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 September 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 (State or Other Jurisdiction of Incorporation or Organization)		51-0411678 (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). o Yes o No

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 54,613,863 common units of Copano Energy, L.L.C. outstanding at November 2, 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 September 30, 2009 and December 31, 2008		3
		Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2009 and 2008		4
		Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2009 and 2008		5
		Unaudited Consolidated Statement of Members’ Capital and Comprehensive Income (Loss) for the Nine Months Ended September 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		40
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		61
	Item 4.	Controls and Procedures		66

PART II — OTHER INFORMATION
	Item 1.	Legal Proceedings		67
	Item 1A.	Risk Factors		67
	Item 6.	Exhibits		67
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


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

ASSETS
Current assets:
Cash and cash equivalents	$	35,378		$	63,684
Accounts receivable, net		81,963			96,028
Risk management assets		47,128			76,440
Prepayments and other current assets		3,688			4,891
Discontinued operations (Note 13)		5,608			5,465

Total current assets		173,765			246,508

Property, plant and equipment, net		834,756			819,099
Intangible assets, net		191,842			198,440
Investment in unconsolidated affiliates		627,068			640,598
Escrow cash		1,858			1,858
Risk management assets		31,346			82,892
Other assets, net		21,924			24,270

Total assets	$	1,882,559		$	2,013,665


LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable	$	89,285		$	103,849
Accrued interest		9,549			11,904
Accrued tax liability		495			784
Risk management liabilities		8,019			6,272
Other current liabilities		10,222			16,787
Discontinued operations (Note 13)		384			—

Total current liabilities		117,954			139,596

Long-term debt (includes $647 and $704 bond premium as of September 30, 2009 and December 31, 2008, respectively)		842,837			821,119
Deferred tax provision		2,256			1,718
Risk management and other noncurrent liabilities		11,966			13,274
Commitments and contingencies (Note 9)
Members’ capital:
Common units, no par value, 54,601,458 units and 53,965,288 units issued and outstanding as of September 30, 2009 and December 31, 2008, respectively		878,994			865,343
Class C units, no par value, 0 units and 394,853 units issued and outstanding as of September 30, 2009 and December 31, 2008, respectively		—			13,497
Class D units, no par value, 3,245,817 units issued and outstanding as of September 30, 2009 and December 31, 2008		112,454			112,454
Paid-in capital		41,168			33,734
Accumulated deficit		(133,900	)		(54,696	)
Accumulated other comprehensive income		8,830			67,626

		907,546			1,037,958

Total liabilities and members’ capital	$	1,882,559		$	2,013,665

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						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(In thousands, except per unit information)

Revenue:
Natural gas sales	$	66,747		$	204,187		$	226,243		$	620,074
Natural gas liquids sales		99,098			174,867			271,392			507,979
Transportation, compression and processing fees		13,926			13,772			42,838			42,896
Condensate and other		9,760			10,044			30,319			36,582

Total revenue		189,531			402,870			570,792			1,207,531

Costs and expenses:
Cost of natural gas and natural gas liquids⁽¹⁾		129,617			332,346			395,114			999,580
Transportation⁽¹⁾		6,484			9,151			18,211			15,688
Operations and maintenance		13,202			15,211			38,764			39,770
Depreciation and amortization		14,575			12,700			41,071			36,929
General and administrative		9,200			11,042			29,246			33,828
Taxes other than income		836			723			2,349			2,193
Equity in earnings from unconsolidated affiliates		(2,529	)		(2,170	)		(6,112	)		(7,354	)

Total costs and expenses		171,385			379,003			518,643			1,120,634

Operating income		18,146			23,867			52,149			86,897
Other income (expense):
Interest and other income		1,065			357			1,119			1,091
Gain on retirement of unsecured debt		—			—			3,939			—
Interest and other financing costs		(15,440	)		(15,470	)		(41,889	)		(42,939	)

Income before income taxes and discontinued operations		3,771			8,754			15,318			45,049
Provision for income taxes		(304	)		(197	)		(1,039	)		(846	)

Income from continuing operations		3,467			8,557			14,279			44,203
Discontinued operations, net of tax (Note 13)		262			166			1,393			2,224

Net income	$	3,729		$	8,723		$	15,672		$	46,427

Basic net income per unit:
Income per unit from continuing operations	$	0.06		$	0.18		$	0.26		$	0.93
Income per unit from discontinued operations		0.01			0.00			0.03			0.04

Net income per unit	$	0.07		$	0.18		$	0.29		$	0.97

Weighted average number of units		54,565			47,868			54,313			47,640
Diluted net income per common unit:
Income per unit from continuing operations	$	0.06		$	0.15		$	0.25		$	0.76
Income per unit from discontinued operations		0.00			0.00			0.02			0.04

Net income per unit	$	0.06		$	0.15		$	0.27		$	0.80

Weighted average number of units		58,036			57,939			57,953			57,891


(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


	Nine Months Ended
	September 30,
	2009			2008
	(In thousands)

Cash Flows From Operating Activities:
Net income	$	15,672		$	46,427
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		41,628			37,092
Amortization of debt issue costs		3,060			2,552
Equity in earnings from unconsolidated affiliates		(6,112	)		(7,354	)
Distributions from unconsolidated affiliates		18,333			18,387
Gain on retirement of unsecured debt		(3,939	)		—
Non-cash (gain) loss on risk management activities, net		(1,443	)		9,485
Equity-based compensation		6,692			3,542
Deferred tax provision		538			294
Other non-cash items		202			(132	)
Changes in assets and liabilities:
Accounts receivable		14,857			6,879
Prepayments and other current assets		1,196			655
Risk management activities		23,462			(35,397	)
Accounts payable		(12,034	)		21,259
Other current liabilities		(1,363	)		(2,468	)

Net cash provided by operating activities		100,749			101,221

Cash Flows From Investing Activities:
Additions to property, plant and equipment		(51,540	)		(115,292	)
Additions to intangible assets		(1,756	)		(4,710	)
Acquisitions		(6,003	)		(83	)
Investment in unconsolidated affiliates		(3,240	)		(25,623	)
Distributions from unconsolidated affiliates		3,191			1,971
Escrow cash		—			(1,856	)
Other		(1,358	)		(1,232	)

Net cash used in investing activities		(60,706	)		(146,825	)

Cash Flows From Financing Activities:
Proceeds from long-term debt		50,000			539,000
Repayment of long-term debt		(10,000	)		(314,000	)
Retirement of unsecured debt		(14,286	)		—
Deferred financing costs		—			(6,670	)
Distributions to unitholders		(94,217	)		(76,623	)
Capital contributions from pre-IPO investors		—			4,103
Equity offering costs		—			(47	)
Proceeds from option exercises		154			1,001

Net cash (used in) provided by financing activities		(68,349	)		146,764

Net (decrease) increase in cash and cash equivalents		(28,306	)		101,160
Cash and cash equivalents, beginning of year		63,684			72,665

Cash and cash equivalents, end of period	$	35,378		$	173,825

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 units		395		13,497		(395	)		(13,497	)		—		—		—		—		—		—			—			—		$	—
Distributions to unitholders		—		—		—			—			—		—		—		—		—		(94,876	)		—			(94,876	)		—
Option exercises		15		154		—			—			—		—		—		—		—		—			—			154
Equity-based compensation		—		—		—			—			—		—		—		—		5,982		—			—			5,982			—
Vested restricted units		57		—		—			—			—		—		—		—		—		—			—			—			—
Vested phantom units		27		—		—			—			—		—		—		—		—		—			—			—			—
Vested unit awards		142		—		—			—			—		—		—		—		1,452		—			—			1,452			—
Net income		—		—		—			—			—		—		—		—		—		15,672			—			15,672			15,672
Derivative settlements reclassified to income		—		—		—			—			—		—		—		—		—		—			(35,103	)		(35,103	)		(35,103	)
Unrealized loss-change in fair value of derivatives		—		—		—			—			—		—		—		—		—		—			(23,693	)		(23,693	)		(23,693	)

Comprehensive loss																														$	(43,124	)

Balance, September 30, 2009		54,601	$	878,994		—		$	—			3,246	$	112,454		—	$	—	$	41,168	$	(133,900	)	$	8,830		$	907,546

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		—		—		—			—			—		—		—		—		—		(77,073	)		—			(77,073	)		—
Option exercises		59		1,001		—			—			—		—		—		—		—		—			—			1,001			—
Equity-based compensation		—		—		—			—			—		—		—		—		3,542		—			—			3,542			—
Vested restricted units		70		—		—			—			—		—		—		—		—		—			—			—			—
Vested phantom units		13		—		—			—			—		—		—		—		—		—			—			—			—
Net income		—		—		—			—			—		—		—		—		—		46,427			—			46,427			46,427
Derivative settlements reclassified to income		—		—		—			—			—		—		—		—		—		—			34,906			34,906			34,906
Unrealized loss-change in fair value of derivatives		—		—		—			—			—		—		—		—		—		—			5,402			5,402			5,402

Comprehensive income																														$	86,735

Balance, September 30, 2008		47,902	$	676,083		790		$	26,995			3,246	$	112,454		5,599	$	175,634	$	31,418	$	(38,513	)	$	(71,627	)	$	912,444

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, through September 2009, 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 September 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. Accordingly, the three and nine months ended September 30, 2008 results have been reclassified to conform to the current periods’ presentation.

Because we sold our crude oil pipeline operations in October 2009, the results related to these operations have been classified as “discontinued operations” on the accompanying unaudited consolidated balance sheets and statements of operations for all periods presented. Unless otherwise indicated, information about the statements of operations that is presented in the notes to unaudited consolidated financial statements relates only to our continuing operations. See Note 13 for additional details.

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% equity investment in Bighorn Gas Gathering, L.L.C. (“Bighorn”), a Delaware limited liability company, and a 37.04% equity investment 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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 1 — Organization and Basis of Presentation (Continued)

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.

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, November 6, 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. We adopted SFAS No. 168 on July 1, 2009 and upon adoption all non-SEC accounting and reporting standards have been superseded, and all non-SEC accounting literature not included in the ASC is deemed non-authoritative. SFAS No. 168 did not change our disclosures or underlying accounting upon adoption. Where we refer to FASB ASC standards in our financial statements, we have also included citations to the corresponding pre-codification standards.

Subsequent Events

On July 1, 2009, we adopted FASB ASC 855, “Subsequent Events” (SFAS No. 165), 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 our policy, which 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 ASC 825 and Accounting Principles Board Opinion 28-1, “Interim Disclosures about Fair Value of Financial Instruments” (FASB Staff Position (“FSP”) 107-1), 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 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 FASB ASC 805, “Business Combinations” (SFAS No. 141 (Revised)), which revises how companies recognize and measure financial assets and liabilities acquired, goodwill acquired and the

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 2 — New Accounting Pronouncements (Continued)

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 FASB ASC 815-10, “Disclosures about Derivative Instruments and Hedging Activities — an amendment of FASB Statement No. 133” (SFAS No. 161). FASB ASC 815-10 establishes the disclosure requirements for derivative instruments and hedging activities and amends and expands the disclosure requirements of FASB ASC 815, “Accounting for Derivative Instruments and Hedging Activities,” (SFAS No. 133) 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 FASB ASC 815 and its related interpretations and how derivative instruments and related hedged items affect an entity’s financial position, financial performance and cash flows. FASB ASC 815-10 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 FASB ASC 815-10.

Useful Life of Intangible Assets

On January 1, 2009, we adopted FASB ASC 350-30, “Determination of the Useful Life of Intangible Assets” (FSP No. 142-3), 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 FASB ASC 350, “Goodwill and Other Intangible Assets,” (SFAS No. 142). This change is intended to improve consistency between the useful life of a recognized intangible asset under FASB ASC 350 and the period of expected cash flows used to measure the fair value of such assets under FASB ASC 350 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 FASB ASC 350-30 did not have a material impact on reported intangible assets or amortization expense.

Variable Interest Entities

In June 2009, the FASB finalized the amendment to FASB ASC 810-10 “Amending FASB interpretation No. 46(R)” (SFAS No. 167), which provides guidance in determining whether an enterprise is the primary beneficiary of a variable interest entity (“VIE”). The analysis required by this guidance identifies the primary beneficiary as the enterprise that has both the power to direct the activities of a VIE, and the obligation to absorb losses or the right to receive benefits of the entity. It also requires ongoing reassessments and eliminates the quantitative approach previously allowed for determining whether an entity is the primary beneficiary of a VIE. This amendment is effective for our fiscal year beginning January 1, 2010 and we do not anticipate its adoption to have a material impact on our consolidated cash flow, results of operations or financial position.

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. Upon adoption of FASB ASC 350-30 (FSP No. 142-3), initial costs of acquiring new intangible assets are amortized over the estimated useful life of the related tangible

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 3 — Intangible Assets (Continued)

assets. Any related renewals or extension costs of intangible assets are expensed over the contract term using the straight-line method. Amortization expense was $2,867,000 and $2,710,000 for the three months ended September 30, 2009 and 2008, respectively. Amortization expense was $8,374,000 and $8,011,000 for the nine months ended September 30, 2009 and 2008, respectively. Estimated aggregate amortization expense remaining for 2009 and each of the five succeeding fiscal years is approximately: 2009 — $2,757,000; 2010 — $11,008,000; 2011 — $10,992,000; 2012 — $10,928,000; 2013 — $10,798,000 and 2014 — $10,653,000.

Intangible assets consisted of the following (in thousands):


	September 30,			December 31,
	2009			2008

Rights-of-way and easements, at cost	$	114,925		$	113,169
Less accumulated amortization for rights-of-way and easements		(17,075	)		(11,919	)
Contracts		107,916			107,916
Less accumulated amortization for contracts		(17,874	)		(14,901	)
Customer relationships		4,864			4,864
Less accumulated amortization for customer relationships		(914	)		(689	)

Intangible assets, net	$	191,842		$	198,440

As of September 30, 2009, the weighted average amortization period for all of our intangible assets was 20 years. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 22 years, 19 years and 13 years, respectively, as of September 30, 2009. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 23 years, 20 years and 14 years, respectively, as of September 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 any debt service obligations. Our investments in unconsolidated affiliates totaled $627,068,000 as of September 30, 2009. As of September 30, 2009, our investments in Bighorn, Fort Union, Southern Dome and Webb Duval were carried at $516,631,000 more than our share of the underlying net assets of each investment. To the extent that we attribute all or a portion of any excess cost amount to higher fair values at the time of our acquisition of interest in these entities, we amortize such excess cost as a reduction in equity earnings in a manner similar to depreciation.

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 as of and for the nine months ended September 30, 2009 is as follows (in thousands):


	Bighorn			Fort Union			Southern Dome			Webb Duval

Operating revenue	$	27,885		$	47,100		$	12,961		$	1,597
Operating expenses		(11,404	)		(5,525	)		(10,818	)		(1,293	)
Depreciation and amortization		(3,939	)		(5,977	)		(643	)		(592	)
Interest income (expense) and other		6			(2,965	)		6			—

Net income (loss)		12,548			32,633			1,506			(288	)
Ownership %		51	%		37.04	%		69.5	%		62.5	%

		6,399			12,087			1,047			(180	)
Priority allocation of earnings and other		540			(286	)		—			—
Copano’s share of management fees charged		495			63			130			103
Amortization of difference between the carried investment and the underlying equity in net assets		(9,586	)		(4,817	)		(7	)		15

Equity in (loss) earnings from unconsolidated affiliates	$	(2,152	)	$	7,047		$	1,170		$	(62	)

Distributions	$	8,344		$	10,316		$	2,016		$	767

Current assets	$	10,939		$	12,048		$	2,855		$	409
Noncurrent assets		98,678			211,859			15,753			6,379
Current liabilities		(2,145	)		(19,751	)		(3,901	)		(843	)
Noncurrent liabilities		—			(91,654	)		—			(57	)

Net assets	$	107,472		$	112,502		$	14,707		$	5,888

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 nine months ended September 30, 2008 is as follows (in thousands):


	Bighorn			Fort Union			Southern Dome			Webb Duval

Operating revenue	$	25,959		$	37,904		$	26,612		$	2,556
Operating expenses		(10,038	)		(3,058	)		(21,936	)		(729	)
Depreciation and amortization		(3,194	)		(3,983	)		(555	)		(582	)
Interest income (expense) and other		72			(4,388	)		5			19

Net income		12,799			26,475			4,126			1,264
Ownership %		51	%		37.04	%		69.5	%		62.5	%

		6,527			9,806			2,868			790
Priority allocation of earnings and other		407			225			—			—
Copano’s share of management fees charged		181			26			130			101
Amortization of difference between the carried investment and the underlying equity in net assets		(8,999	)		(4,817	)		(7	)		16

Equity in (loss) earnings from unconsolidated affiliates	$	(1,884	)	$	5,240		$	2,991		$	907

Distributions	$	8,247		$	7,334		$	3,579		$	1,125

Note 5 — Long-Term Debt

A summary of our debt follows (in thousands):


	September 30,		December 31,
	2009		2008

Long-term debt:
Credit Facility	$	260,000	$	220,000
Senior Notes:
8.125% senior notes due 2016		332,665		332,665
Unamortized bond premium-senior notes due 2016		647		704
7.75% senior notes due 2018		249,525		267,750

Total Senior Notes		582,837		601,119

Total	$	842,837	$	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 September 30, 2009, we had $260 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 September 30, 2009 and 2008, we had no letters of credit outstanding.

The effective average interest rate on borrowings under the Credit Facility for the nine months ended September 30, 2009 and 2008 was 4.8% and 6.7%, 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 $6,245,000 and $9,010,000 for the nine months ended September 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 September 30, 2009, the unamortized portion of debt issue costs totaled $6,545,000.

The Credit Facility contains covenants (some of which require that we make 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 September 30, 2009, our ratio of EBITDA to interest expense was 3.41x, and our ratio of total debt to EBITDA was 3.99x. Based on our ratio of total debt to EBITDA, our remaining available borrowing capacity under the Credit Facility as of September 30, 2009 was approximately $290 million. If we failed to comply with the financial or other covenants under our Credit Facility 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 covenants under the Credit Facility as of September 30, 2009.

Senior Notes

8.125% Senior Notes Due 2016. At September 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 $20,857,000 and $21,950,000 for the nine months ended September 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 September 30, 2009, the unamortized portion of debt issue costs totaled $5,489,000.

7.75% Senior Notes Due 2018. At September 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 $15,463,000 and $9,028,000 for the nine months ended September 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 September 30, 2009, the unamortized portion of debt issue costs totaled $4,716,000.

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 September 30, 2009, our ratio of EBITDA to fixed charges was 3.28x.

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

Condensed consolidating financial information for Copano and its wholly owned subsidiaries is presented below.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long Term Debt (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS


	September 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	$	4,460		$	—		$	30,918		$	—	$	—		$	35,378		$	20,417		$	—		$	43,267		$	—	$	—		$	63,684
Accounts receivable, net		28			—			81,935			—		—			81,963			1			—			96,027			—		—			96,028
Intercompany receivable		47,328			(1	)		(47,327	)		—		—			—			110,551			—			(110,551	)		—		—			—
Risk management assets		—			—			47,128			—		—			47,128			—			—			76,440			—		—			76,440
Prepayments and other current assets		1,927			—			1,761			—		—			3,688			911			—			3,980			—		—			4,891
Discontinued operations		—			—			5,608			—		—			5,608			—			—			5,465			—		—			5,465

Total current assets		53,743			(1	)		120,023			—		—			173,765			131,880			—			114,628			—		—			246,508

Property, plant and equipment, net		106			—			834,650			—		—			834,756			136			—			818,963			—		—			819,099
Intangible assets, net		—			—			191,842			—		—			191,842			—			—			198,440			—		—			198,440
Investment in unconsolidated affiliates		—			—			627,068			627,068		(627,068	)		627,068			—			—			640,598			640,598		(640,598	)		640,598
Investment in consolidated subsidiaries		1,694,001			—			—			—		(1,694,001	)		—			1,723,814			—			—			—		(1,723,814	)		—
Escrow cash		—			—			1,858			—		—			1,858			—			—			1,858			—		—			1,858
Risk management assets		—			—			31,346			—		—			31,346			—			—			82,892			—		—			82,892
Other assets, net		16,749			—			5,175			—		—			21,924			19,809			—			4,461			—		—			24,270

Total assets	$	1,764,599		$	(1	)	$	1,811,962		$	627,068	$	(2,321,069	)	$	1,882,559		$	1,875,639		$	—		$	1,861,840		$	640,598	$	(2,364,412	)	$	2,013,665


LIABILITIES AND MEMBERS’/PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	21		$	—		$	89,264		$	—	$	—		$	89,285		$	2		$	—		$	103,847		$	—	$	—		$	103,849
Accrued interest		8,828			—			721			—		—			9,549			11,878			—			26			—		—			11,904
Accrued tax liability		495			—			—			—		—			495			784			—			—			—		—			784
Risk management liabilities		—			—			8,019			—		—			8,019			—			—			6,272			—		—			6,272
Other current liabilities		2,266			—			7,956			—		—			10,222			1,731			—			15,056			—		—			16,787
Discontinued liabilities		—			—			384			—		—			384			—			—			—			—		—			—

Total current liabilities		11,610			—			106,344			—		—			117,954			14,395			—			125,201			—		—			139,596

Long-term debt		842,837			—			—			—		—			842,837			821,119			—			—			—		—			821,119
Deferred tax provision		2,256			—			—			—		—			2,256			1,718			—			—			—		—			1,718
Risk management and other noncurrent liabilities		350			—			11,616			—		—			11,966			449			—			12,825			—		—			13,274
Members’/Partners’ capital:
Common units		878,994			—						—		—			878,994			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		41,168			1			1,203,367			602,828		(1,806,196	)		41,168			33,734			1			1,544,237			629,359		(2,173,597	)		33,734
Accumulated (deficit) earnings		(133,900	)		(2	)		481,805			24,240		(506,043	)		(133,900	)		(54,696	)		(1	)		111,951			11,239		(123,189	)		(54,696	)
Accumulated other comprehensive income (loss)		8,830			—			8,830			—		(8,830	)		8,830			67,626			—			67,626			—		(67,626	)		67,626

		907,546			(1	)		1,694,002			627,068		(2,321,069	)		907,546			1,037,958			—			1,723,814			640,598		(2,364,412	)		1,037,958

Total liabilities and members’/partners’ capital	$	1,764,599		$	(1	)	$	1,811,962		$	627,068	$	(2,321,069	)	$	1,882,559		$	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 September 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	$	—		$	—	$	66,747		$	—		$	—		$	66,747		$	—		$	—	$	204,187		$	—		$	—		$	204,187
Natural gas liquids sales		—			—		99,098			—			—			99,098			—			—		174,867			—			—			174,867
Transportation, compression and processing fees		—			—		13,926			—			—			13,926			—			—		13,772			—			—			13,772
Condensate and other		—			—		9,760			—			—			9,760			—			—		10,044			—			—			10,044

Total revenue		—			—		189,531			—			—			189,531			—			—		402,870			—			—			402,870

Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		129,617			—			—			129,617			—			—		332,346			—			—			332,346
Transportation		—			—		6,484			—			—			6,484			—			—		9,151			—			—			9,151
Operations and maintenance		—			—		13,202			—			—			13,202			(374	)		—		15,585			—			—			15,211
Depreciation and amortization		10			—		14,565			—			—			14,575			11			—		12,689			—			—			12,700
General and administrative		4,250			—		4,950			—			—			9,200			6,400			—		4,642			—			—			11,042
Taxes other than income		—			—		836			—			—			836			—			—		723			—			—			723
Equity in (earnings) loss from unconsolidated affiliates		—			—		(2,529	)		(2,529	)		2,529			(2,529	)		—			—		(2,170	)		(2,170	)		2,170			(2,170	)

Total costs and expenses		4,260			—		167,125			(2,529	)		2,529			171,385			6,037			—		372,966			(2,170	)		2,170			379,003

Operating (loss) income		(4,260	)		—		22,406			2,529			(2,529	)		18,146			(6,037	)		—		29,904			2,170			(2,170	)		23,867
Interest and other income		—			—		1,065			—			—			1,065			16			—		341			—			—			357
Interest and other financing costs		(13,364	)		—		(2,076	)		—			—			(15,440	)		(14,354	)		—		(1,116	)		—			—			(15,470	)

(Loss) income before income taxes, discontinued operations and equity in earnings from consolidated subsidiaries		(17,624	)		—		21,395			2,529			(2,529	)		3,771			(20,375	)		—		29,129			2,170			(2,170	)		8,754
Provision for income taxes		(304	)		—		—			—			—			(304	)		(197	)		—		—			—			—			(197	)

(Loss) income before discontinued operations and equity in earnings from consolidated subsidiaries		(17,928	)		—		21,395			2,529			(2,529	)		3,467			(20,572	)		—		29,129			2,170			(2,170	)		8,557
Discontinued operations, net of tax		—			—		262			—			—			262			—			—		166			—			—			166

Loss) income before equity in earnings from consolidated subsidiaries		(17,928	)		—		21,657			2,529			(2,529	)		3,729			(20,572	)				29,295			2,170			(2,170	)		8,723
Equity in earnings (loss) from consolidated subsidiaries		21,657			—		—			—			(21,657	)		—			29,295			—		—			—			(29,295	)		—

Net income (loss)	$	3,729		$	—	$	21,657		$	2,529		$	(24,186	)	$	3,729		$	8,723		$	—	$	29,295		$	2,170		$	(31,465	)	$	8,723

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long Term Debt (Continued)


	Nine Months Ended September 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	$	—		$	—	$	226,243		$	—		$	—		$	226,243		$	—		$	—	$	620,074		$	—		$	—		$	620,074
Natural gas liquids sales		—			—		271,392			—			—			271,392			—			—		507,979			—			—			507,979
Transportation, compression and processing fees		—			—		42,838			—			—			42,838			—			—		42,896			—			—			42,896
Condensate and other		—			—		30,319			—			—			30,319			—			—		36,582			—			—			36,582

Total revenue		—			—		570,792			—			—			570,792			—			—		1,207,531			—			—			1,207,531

Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		395,114			—			—			395,114			—			—		999,580			—			—			999,580
Transportation		—			—		18,211			—			—			18,211			—			—		15,688			—			—			15,688
Operations and maintenance		—			—		38,764			—			—			38,764			690			—		39,080			—			—			39,770
Depreciation and amortization		30			—		41,041			—			—			41,071			34			—		36,895			—			—			36,929
General and administrative		14,169			—		15,077			—			—			29,246			19,823			—		14,005			—			—			33,828
Taxes other than income		—			—		2,349			—			—			2,349			—			—		2,193			—			—			2,193
Equity in (earnings) loss from unconsolidated affiliates		—			—		(6,112	)		(6,112	)		6,112			(6,112	)		—			—		(7,354	)		(7,354	)		7,354			(7,354	)

Total costs and expenses		14,199			—		504,444			(6,112	)		6,112			518,643			20,547			—		1,100,087			(7,354	)		7,354			1,120,634

Operating (loss) income		(14,199	)		—		66,348			6,112			(6,112	)		52,149			(20,547	)		—		107,444			7,354			(7,354	)		86,897
Interest and other income		—			—		1,119			—			—			1,119			40			—		1,051			—			—			1,091
Gain on retirement of unsecured debt		3,939			—		—			—			—			3,939			—			—		—			—			—			—
Interest and other financing costs		(39,583	)		—		(2,306	)		—			—			(41,889	)		(37,727	)		—		(5,212	)		—			—			(42,939	)

(Loss) income before income taxes, discontinued operations and equity in earnings from consolidated subsidiaries		(49,843	)		—		65,161			6,112			(6,112	)		15,318			(58,234	)		—		103,283			7,354			(7,354	)		45,049
Provision for income taxes		(1,039	)		—		—			—			—			(1,039	)		(846	)		—		—			—			—			(846	)

(Loss) income before discontinued operations and equity in earnings from consolidated subsidiaries		(50,882	)		—		65,161			6,112			(6,112	)		14,279			(59,080	)		—		103,283			7,354			(7,354	)		44,203
Discontinued operations, net of tax		—			—		1,393			—			—			1,393			—			—		2,224			—			—			2,224

Loss) income before equity in earnings from consolidated subsidiaries		(50,882	)		—		66,554			6,112			(6,112	)		15,672			(59,080	)		—		105,507			7,354			(7,354	)		46,427
Equity in earnings (loss) from consolidated subsidiaries		66,554			—		—			—			(66,554	)		—			105,507			—		—			—			(105,507	)		—

Net income (loss)	$	15,672		$	—	$	66,554		$	6,112		$	(72,666	)	$	15,672		$	46,427		$	—	$	105,507		$	7,354		$	(112,861	)	$	46,427

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


	Nine Months Ended September 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	$	14,822		$	—	$	85,927		$	18,333		$	(18,333	)	$	100,749		$	(115,305	)	$	—	$	216,526		$	18,387		$	(18,387	)	$	101,221

Cash Flows From Investing Activities:
Net cash provided by (used in) investing activities		37,570			—		(60,706	)		(49	)		(37,521	)		(60,706	)		65,010			—		(146,825	)		(23,652	)		(41,358	)		(146,825	)

Cash Flows From Financing Activities:
Net cash provided by (used in) financing activities		(68,349	)		—		(37,570	)		3,240			34,330			(68,349	)		146,764			—		(65,010	)		25,623			39,387			146,764

Net (decrease) increase in cash and cash equivalents		(15,957	)		—		(12,349	)		21,524			(21,524	)		(28,306	)		96,469			—		4,691			20,358			(20,358	)		101,160
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	$	4,460		$	—	$	30,918		$	51,736		$	(51,736	)	$	35,378		$	106,487		$	—	$	67,338		$	24,740		$	(24,740	)	$	173,825

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 September 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 payment of our common unit distribution with respect to the fourth quarter of 2009. 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
September 30, 2009	$0.5750	October 14, 2009	November 2, 2009	November 12, 2009	$31,860,000

Accounting for Equity-Based Compensation

We use FASB ASC 718 (SFAS No. 123(R)) to account for equity-based compensation expense related to awards issued under our long-term incentive plan (“LTIP”) discussed below. As of September 30, 2009, the number of units available for grant under our LTIP totaled 1,769,726, of which up 1,160,198 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 $1,106,000 and $1,299,000 related to the amortization of restricted common units outstanding during the nine months ended September 30, 2009 and 2008, respectively.

A summary of restricted common unit activity for the nine months ended September 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		(56,922	)		20.83
Forfeited		(5,326	)		27.80

Outstanding at end of period		107,521		$	22.88

As of September 30, 2009, unrecognized compensation costs related to outstanding restricted common units totaled $1,626,000. The expense is expected to be recognized over an approximate weighted average period of one and a half years. The total fair value of restricted common units that vested during the three months ended September 30, 2009 was $1,186,000.

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 $3,485,000 and $1,686,000 related to the amortization of phantom units outstanding during the nine months ended September 30, 2009 and 2008, respectively.

A summary of phantom unit activity for the nine months ended September 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		(39,749	)		38.56
Forfeited		(70,659	)		28.80

Outstanding at end of period		691,202		$	28.61

As of September 30, 2009, unrecognized compensation expense related to outstanding phantom units totaled $17,661,000. 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 $671,000 and $749,000 related to unit options, net of anticipated forfeitures, for the nine months ended September 30, 2009 and 2008, respectively.

A summary of unit option activity for the nine months ended September 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		33,000			14.89
Exercised		(14,788	)		10.41
Cancelled		(14,264	)		7.69
Forfeited		(48,124	)		28.19

Outstanding at end of period		1,366,830		$	23.51

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 common 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.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 6 — Members’ Capital and Distributions (Continued)


	Nine Months
	Ended September 30,
	2009			2008

Weighted average exercise price		$14.89			$33.76
Expected volatility		29.76%-32.25	%		19.96%-20.72	%
Distribution yield		6.68%-6.69	%		6.18%-6.28	%
Risk-free interest rate		1.71%-3.28	%		2.71%-3.94	%
Expected term (in years)		6.5			6.5
Weighted average grant-date fair value of options granted		$2.07			$3.08
Total intrinsic value of options exercised		$91,000			$990,000

As of September 30, 2009, unrecognized compensation costs related to outstanding unit options totaled $1,701,000. 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 $214,000 and $0 related to UARs, net of anticipated forfeitures, for the nine months ended September 30, 2009 and 2008, respectively.

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


	Number of
	Units			Weighted
	Underlying			Average
	UARs			Exercise Price

Outstanding at beginning of year		—		$	—
Granted		298,000			15.09
Forfeited		(15,100	)		15.09

Outstanding at end of period		282,900		$	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 common 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.


	Nine Months Ended
	September 30, 2009

Weighted average exercise price		$15.09
Expected volatility		30.85%-64.76	%
Distribution yield		6.76%-8.47	%
Risk-free interest rate		0.90%-2.99	%
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 September 30, 2009, unrecognized compensation costs related to outstanding UARs totaled $600,000. The expense is expected to be recognized over a weighted average period of approximately three years.

Unit Awards. 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 nine months ended September 30, 2009, we

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 6 — Members’ Capital and Distributions (Continued)

granted 142,433 unit awards under our LTIP with a weighted average fair value of $15.05 to settle our Management Incentive Compensation Plan (“MICP”) and Employee Incentive Compensation Program (“EICP”) obligations.

Since FASB ASC 480 (SFAS No. 150), “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, we classify equity awards issued to settle EICP and the MICP obligations as liability awards. As of September 30, 2009, we accrued $484,000 and $667,000 for the third quarter 2009 EICP bonuses and an estimate of the 2009 MICP incentive bonuses, respectively.

As of September 30, 2009, the estimated unrecognized compensation costs related to outstanding liability awards totaled $548,000 and $225,000 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 FASB ASC 260, “Earnings Per Share” (SFAS No. 128). 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				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008

Net income available — basic and diluted	$	3,729	$	8,723	$	15,672	$	46,427

Basic weighted average units		54,565		47,868		54,313		47,640
Dilutive weighted average units⁽¹⁾⁽²⁾		58,036		57,939		57,953		57,891
Basic net income per unit:
Income per unit from continuing operations	$	0.06	$	0.18	$	0.26	$	0.93
Income per unit from discontinued operations		0.01		0.00		0.03		0.04

Net income per unit	$	0.07	$	0.18	$	0.29	$	0.97

Diluted net income per unit:
Income per unit from continuing operations⁽¹⁾⁽²⁾	$	0.06	$	0.15	$	0.25	$	0.76
Income per unit from discontinued operations⁽¹⁾⁽²⁾		0.00		0.00		0.02		0.04

Net income per unit	$	0.06	$	0.15	$	0.27	$	0.80

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 7 — Net Income Per Unit (Continued)


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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
	(In thousands)

Employee options		114		356		93		415
Unit appreciation rights		—		—		—		—
Restricted units		15		63		5		62
Phantom units		33		18		58		23
Contingent incentive plan unit awards		63		—		63		—
Class C units		—		790		175		905
Class D units		3,246		3,246		3,246		3,246
Class E units		—		5,599		—		5,599


(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 Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
			(In thousands)

Employee options		1,253		1,061		1,273		1,002
Unit appreciation rights		283		—		283		—
Restricted units		93		108		102		109
Phantom units		658		574		633		568

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 September 30, 2009 and 2008, we reimbursed Copano Operations $695,000 and $796,000, respectively, for administrative and operating costs, including payroll and benefits expense for certain of our field and administrative personnel. For the nine months ended September 30, 2009 and 2008, we reimbursed Copano Operations $1,981,000 and $2,476,000, 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 September 30, 2009, amounts payable by us to Copano Operations were $14,000. 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.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8 — Related Party Transactions (Continued)

Our management believes that the terms and provisions of our related party agreements are fair to us; however, we cannot be certain that such agreements and services have terms as favorable to us as we could obtain from unaffiliated third parties.

Natural Gas and Related Transactions

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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008

Affiliates of Mr. Eckel:
Natural gas sales⁽¹⁾	$	—	$	29	$	1	$	103
Gathering and compression services⁽²⁾		5		3		16		17
Natural gas purchases⁽³⁾		183		304		748		1,018
Payable by us as of September 30, 2009⁽⁴⁾						47
Webb Duval:
Natural gas sales⁽¹⁾		209		590		804		590
Natural gas purchases⁽³⁾		87		313		320		1,416
Transportation costs⁽⁵⁾		77		89		260		291
Management fees⁽⁶⁾		56		55		166		162
Reimbursable costs⁽⁶⁾		158		171		458		494
Payable to us as of September 30, 2009⁽⁷⁾						667
Payable by us as of September 30, 2009⁽⁴⁾						6
Southern Dome:
Management fees⁽⁶⁾		63		63		188		188
Reimbursable costs⁽⁶⁾		107		157		262		346
Payable to us as of September 30, 2009⁽⁷⁾						484
Bighorn:
Gathering costs⁽⁵⁾		65		144		286		460
Compressor rental fees⁽⁸⁾		399		—		564		—
Management fees⁽⁶⁾		135		68		406		205
Reimbursable costs⁽⁶⁾		597		779		1,760		1,454
Payable to us as of September 30, 2009⁽⁷⁾						1,173
Payable by us as of September 30, 2009⁽⁴⁾						46
Fort Union:
Gathering costs⁽⁵⁾		2,054		2,213		6,093		6,319
Treating costs⁽³⁾		127		276		461		627
Management fees⁽⁶⁾		57		24		170		71
Reimbursable costs⁽⁶⁾		40		—		207		—
Payable to us as of September 30, 2009⁽⁷⁾						59
Payable by us as of September 30, 2009⁽⁴⁾						40
Other:
Natural gas sales⁽¹⁾		70		142		167		319
Condensate and other		—		27		—		27
Payable to us as of September 30, 2009⁽⁷⁾						67

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 8 — Related Party Transactions (Continued)


(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.

(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 expenses 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.

Other Transactions

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 $587,000 and $1,339,000 for the three months ended September 30, 2009 and 2008, respectively, and $2,721,000 and $4,680,000 for the nine months ended September 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. Our management believes that the terms and provisions of our related party agreements are fair to us; however, we cannot be certain that such agreements and services have terms as favorable to us as we could obtain from unaffiliated third parties.

Note 9 — Commitments and Contingencies

Commitments

For the three months ended September 30, 2009 and 2008, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $1,455,000 and $1,997,000, respectively. For the nine months ended September 30, 2009 and 2008, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $6,041,000 and $5,085,000, respectively.

We have both fixed and variable quantity contractual commitments arising in the ordinary course of our natural gas marketing activities. As of September 30, 2009, we had fixed contractual commitments to purchase 486,000 million British thermal units (“MMBtu”) of natural gas in October 2009. As of September 30, 2009, we had fixed contractual commitments to sell 2,367,000 MMBtu of natural gas in October 2009. All of these contracts are based on index-related market pricing. Using index-related market prices as of September 30, 2009, total commitments to purchase natural gas related to such agreements equaled $1,774,000 and total commitments to sell natural gas under such agreements equaled $8,452,000. 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 September 2009, natural gas volumes purchased under such contracts equaled 10,299,093 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 September 2009, natural gas volumes sold under such contracts equaled 4,765,000 MMBtu.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9 — Commitments and Contingencies (Continued)

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 are obligated to pay approximately $2,605,000 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 $2,231,000 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 commitments, which expire in November 2009 and November 2017, to third parties for the duration of the obligation.

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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 9 — Commitments and Contingencies (Continued)

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.

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 November 6, 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 2010.

Note 10 — Supplemental Disclosures to the Statements of Cash Flows


	Nine Months Ended
	September 30,
	2009		2008
	(In thousands)

Cash payments for interest, net of $2,982,000 and $2,261,000 capitalized in 2009 and 2008, respectively	$	41,820	$	35,136
Cash payments for federal and state income taxes	$	790	$	492

We incurred a decrease in liabilities for investing activities that had not been paid as of September 30, 2009 of $9,908,000 and an increase in liabilities of $11,296,000 as of September 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. As of September 30, 2009 and 2008, we accrued $3,975,000 and $21,348,000, respectively, for capital expenditures that had not been paid and, therefore, these amounts are not included in investing activities for each respective period presented.

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,

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 11 — Financial Instruments (Continued)

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 FASB ASC 815 (SFAS No. 133) 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 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 nine months ended September 30, 2009, we recorded unrealized mark-to-market gains of $81,000 related to undesignated economic hedges, unrealized losses of $201,000 related to ineffectiveness on our risk management portfolio and reclassified into earnings a gain of $87,000 as a result of the discontinuance of cash flow hedge accounting for certain unwound derivatives.. During the nine months ended September 30, 2008, we recorded unrealized mark-to-market losses of $5,414,000, unrealized losses of $375,000 related to ineffectiveness on our risk management portfolio and reclassified into earnings losses of $492,000 as a result of the discontinuance of cash flow hedge accounting for certain unwound derivatives. As of September 30, 2009, we estimated that $10,852,000 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 September 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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 11 — Financial Instruments (Continued)

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

Purchased Mt. Belvieu Purity Ethane Put Spread Options


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

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		250
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.

Purchased Mt. Belvieu TET Propane Put Spread Options


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

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

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 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		—		—

Purchased Mt. Belvieu Non-TET Isobutane Put Spread Options


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

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		255	$	1.2275			400	⁽²⁾
2009		—		—	$	(1.7025	)		(320	)⁽³⁾
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		—			—


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

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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 11 — Financial Instruments (Continued)

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


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

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

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				Volumes
	(Per gallon)				(Bbls/d)
	Bought		Sold

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	⁽⁴⁾
2009	$	60.00		500
2010	$	55.00		1,000
2010	$	60.00		400
2011	$	55.00		1,000
2011	$	60.00		400
2011	$	77.00		700
2011	$	79.00		400	⁽⁵⁾
2012	$	79.00		300


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

(5)		Purchased in October 2009.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 11 — Financial Instruments (Continued)

Purchased WTI Crude Oil Put Spread Options


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

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 using interest rate swaps, which allow us to convert a portion of our variable rate debt into fixed rate debt. As of September 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 September 30, 2009 were designated as cash flow hedges.

For the nine months ended September 30, 2009, interest and other financing costs on the consolidated statement of operations include unrealized mark-to-market gains of $1,563,000 on undesignated interest rate swaps and no ineffectiveness on designated interest rate swaps. For the nine months ended September 30, 2009, we paid $3,869,000 in settlement of expired positions. For the nine months ended September 30, 2008, interest and other financing costs on the consolidated statement of operations includes unrealized mark-to-market losses of $3,713,000 on undesignated interest rate swaps and unrealized gains of $17,000 on designated interest rate swaps. For the nine months ended September 30, 2008, we paid $1,516,000 in settlement of expired positions.

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

We recognize the fair value of our assets and liabilities that require periodic re-measurement as necessary based upon the requirements of FASB ASC 820. 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 FASB ASC 820 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 FASB ASC 820 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 FASB ASC 820, 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)
	September 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)	$	—	$	—		$	47,128	$	47,128		$	—	$	—		$	76,440		$	76,440
Short-term — Not designated^(b)		—		—			—		—			—		—			—			—
Long-term — Designated^(c)		—		—			29,985		29,985			—		—			81,192			81,192
Long-term — Not designated^(c)		—		—			1,361		1,361			—		—			1,700			1,700

Total	$	—	$	—		$	78,474	$	78,474		$	—	$	—		$	159,332		$	159,332

Liabilities
Commodity derivatives:
Short-term — Designated^(d)	$	—	$	—		$	2,010	$	2,010		$	—	$	—		$	—		$	—
Short-term — Not designated^(d)		—		—			587		587			—		—			2,308			2,308
Long-term — Designated^(e)		—		—			5,656		5,656			—		—			4,347			4,347
Interest rate derivatives:
Short-term — Designated^(d)		—		—			—		—			—		302			—			302
Short-term — Not designated^(d)		—		5,423			—		5,423			—		3,662			—			3,662
Long-term — Designated^(e)		—		—			—		—			—		854			—			854
Long-term — Not designated^(e)		—		4,043			—		4,043			—		6,288			—			6,288

Total	$	—	$	9,466		$	8,253	$	17,719		$	—	$	11,106		$	6,655		$	17,761

Total designated	$	—	$	—		$	69,447	$	69,447		$	—	$	(1,156	)	$	153,285		$	152,129

Total not designated	$	—	$	(9,466	)	$	774	$	(8,691	)	$	—	$	(9,950	)	$	(608	)	$	(10,558	)


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

(b)		Included on the consolidated balance sheets as a current asset 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 liability 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 CenterPoint 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						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008

Asset (liability) balance, beginning of period	$	72,040		$	(53,989	)	$	152,677		$	(48,407	)
Total gains (losses):
Non-cash amortization of option premium		(9,236	)		(8,425	)		(27,715	)		(24,482	)
Other amounts included in earnings		16,728			(6,051	)		62,060			(25,280	)
Included in accumulated other comprehensive loss		2,736			60,980			(58,873	)		35,632
Purchases		4,397			17,570			4,397			60,160
Settlements		(16,444	)		6,960			(62,325	)		19,422
Transfers in and/or out of Level 3		—			—			—			—

Asset (liability) balance, end of period	$	70,221		$	17,045		$	70,221		$	17,045

Change in unrealized losses (income) included in earnings relating to instruments still held as of end of period	$	395		$	1,538		$	38		$	(5,476	)

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 September 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 FASB ASC	in OCI on			from Accumulated			Excluded from
815 (SFAS 133) Cash Flow	Derivatives			OCI into Income			Effectiveness			Statement of Operations
Hedging Relationships	(Effective Portion)			(Effective Portion)			Testing)			Location

*Three Months Ended September 30, 2009*
Natural gas	$	(38	)	$	(98	)	$	9		Natural gas sales
Natural gas liquids		5,216			3,081			(52	)	Natural gas liquids sales
Crude oil		1,640			1,098			33		Condensate and other
Interest rate swaps		257			128			—		Interest and other financing costs

Total	$	7,075		$	4,209		$	(10	)

*Nine Months Ended September 30, 2009*
Natural gas	$	(2,160	)	$	(2,577	)	$	77		Natural gas sales
Natural gas liquids		(13,954	)		26,470			(89	)	Natural gas liquids sales
Crude oil		(7,830	)		11,036

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