019,957 MMBtu.

In connection with our acquisition of Cantera Natural Gas, LLC (“Cantera”), we assumed a “Contingent Consideration Note” to CMS Gas Transmission Company (“CMS Gas Transmission”), dated as of July 2, 2003, that provided for annual payments to CMS Gas Transmission through March 2009 contingent upon Bighorn and Fort Union achieving certain earnings thresholds. In April 2009, we paid $2,834,000 as the sole and final consideration to fulfill our obligation under the note.

We are party to firm transportation agreements with Wyoming Interstate Gas Company (“WIC”), under which we are obligated to pay for transportation capacity whether or not we use such capacity. Under these agreements, we

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 9 —	Commitments and Contingencies (Continued)

are obligated to pay approximately $5,224,000 for the remainder of 2009, $9,876,000 in 2010, $9,876,000 in 2011, $9,867,000 in 2012, $8,978,000 in 2013 and $24,713,000 thereafter. The agreements expire on December 31, 2019. All of our obligations under these agreements are offset by capacity release agreements between us and third parties, under which they pay for the right to use our capacity. These capacity release agreements cover 100% of our total WIC capacity and continue through December 31, 2019. We have placed in escrow $1,858,000, classified as escrow cash on the consolidated balance sheets, as credit support for our obligations under the WIC agreements.

Additionally, we have two firm gathering agreements with Fort Union, under which we are obligated to pay for gathering capacity on the Fort Union system whether or not we use such capacity. Under these agreements, we are obligated to pay approximately $5,105,000 for the remainder of 2009, $4,582,000 for 2010, $5,859,000 for 2011, $7,154,000 for 2012 and $7,665,000 for each of the years thereafter. Generally, we resell our firm capacity to third parties under various types of agreements. We have sub-contracted approximately one third of our existing commitment to third parties for the duration of the obligation. These commitments expire in November 2009 and November 2017.

Regulatory Compliance

In the ordinary course of business, we are subject to various laws and regulations. In the opinion of our management, compliance with existing laws and regulations will not materially affect our financial position.

Litigation

As a result of our Cantera acquisition in October 2007, we acquired Cantera Gas Company LLC (“Cantera Gas Company,” formerly CMS Field Services, Inc. (“CMSFS”)). Cantera Gas Company is a party to a number of legal proceedings alleging (i) false reporting of natural gas prices by CMSFS and numerous other parties and (ii) other related claims. The claims made in these proceedings are based on events that occurred before Cantera Resources, Inc. acquired CMSFS in June 2003 (the “CMS Acquisition”). The amount of liability, if any, against Cantera Gas Company is not reasonably estimable. Pursuant to the CMS Acquisition purchase agreement, CMS Gas Transmission has assumed responsibility for the defense of these claims, and Cantera Gas Company is fully indemnified by CMS Gas Transmission and its parent, CMS Enterprises Company, against any losses that Cantera Gas Company may suffer as a result of these claims.

As a result of the Cimmarron acquisition and a smaller 2007 “bolt-on” acquisition, we, through wholly owned subsidiaries, assumed three natural gas purchase agreements with Targa North Texas LP (“Targa”) pursuant to which we have sold natural gas purchased from north Texas producers to Targa (the “Targa Agreements”). One of these agreements terminated on June 1, 2008, and the remaining agreements expire on October 1, 2010 and December 1, 2011. Because of a dispute regarding what portion, if any, of the natural gas we purchase from north Texas producers has been contractually dedicated for resale to Targa, our wholly owned subsidiary, River View Pipelines, L.L.C. (“River View”), filed suit against Targa in the 190th Judicial District Court in Harris County, Texas, on May 28, 2008, seeking a declaratory judgment that River View has no obligation to sell to Targa any natural gas River View purchases from wells located in Denton, Wise, Cooke or Montague Counties, Texas. In Targa’s response filed July 25, 2008, Targa seeks a declaratory judgment that this natural gas is contractually dedicated to Targa and claims unspecified monetary damages for alleged breaches of the Targa Agreements by River View and certain other wholly owned subsidiaries, all of which we dispute. The trial is scheduled for April 10, 2010, and the litigation is in the preliminary stage of discovery. Although we believe that our interpretation of the Targa Agreements’ contractual dedication provisions is correct, we can give no assurances regarding the litigation’s outcome, and any potential liability we may incur is not reasonably estimable.

We may, from time to time, be involved in other litigation and claims arising out of our operations in the normal course of business.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 9 —	Commitments and Contingencies (Continued)

Definitive Purchase Agreement

In September 2008, we signed a definitive purchase agreement with Williams’ Transco subsidiary to acquire the McMullen Lateral pipeline, a 151-mile, 24-inch pipeline extending from McMullen County, Texas, to Wharton County, Texas. Closing of the transaction is subject to receipt of necessary and requested Federal Energy Regulatory Commission (“FERC”) authorizations. On December 19, 2008, we filed a joint application with Transco to acquire the McMullen Lateral through an abandonment proceeding (filing number CP 09-38-000). As of August 7, 2009, the FERC has not ruled on our application. Our Board of Directors has also approved construction projects designed to integrate the McMullen Lateral with our existing facilities, provide McMullen Lateral shippers access to numerous third party pipelines, including Transco, and also provide an additional residue gas outlet for our Houston Central processing plant. The purchase price for the McMullen Lateral is $42.5 million, and we anticipate that the combined costs of the acquisition and related construction projects will total approximately $95 million. We plan to finance the transaction and related projects with cash from operations, cash on hand and borrowings under our Credit Facility. Subject to FERC approval, we anticipate making these capital expenditures primarily in 2009 and 2010.


Note 10 —	Supplemental Disclosures to the Statements of Cash Flows


	Six Months
	Ended June 30,
	2009		2008
	(In thousands)

Cash payments for interest, net of $2,347,000 and $1,423,000 capitalized in 2009 and 2008, respectively	$	26,275	$	20,503
Cash payments for federal and state income taxes	$	790	$	—

We incurred a decrease in liabilities for investing activities that had not been paid as of June 30, 2009 of $10,691,000 and an increase in liabilities of $8,842,000 as of June 30, 2008. Such amounts are not included in the change in accounts payable and accrued liabilities or with acquisitions, additions to property, plant and equipment and intangible assets on the consolidated statements of cash flows.


Note 11 —	Financial Instruments

Commodity Risk Hedging Program

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices as a result of: (i) processing or conditioning at our processing plants or third-party processing plants and (ii) purchasing and selling volumes of natural gas at index-related prices. In order to manage the risks associated with natural gas and NGL prices, we engage in risk management activities that take the form of commodity derivative instruments. These activities are governed by our risk management policy, which, subject to certain limitations, allows our management to purchase options and enter into swaps for crude oil, NGLs and natural gas in order to reduce our exposure to a substantial adverse change in the prices of those commodities. Our risk management policy prohibits the use of derivative instruments for speculative purposes.

Financial instruments that we acquire pursuant to our risk management policy are generally designated as cash flow hedges under SFAS No. 133 (FASB ASC 815) and are recorded on our consolidated balance sheets at fair value. For derivatives designated as cash flow hedges, we recognize the effective portion of changes in fair value as other comprehensive income (“OCI”) and reclassify them to revenue within the consolidated statements of income as the underlying transactions impact earnings. For derivatives not designated as cash flow hedges, we recognize

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

changes in fair value as a gain or loss in our consolidated statements of income. These financial instruments serve the same risk management purpose whether designated as a cash flow hedge or not.

We assess, both at the inception of the hedge and on an ongoing basis, whether the derivatives are effective in hedging the variability of forecasted cash flows of underlying hedged items. If it is determined that a derivative is not effective as a hedge or that it has ceased to be an effective hedge due to the loss of correlation between the hedging instrument and the underlying hedged item or it becomes probable that the original forecasted transaction will not occur, we discontinue hedge accounting and subsequent changes in the derivative fair value are immediately recognized as a gain or loss (increase or decrease in revenue) in our consolidated statements of income.

During the six months ended June 30, 2009, we recorded unrealized mark-to-market losses of $357,000 related to undesignated economic hedges and unrealized losses of $192,000 related to ineffectiveness on our risk management portfolio. During the six months ended June 30, 2008, we recorded unrealized mark-to-market losses of $7,014,000 and unrealized gains of $246,000 related to ineffectiveness on our risk management portfolio. As of June 30, 2009, we estimated that $9,898,000 of OCI will be reclassified through earnings in the next 12 months as a result of monthly physical settlements of crude oil, NGLs and natural gas.

The following tables summarize our commodity hedge portfolio as of June 30, 2009 (all hedges are settled monthly):

Purchased CenterPoint East Natural Gas Puts


	Put
	Put Strike		Put Volumes
	(Per MMBtu)		(MMBtu/d)

2009	$	6.9500		5,000

Purchased Houston Ship Channel Index Natural Gas Options


	Call Spread						Call
	Call Strike
	(Per MMBtu)				Call Volumes		Strike		Volume
	Bought		Sold		(MMBtu/d)		(Per MMBtu)		(MMBtu/d)

2009	$	7.7500	$	10.0000		8,000	$	10.0000		10,000
2010	$	7.3500	$	10.0000		7,100	$	10.0000		10,000
2011	$	6.9500	$	10.0000		7,100	$	10.0000		10,000

Purchased Mt. Belvieu Purity Ethane Puts and Entered into Swaps


	Put				Swap
	Strike		Volumes		Price		Volumes
	(Per gallon)		(Bbls/d)		(Per gallon)		(Bbls/d)

2009	$	0.5900		2,200	$	0.6025		1,100
2010	$	0.5550		1,600	$	0.5700		500
2011	$	0.5300		1,700	$	0.5450		500

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

Purchased Mt. Belvieu Purity Ethane Put Spread Options


	Put Spread
	Strike
	(Per gallon)				Volumes
	Bought		Sold		(Bbls/d)

2009	$	0.8300	$	0.5900		1,100
2009	$	0.7900	$	0.5900		1,100

Purchased Mt. Belvieu TET Propane Puts and Entered into Swaps


	Put					Swap
	Strike		Volumes			Price		Volumes
	(Per gallon)		(Bbls/d)			(Per gallon)		(Bbls/d)

2009	$	0.8725		2,200			—		—
2009	$	0.9650		1,000	⁽¹⁾	$	1.0275		1,000	⁽²⁾
2010	$	0.8500		1,100			—		—
2010	$	0.9460		700		$	0.9925		700
2011	$	0.8265		1,100			—		—
2011	$	0.9340		700		$	0.9750		700
2011	$	1.3300		900			—		—


(1)		Includes 423 Bbls/d that are not designated as a cash flow hedge under hedge accounting.

(2)		Includes 750 Bbls/d that were unwound in July 2009.

Purchased Mt. Belvieu TET Propane Put Spread Options


	Put Spread
	Strike
	(Per gallon)				Volumes
	Bought		Sold		(Bbls/d)

2009	$	1.3300	$	0.8725		1,600
2009	$	1.3300	$	0.8725		600
2009	$	1.3300	$	0.9650		100
2010	$	1.4900	$	0.8500		1,100
2010	$	1.4900	$	0.9460		700

Purchased Mt. Belvieu Non-TET Isobutane Puts and Entered into Swaps


	Put				Swap
	Strike		Volumes		Price		Volumes
	(Per gallon)		(Bbls/d)		(Per gallon)		(Bbls/d)

2009	$	1.0600		450		—		—
2009	$	1.1600		100	$	1.2425		100
2010	$	1.0350		300		—		—
2010	$	1.1145		100	$	1.2025		100
2011	$	1.0205		300		—		—
2011	$	1.1100		100	$	1.1800		100
2011	$	1.7100		200		—		—

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

Purchased Mt. Belvieu Non-TET Isobutane Put Spread Options


	Put Spread
	Strike
	(Per gallon)				Volumes
	Bought		Sold		(Bbls/d)

2009	$	1.6200	$	1.0600		175
2009	$	1.5700	$	1.0600		275
2009	$	1.6200	$	1.1600		100
2010	$	1.8900	$	1.1145		100
2010	$	1.8900	$	1.0350		300

Purchased Mt. Belvieu Non-TET Normal Butane Puts and Entered into Swaps


	Put					Swap
	Strike		Volumes			Price			Volumes
	(Per gallon)		(Bbls/d)			(Per gallon)			(Bbls/d)

2009	$	1.0525		700			—			—
2009	$	1.1400		400	⁽³⁾	$	1.2275			400	⁽⁴⁾
2009		—		—		$	(1.7025	)		(320	)⁽⁵⁾
2010	$	1.0300		300			—			—
2010	$	1.1000		200		$	1.1850			200
2011	$	1.0205		300			—			—
2011	$	1.0850		200		$	1.1700			200
2011	$	1.7100		350			—			—


(3)		Includes 145 Bbls/d that were unwound in July 2009.

(4)		Includes 395 Bbls/d that are not designated as a cash flow hedge under hedge accounting.

(5)		Instrument is not designated as a cash flow hedge under hedge accounting.

Purchased Mt. Belvieu Non-TET Normal Butane Put Spread Options


	Put Spread
	Strike
	(Per gallon)				Volumes
	Bought		Sold		(Bbls/d)

2009	$	1.58	$	1.0525		150
2009	$	1.54	$	1.0525		550
2009	$	1.58	$	1.1400		200
2010	$	1.88	$	1.1000		200
2010	$	1.88	$	1.0300		300

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

Purchased Mt. Belvieu Non-TET Natural Gasoline Puts and Entered into Swaps


	Put				Swap
	Strike		Volumes		Price		Volumes
	(Per gallon)		(Bbls/d)		(Per gallon)		(Bbls/d)

2009	$	1.440		200	$	1.540		200
2010	$	1.408		300		—		—
2011	$	1.410		300		—		—

Purchased Mt. Belvieu Non-TET Natural Gasoline Put Spread Options


	Put Spread
	Strike
	(Per gallon)				Volumes
	Bought		Sold		(Bbls/d)

2009	$	1.98	$	1.440		120
2010	$	2.54	$	1.408		300

Purchased WTI Crude Oil Puts


	Put
	Strike		Volumes
	(Per barrel)		(Bbls/d)

2009	$	55.00		1,000
2009	$	60.00		500
2010	$	55.00		1,000
2010	$	60.00		400
2011	$	55.00		1,000
2011	$	60.00		400

Purchased WTI Crude Oil Put Spread Options


	Put Spread
	Strike
	(Per barrel)				Volumes
	Bought		Sold		(Bbls/d)

2009	$	86.50	$	55.00		750
2009	$	92.00	$	55.00		250
2009	$	92.00	$	60.00		500
2010	$	118.00	$	55.00		1,000
2010	$	118.00	$	60.00		400

Interest Rate Risk Hedging Program

Our interest rate exposure results from variable rate borrowings under our Credit Facility. We manage a portion of our interest rate exposure by utilizing interest rate swaps, which allow us to convert a portion of variable rate debt into fixed rate debt. As of June 30, 2009, we hold a notional amount of $145.0 million in interest rate swaps with an average fixed rate of 4.44% that mature between July 2010 and October 2012. None of the interest rate swaps outstanding as June 30, 2009 were designated as cash flow hedges.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

For the six months ended June 30, 2009, interest and other financing costs on the consolidated statement of operations include unrealized mark-to-market gains of $2,184,000 on undesignated interest rate swaps and no ineffectiveness on designated interest rate swaps. For the six months ended June 30, 2009, we paid $2,414,000 in settlement of expired positions. For the six months ended June 30, 2008, interest and other financing costs on the consolidated statement of operations includes unrealized mark-to-market losses of $3,250,000 on undesignated interest rate swaps and unrealized gains of $17,000 on designated interest rate swaps. For the six months ended June 30, 2008, we paid $862,000 in settlement of expired positions.

SFAS No. 157 Fair Value Measurement (FASB ASC 820) and SFAS No. 161 Disclosures about Derivative Instruments and Hedging Activities (FASB ASC 815)

We recognize the fair value of our assets and liabilities that require periodic re-measurement as necessary based upon the requirements of SFAS No. 157. This standard defines fair value, expands disclosure requirements with respect to fair value and specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. “Inputs” are the assumptions that a market participant would use in valuing the asset or liability. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our market assumptions. The three levels of the fair value hierarchy established by SFAS No. 157 are as follows:


	•	Level 1 — Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

	•	Level 2 — Quoted prices in markets that are not considered to be active or financial instruments for which all significant inputs are observable, either directly or indirectly; and

	•	Level 3 — Prices or valuations that require inputs that are both significant to the fair value measurement and unobservable. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

At each balance sheet date, we perform an analysis of all instruments subject to SFAS No. 157 and include in Level 3 all of those for which fair value is based on significant unobservable inputs.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

The following table sets forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis. As required by SFAS No. 157, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value of assets and liabilities and their placement with the fair value hierarchy levels.


	Fair Value Measurements on Hedging Instruments^(a)
	June 30, 2009											December 31, 2008
	Level 1		Level 2			Level 3			Total			Level 1		Level 2			Level 3			Total
	(In thousands)											(In thousands)

Assets
Commodity derivatives:
Short-term — Designated^(b)	$	—	$	—		$	44,265		$	44,265		$	—	$	—		$	76,440		$	76,440
Short-term — Not designated^(b)		—		—			5			5			—		—			—			—
Long-term — Designated^(c)		—		—			36,936			36,936			—		—			81,192			81,192
Long-term — Not designated^(c)		—		—			202			202			—		—			1,700			1,700

Total	$	—	$	—		$	81,408		$	81,408		$	—	$	—		$	159,332		$	159,332

Liabilities
Commodity derivatives:
Short-term — Designated^(d)	$	—	$	—		$	1,345		$	1,345		$	—	$	—		$	—		$	—
Short-term — Not designated^(d)		—		—			1,172		$	1,172			—		—			2,308			2,308
Long-term — Designated^(e)		—		—			6,851			6,851			—		—			4,347			4,347
Interest rate derivatives:
Short-term — Designated^(d)		—		—			—			—			—		302			—			302
Short-term — Not designated^(d)		—		5,257			—			5,257			—		3,662			—			3,662
Long-term — Designated^(e)		—		—			—			—			—		854			—			854
Long-term — Not designated^(e)		—		3,716			—			3,716			—		6,288			—			6,288

Total	$	—	$	8,973		$	9,368		$	18,341		$	—	$	11,106		$	6,655		$	17,761

Total designated	$	—	$	—		$	73,005		$	73,005		$	—	$	(1,156	)	$	153,285		$	152,129

Total not designated	$	—	$	(8,973	)	$	(965	)	$	(9,938	)	$	—	$	(9,950	)	$	(608	)	$	(10,558	)


(a)		Instruments re-measured on a recurring basis.

(b)		Included on the consolidated balance sheets as a current assets under the heading of “Risk management assets.”

(c)		Included on the consolidated balance sheets as a noncurrent asset under the heading of “Risk management assets.”

(d)		Included on the consolidated balance sheets as a current liabilities under the heading of “Risk management liabilities.”

(e)		Included on the consolidated balance sheets as a noncurrent liability under the heading of “Risk management and other noncurrent liabilities.”

Our commodity derivative instruments are Level 3 derivative contracts, which we value using internally developed valuation models. If the commodity underlying a derivative instrument is traded on an index that provides observable market information, such as West Texas Intermediate crude and Houston Ship Channel natural gas, we include the observable market price and volatility data as inputs to our valuation model. If the commodity underlying a derivative instrument is traded on an index that is thinly traded or has no readily observable market data, such as NGLs and Center Point East natural gas, the inputs to our valuation model are based on forward pricing curves that we generate using a multi-variable linear regression methodology and implied volatilities from markets for comparable products.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

The following table provides a reconciliation of changes in the fair value of derivatives classified as Level 3 in the fair value hierarchy (in thousands):


	Three Months Ended
	June 30,						Six Months Ended June 30,
	2009			2008			2009			2008

Asset (liability) balance, beginning of period	$	136,151		$	(35,204	)	$	152,677		$	(48,407	)
Total gains (losses):
Non-cash amortization of option premium		(9,291	)		(8,494	)		(18,479	)		(16,057	)
Other amounts included in earnings		20,049			(8,999	)		45,332			(19,229	)
Included in accumulated other comprehensive loss		(54,108	)		(24,648	)		(61,609	)		(25,348	)
Purchases		—			16,640			—			42,590
Settlements		(20,761	)		6,716			(45,881	)		12,462
Transfers in and/or out of Level 3		—			—			—			—

Asset (liability) balance, end of period	$	72,040		$	(53,989	)	$	72,040		$	(53,989	)

Change in unrealized losses included in earnings relating to instruments still held as of end of period	$	(414	)	$	(2,283	)	$	(357	)	$	(6,768	)

Unrealized and realized gains and losses for Level 3 recurring items recorded in earnings are included in revenue on the consolidated statements of operations. The effective portion of unrealized gains and losses relating to cash flow hedges are included in accumulated other comprehensive loss on the consolidated balance sheet and statement of members’ capital and comprehensive income (loss).

Transfers in and/or out of Level 3 represent existing assets or liabilities that were either previously categorized as a higher level for which the inputs to the model became unobservable or assets and liabilities that were previously classified as Level 3 for which the lowest significant input became observable during the period. There were no transfers in or out of Level 3 during the period.

We have not entered into any derivative transactions containing credit risk related contingent features as of June 30, 2009.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

The following table presents derivatives that are designated as cash flow hedges:

The Effect of Derivative Instruments on the Statements of Operations
(In thousands)


							Amount of Gain or
							(Loss) Recognized
							in Income on
							Derivative
	Amount of Gain or			Amount of Gain or			(Ineffective
	(Loss) Recognized			(Loss) Reclassified			Portion and Amount
Derivatives in SFAS 133	in OCI on			from Accumulated			Excluded from
(FASB ASC 815) Cash	Derivatives			OCI into Income			Effectiveness			Statement of Operations
Flow Hedging Relationships	(Effective Portion)			(Effective Portion)			Testing)			Location

*Three Months Ended June 30, 2009*
Natural gas	$	(832	)	$	(933	)	$	68		Natural gas sales
Natural gas liquids		(31,008	)		8 ,016			(22	)	Natural gas liquids sales
Crude oil		(11,576	)		3,609			(345	)	Condensate and other
Interest rate swaps		250			119			—		Interest and other financing costs

Total	$	(43,166	)	$	10,811		$	(299	)

*Six Months Ended June 30, 2009*
Natural gas	$	(1,342	)	$	(1,699	)	$	68		Natural gas sales
Natural gas liquids		(23,049	)		19,509			(37	)	Natural gas liquids sales
Crude oil		(11,749	)		7,659			(222	)	Condensate and other
Interest rate swaps		(12	)		38			—		Interest and other financing costs

Total	$	(36,152	)	$	25,507		$	(191	)

The following table presents derivatives that are not designated as cash flow hedges:

The Effect of Derivative Instruments on the Statements of Operations
(In thousands)


	Amount of Gain or
Derivatives Not Designated as Hedging Instruments	(Loss) Recognized in			Statement of Operations
Under Statement 133	Income on Derivative			Location

*Three months ended June 30, 2009*
Natural gas liquids	$	(414	)	Natural gas liquids sales
Interest rate		2,109		Interest and other financing costs

Total	$	1,695

*Six months ended June 30, 2009*
Natural gas liquids	$	(357	)	Natural gas liquids sales
Interest rate		2,184		Interest and other financing costs

Total	$	1,827

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 12 —	Fair Value of Financial Instruments

Amounts reflected in our consolidated balance sheets as of June 30, 2009 for cash and cash equivalents approximate fair value. We believe that the fair value of our Credit Facility does not approximate its carrying value as of June 30, 2009 because the applicable floating rate margin on our Credit Facility was below market rate. The fair value of our Credit Facility has been estimated based on similar debt transactions that occurred during the six months ended June 30, 2009. Estimates of the fair value of our Senior Notes are based on market information as of June 30, 2009. A summary of the fair value and carrying value of the financial instruments as of June 30, 2009 is shown in the table below.


	June 30, 2009
	Carrying		Estimated
	Value		Fair Value
	(In thousands)

Cash and cash equivalents	$	74,683	$	74,683
Credit Facility		270,000		258,933
2016 Notes		332,665		314,368
2018 Notes		249,525		225,820


Note 13 —	Segment Information

We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into the following three segments for both internal and external reporting and analysis:


	•	Oklahoma, which includes midstream natural gas services in central and east Oklahoma, including gathering and related compression, dehydration, treating and nitrogen rejection services and natural gas processing. This segment also includes a crude oil pipeline located in south Oklahoma and north Texas and our equity investment in Southern Dome.

	•	Texas, which includes midstream natural gas services in south and north Texas, including gathering and intrastate transmission of natural gas, and related services such as compression, dehydration and marketing. Our Texas segment also provides natural gas processing, conditioning and treating and NGL fractionation and transportation. Our Texas segment includes our Louisiana processing assets and our equity investment in Webb Duval.

	•	Rocky Mountains, which includes natural gas gathering and related operations in Wyoming. Our Rocky Mountains segment includes our equity investments in Bighorn and Fort Union, two firm gathering agreements with Fort Union and two firm transportation agreements with WIC.

The amounts indicated below as “Corporate and other” relate to our risk management activities, intersegment eliminations and other activities we perform or assets we hold that have not been allocated to any of our reporting segments.

We evaluate segment performance based on segment gross margin before depreciation, amortization and impairment. All of our revenue is derived from, and all of our assets and operations are located in Oklahoma, Texas, Wyoming and Louisiana in the United States. Operating and maintenance expenses and general and administrative expenses incurred at corporate and other are allocated to Oklahoma, Texas and Rocky Mountains based on actual expenses incurred by each segment or an allocation based on activity, as appropriate.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 13 —	Segment Information (Continued)

Summarized financial information concerning our reportable segments is shown in the following table (in thousands). Prior year information has been restated to conform to the current year presentation of our segment information.

Rocky

Total

Corporate

Oklahoma

Texas

Mountains

Segments

and Other

Consolidated

Three Months Ended June 30, 2009:

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents