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, 2010
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). Yes þ No o

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


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

(Do not check if a smaller reporting company)

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

There were 65,755,914 common units of Copano Energy, L.L.C. outstanding at November 1, 2010. 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, 2010 and December 31, 2009		3
		Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2010 and 2009		4
		Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2010 and 2009		5
		Unaudited Consolidated Statement of Members’ Capital and Comprehensive Income (Loss) for the Nine Months Ended September 30, 2010 and 2009		6
		Notes to Unaudited Consolidated Financial Statements		7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		38
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		58
	Item 4.	Controls and Procedures		60

PART II — OTHER INFORMATION
	Item 1.	Legal Proceedings		61
	Item 1A.	Risk Factors		61
	Item 6.	Exhibits		63
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT


Item 1.	*Financial Statements.*

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2010			2009
	(In thousands, except unit information)

ASSETS
Current assets:
Cash and cash equivalents	$	101,781		$	44,692
Accounts receivable, net		81,104			91,156
Risk management assets		19,438			36,615
Prepayments and other current assets		2,802			4,937

Total current assets		205,125			177,400

Property, plant and equipment, net		910,673			841,323
Intangible assets, net		183,893			190,376
Investments in unconsolidated affiliates		589,812			618,503
Escrow cash		1,859			1,858
Risk management assets		16,585			15,381
Other assets, net		19,198			22,571

Total assets	$	1,927,145		$	1,867,412


LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable	$	106,031		$	111,021
Accrued interest		8,698			11,921
Accrued tax liability		696			672
Risk management liabilities		7,392			9,671
Other current liabilities		16,749			9,358

Total current liabilities		139,566			142,643

Long term debt (includes $567 and $628 bond premium as of September 30, 2010 and December 31, 2009, respectively)		582,757			852,818
Deferred tax provision		1,842			1,862
Risk management and other noncurrent liabilities		6,130			10,063
Commitments and contingencies (Note 9)
Members’ capital:
Series A convertible preferred units, no par value, 10,327,022 units and 0 units issued and outstanding as of September 30, 2010 and December 31, 2009, respectively		292,781			—
Common units, no par value, 65,744,236 units and 54,670,029 units issued and outstanding as of September 30, 2010 and December 31, 2009, respectively		1,159,400			879,504
Class D units, no par value, 0 and 3,245,817 units issued and outstanding as of September 30, 2010 and December 31, 2009, respectively		—			112,454
Paid in capital		49,559			42,518
Accumulated deficit		(289,001	)		(158,267	)
Accumulated other comprehensive loss		(15,889	)		(16,183	)

		1,196,850			860,026

Total liabilities and members’ capital	$	1,927,145		$	1,867,412

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						Nine Months
	Ended September 30,						Ended September 30,
	2010			2009			2010			2009
	(In thousands, except per unit information)

Revenue:
Natural gas sales	$	87,524		$	66,747		$	292,559		$	226,243
Natural gas liquids sales		118,999			99,098			353,119			271,392
Transportation, compression and processing fees		17,909			13,926			47,539			42,838
Condensate and other		13,272			9,760			41,204			30,319

Total revenue		237,704			189,531			734,421			570,792

Costs and expenses:
Cost of natural gas and natural gas liquids⁽¹⁾		174,461			129,617			551,939			395,114
Transportation⁽¹⁾		5,340			6,484			16,619			18,211
Operations and maintenance		13,004			13,202			38,337			38,764
Depreciation and amortization		15,218			14,575			46,002			41,071
General and administrative		9,869			9,200			31,311			29,246
Taxes other than income		1,315			836			3,658			2,349
Equity in (earnings) loss from unconsolidated affiliates		(2,049	)		(2,529	)		19,788			(6,112	)

Total costs and expenses		217,158			171,385			707,654			518,643

Operating income		20,546			18,146			26,767			52,149
Other income (expense):
Interest and other income		15			1,065			59			1,119
Gain on retirement of unsecured debt		—			—			—			3,939
Interest and other financing costs		(12,943	)		(15,440	)		(41,239	)		(41,889	)

Income (loss) before income taxes and discontinued operations		7,618			3,771			(14,413	)		15,318
Provision for income taxes		(320	)		(304	)		(660	)		(1,039	)

Income (loss) from continuing operations		7,298			3,467			(15,073	)		14,279
Discontinued operations, net of tax (Note 13)		—			262			—			1,393

Net income (loss)		7,298			3,729			(15,073	)		15,672
Preferred unit distributions		(7,500	)		—			(7,500	)		—

Net (loss) income to common units	$	(202	)	$	3,729		$	(22,573	)	$	15,672

Basic net (loss) income per common unit:
(Loss) income per common unit from continuing operations	$	—		$	0.06		$	(0.36	)	$	0.26
Income per common unit from discontinued operations		—			0.01			—			0.03

Net (loss) income per common unit	$	—		$	0.07		$	(0.36	)	$	0.29

Weighted average number of common units		65,658			54,565			63,193			54,313

Diluted net (loss) income per common unit:
(Loss) income per common unit from continuing operations	$	—		$	0.06		$	(0.36	)	$	0.25
Income per common unit from discontinued operations		—			—			—			0.02

Net (loss) income per common unit	$	—		$	0.06		$	(0.36	)	$	0.27

Weighted average number of common units		65,658			58,036			63,193			57,953


(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,
	2010			2009
	(In thousands)

Cash Flows From Operating Activities:
Net (loss) income	$	(15,073	)	$	15,672
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization		46,002			41,628
Amortization of debt issue costs		2,773			3,060
Equity in loss (earnings) from unconsolidated affiliates		19,788			(6,112	)
Distributions from unconsolidated affiliates		16,999			18,333
Gain on retirement of unsecured debt		—			(3,939	)
Non-cash gain on risk management activities, net		(555	)		(1,443	)
Equity-based compensation		7,118			6,692
Deferred tax provision		(19	)		538
Other non-cash items		(458	)		202
Changes in assets and liabilities:
Accounts receivable		10,586			14,857
Prepayments and other current assets		2,135			1,196
Risk management activities		10,766			23,462
Accounts payable		(6,518	)		(12,034	)
Other current liabilities		945			(1,363	)

Net cash provided by operating activities		94,489			100,749

Cash Flows From Investing Activities:
Additions to property, plant and equipment		(101,265	)		(51,540	)
Additions to intangible assets		(2,259	)		(1,756	)
Acquisitions		—			(6,003	)
Investments in unconsolidated affiliates		(11,186	)		(3,240	)
Distributions from unconsolidated affiliates		2,555			3,191
Proceeds from sale of assets		279			—
Other		280			(1,358	)

Net cash used in investing activities		(111,596	)		(60,706	)

Cash Flows From Financing Activities:
Proceeds from long-term debt		80,000			50,000
Repayment of long-term debt		(350,000	)		(10,000	)
Retirement of unsecured debt		—			(14,286	)
Deferred financing costs		(995	)		—
Distributions to unitholders		(107,612	)		(94,217	)
Proceeds from issuance of Series A convertible preferred units, net of underwriting discounts and commissions of $8,935		291,065			—
Proceeds from public offering of common units, net of underwriting discounts and commissions of $7,223		164,786			—
Equity offering costs		(6,236	)		—
Proceeds from option exercises		3,188			154

Net cash provided by (used in) financing activities		74,196			(68,349	)

Net increase (decrease) in cash and cash equivalents		57,089			(28,306	)
Cash and cash equivalents, beginning of year		44,692			63,684

Cash and cash equivalents, end of period	$	101,781		$	35,378

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)


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

Balance, December 31, 2009		—	$	—			54,670	$	879,504			—	$	—		3,246		$	112,454		$	42,518	$	(158,267	)	$	(16,183	)	$	860,026		$	—
Conversion of Class D Units into common units		—		—			3,246		112,454			—		—		(3,246	)		(112,454	)		—		—			—			—			—
In-kind distributions		—		7,500			—		—			—		—		—			—			—		(7,500	)		—			—			—
Cash distributions to common unitholders		—		—			—		—			—		—		—			—			—		(108,161	)		—			(108,161	)		—
Issuance of units		10,327		300,000			7,446		172,008			—		—		—			—			—		—			—			472,008			—
Equity offering costs		—		(14,719	)		—		(7,754	)		—		—		—			—			—		—			—			(22,473	)		—
Equity-based compensation		—		—			382		3,188			—		—		—			—			7,041		—			—			10,229			—
Net loss		—		—			—		—			—		—		—			—			—		(15,073	)		—			(15,073	)		(15,073	)
Derivative settlements reclassified to income		—		—			—		—			—		—		—			—			—		—			(3,636	)		(3,636	)		(3,636	)
Unrealized gain-change in fair value of derivatives		—		—			—		—			—		—		—			—			—		—			3,930			3,930			3,930

Comprehensive loss																																$	(14,779	)

Balance, September 30, 2010		10,327	$	292,781			65,744	$	1,159,400			—	$	—		—		$	—		$	49,559	$	(289,001	)	$	(15,889	)	$	1,196,850


	Series A Preferred				Common				Class C						Class D						Accumulated			Accumulated						Total
	Number		Preferred		Number		Common		Number			Class C			Number		Class D		Paid-in		Earnings			Other 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	)		—		—		—		—			—			—			—
Cash distributions to common unitholders		—		—		—		—		—			—			—		—		—		(94,876	)		—			(94,876	)		—
Equity-based compensation		—		—		241		154		—			—			—		—		7,434		—			—			7,588			—
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

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 wellheads or designated points near producing wells and deliver these volumes to our processing plants, third-party processing plants, third-party pipelines, local distribution companies, power generation facilities and industrial consumers. Our processing plants take delivery of natural gas from our gathering systems as well as third-party pipelines. The natural gas is then treated as needed to remove contaminants and then conditioned or processed to extract mixed natural gas liquids (“NGLs”). After treating and processing or conditioning, we deliver the residue gas primarily to third-party pipelines through plant interconnects and sell the NGLs, in some cases after separating the NGLs into select component products, to third parties through our plant interconnects or our NGL pipelines. We refer to our operations (i) conducted through our subsidiaries operating in Oklahoma, including our crude oil pipeline which we sold in October 2009, 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 unaudited consolidated financial statements.

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 statements of operations for the three and nine months ended September 30, 2009. 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.

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. 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, as amended, for the year ended December 31, 2009.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 2 —	New Accounting Pronouncements

Fair Value Measurements

In January 2010, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2010-06, “Fair Value Measurements and Disclosures: Improving Disclosures about Fair Value Measurements,” which updates Accounting Standards Codification (“ASC”) 820-10 to require new disclosure of amounts transferred in and out of Level 1 and Level 2 of the fair value hierarchy and presentation of a reconciliation of changes in fair value amounts in the Level 3 fair value hierarchy on a gross basis rather than a net basis. Additionally, ASU 2010-06 requires greater disaggregation of the assets and liabilities for which fair value measurements are presented and requires expanded disclosure of the valuation techniques and inputs used for Level 2 and Level 3 fair value measurements. We implemented ASU 2010-06 on January 1, 2010. See Note 11 for required additional disclosures.


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 ASC 350-30, “Determination of the Useful Life of Intangible Assets” initial costs of acquiring new intangible assets are amortized over the estimated useful life of the related tangible assets. Any related renewals or extension costs of intangible assets are expensed over the contract term using the straight-line method. Amortization expense was $2,792,000 and $2,867,000 for the three months ended September 30, 2010 and 2009, respectively. Amortization expense was $8,354,000 and $8,374,000 for the nine months ended September 30, 2010 and 2009, respectively. Estimated aggregate amortization expense remaining for 2010 and each of the five succeeding fiscal years is approximately: 2010 — $2,799,000; 2011 — $11,167,000; 2012 — $11,101,000; 2013 — $10,927,000; 2014 — $10,764,000; and 2015 — $10,730,000.

Intangible assets consisted of the following:


	September 30,			December 31,
	2010			2009
	(In thousands)

Rights-of-way and easements, at cost	$	117,927		$	116,122
Less accumulated amortization for rights-of-way and easements		(21,890	)		(18,204	)
Contracts		107,916			107,916
Less accumulated amortization for contracts		(23,698	)		(19,330	)
Customer relationships		4,864			4,864
Less accumulated amortization for customer relationships		(1,226	)		(992	)

Intangible assets, net	$	183,893		$	190,376

As of September 30, 2010 and 2009, the weighted average amortization period for all of our intangible assets was 19 years and 20 years, respectively. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 21 years, 18 years and 12 years, respectively, as of September 30, 2010. 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.


Note 4 —	Investments in Unconsolidated Affiliates

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, a 37.04% equity

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4 — Investments in Unconsolidated Affiliates (Continued)

investment in Fort Union Gas Gathering, L.L.C. (“Fort Union”), a Delaware limited liability company and a 50% equity investment in Eagle Ford Gathering LLC (“Eagle Ford”), a Delaware limited liability company.

We received total distributions from our investments in unconsolidated affiliates of $6,564,000 and $19,554,000 for the three and nine months ended September 30, 2010, respectively, and $7,296,000 and $21,524,000 for the three and nine months ended September 30, 2009, respectively. We made cash contributions to our unconsolidated affiliates of $9,648,000 and $11,186,000 for the three and nine months ended September 30, 2010, respectively, and $466,000 and $3,240,000 for the three and nine months ended September 30, 2009, respectively.

No restrictions exist under Webb Duval’s, Southern Dome’s, Bighorn’s, or Eagle Ford’s partnership or operating agreements that limit these entities’ ability to pay distributions to their respective partners or members after consideration of their respective current and anticipated cash needs, including debt service obligations. Fort Union can distribute cash to its members only if its ratio of net operating cash flow to debt service is not less than 1.25 to 1.00 and it is not otherwise in default under its credit agreement. If Fort Union fails to comply with this covenant or otherwise defaults under its credit agreement, it would be prohibited from distributing cash. As of September 30, 2010, Fort Union is in compliance with all financial covenants.

We evaluate the carrying value of our investments in unconsolidated subsidiaries when indicators of impairment are present. As of September 30, 2010, the carrying value of our investments in unconsolidated subsidiaries did not indicate an impairment was present. During the three months ended June 30, 2010, we recorded a $25 million non-cash impairment charge relating to our investment in Bighorn primarily as a result of a continued weak Rocky Mountains pricing environment for natural gas, lack of drilling activity in Wyoming’s Powder River Basin and a downward shift in the Colorado Interstate Gas forward price curve.

The summarized financial information for our significant equity investments is as follows:


	As of and for the Nine Months Ended September 30,
	2010						2009
	Bighorn			Fort Union			Bighorn			Fort Union
	($ in thousands)

Operating revenue	$	23,793		$	42,852		$	27,885		$	47,100
Operating expenses		(8,904	)		(5,362	)		(11,404	)		(5,525	)
Depreciation and amortization		(3,887	)		(5,628	)		(3,939	)		(5,977	)
Interest income (expense) and other		77			(3,520	)		6			(2,965	)

Net income (loss)		11,079			28,342			12,548			32,633
Ownership %		51	%		37.04	%		51	%		37.04	%

		5,650			10,498			6,399			12,087
Priority allocation of earnings and other		379			—			540			(286	)
Copano’s share of management fees charged		213			66			495			63
Amortization of difference between the carried investment and the underlying equity in net assets and impairment		(33,899	)		(4,817	)		(9,586	)		(4,817	)

Equity in (loss) earnings from unconsolidated affiliates	$	(27,657	)	$	5,747		$	(2,152	)	$	7,047

Distributions	$	8,423		$	8,704		$	8,344		$	10,316

Current assets	$	6,188		$	14,424		$	10,939		$	12,048
Noncurrent assets		89,750			206,580			98,678			211,859
Current liabilities		(1,206	)		(19,949	)		(2,145	)		(19,751	)
Noncurrent liabilities		(257	)		(78,190	)		—			(91,654	)

Net assets	$	94,475		$	122,865		$	107,472		$	112,502

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 4 — Investments in Unconsolidated Affiliates (Continued)

The summarized financial information of our other unconsolidated investments is presented below in aggregate:


	As of and for the
	Nine Months Ended September 30,
	2010			2009
	(In thousands)

Operating revenue	$	24,112		$	15,901
Operating expenses		(18,149	)		(10,857	)
Depreciation and amortization		(1,137	)		(1,245	)
Other expense, net		(2,021	)		(2,286	)

Net income	$	2,805		$	1,513

Current assets	$	15,945		$	3,709
Noncurrent assets		43,610			22,340
Current liabilities		(21,080	)		(5,021	)
Noncurrent liabilities		(61	)		(58	)

Net assets	$	38,414		$	20,970

Our share of the equity in earnings from unconsolidated affiliates and distributions related to our other equity investments above was $2,122,000 and $2,427,000, respectively, for the nine months ended September 30, 2010, and $1,217,000 and $2,864,000, respectively, for the nine months ended September 30, 2009.


Note 5 —	Long-Term Debt


	September 30,		December 31,
	2010		2009
	(In thousands)

Long-term debt:
Credit Facility	$	—	$	270,000
Senior Notes:
8.125% senior unsecured notes due 2016		332,665		332,665
Unamortized bond premium-senior notes due 2016		567		628
7.75% senior unsecured notes due 2018		249,525		249,525

Total Senior Notes		582,757		582,818

Total	$	582,757	$	852,818

Senior Secured Revolving Credit Facility

As a result of using proceeds from our issuance of preferred units discussed in Note 6, on September 30, 2010, we had no 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 $50.0 million in standby letters of credit. As of September 30, 2010 and December 31, 2009, we had no letters of credit outstanding.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (Continued)

The effective average interest rate on borrowings under the Credit Facility for the nine months ended September 30, 2010 and 2009 was 7.74% and 4.8%, respectively, and the quarterly commitment fee on the unused portion of the Credit Facility for those periods was 0.25%. Interest and other financing costs related to the Credit Facility totaled $4,709,000 and $6,245,000 for the nine months ended September 30, 2010 and 2009, respectively. Costs incurred in connection with the establishment of this Credit Facility are being amortized over its term, and as of September 30, 2010, the unamortized portion of debt issue costs totaled $5,272,000.

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).

EBITDA for the purposes of the Credit Facility is our EBITDA with certain negotiated adjustments.

At September 30, 2010, our ratio of EBITDA to interest expense was 3.60x, and our ratio of total debt to EBITDA was 3.02x. Based on our current four-quarter EBITDA, as defined under the Credit Facility, we could borrow an additional $390 million before reaching our maximum total debt to EBITDA ratio of 5.0 to 1.0. 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 financial covenants under the Credit Facility as of September 30, 2010.

Senior Notes

8.125% Senior Notes Due 2016. At September 30, 2010, 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 $20,852,000 and $20,857,000 for the nine months ended September 30, 2010 and 2009, 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, 2010, the unamortized portion of debt issue costs totaled $4,633,000.

7.75% Senior Notes Due 2018. At September 30, 2010, the aggregate principal amount of 7.75% senior unsecured notes due 2018 (the “2018 Notes” and, together with the 2016 Notes, the “Senior Notes”) outstanding was $249,525,000.

Interest and other financing costs relating to the 2018 Notes totaled $14,912,000 and $15,463,000 for the nine months ended September 30, 2010 and 2009, 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, 2010, the unamortized portion of debt issue costs totaled $4,171,000.

General. The indentures governing our Senior Notes include an incurrence covenant which restricts 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. For the twelve months ended September 30, 2010, our ratio of EBITDA to fixed charges was 3.38x, which is in compliance with this incurrence covenant under the indentures governing our Senior Notes.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long Term Debt (Continued)

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


	September 30, 2010																	December 31, 2009
										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	$	47,853		$	—		$	53,928		$	—	$	—		$	101,781		$	3,861		$	—		$	40,831		$	—	$	—		$	44,692
Accounts receivable, net		4			—			81,100			—		—			81,104			29			—			91,127			—		—			91,156
Intercompany receivable		36,702			(1	)		(36,701	)		—		—			—			21,034			—			(21,034	)		—		—			—
Risk management assets		—			—			19,438			—		—			19,438			—			—			36,615			—		—			36,615
Prepayments and other current assets		1,595			—			1,207			—		—			2,802			3,610			—			1,327			—		—			4,937
Discontinued operations		—			—			—			—		—			—			—			—			—			—		—			—

Total current assets		86,154			(1	)		118,972			—		—			205,125			28,534			—			148,866			—		—			177,400

Property, plant and equipment, net		66			—			910,607			—		—			910,673			96			—			841,227			—		—			841,323
Intangible assets, net		—			—			183,893			—		—			183,893			—			—			190,376			—		—			190,376
Investment in unconsolidated affiliates		—			—			589,812			589,812		(589,812	)		589,812			—			—			618,503			618,503		(618,503	)		618,503
Investment in consolidated subsidiaries		1,695,065			—			—			—		(1,695,065	)		—			1,684,994			—			—			—		(1,684,994	)		—
Escrow cash		—			—			1,859			—		—			1,859			—			—			1,858			—		—			1,858
Risk management assets		—			—			16,585			—		—			16,585			—			—			15,381			—		—			15,381
Other assets, net		14,077			—			5,121			—		—			19,198			15,854			—			6,717			—		—			22,571

Total assets	$	1,795,362		$	(1	)	$	1,826,849		$	589,812	$	(2,284,877	)	$	1,927,145		$	1,729,478		$	—		$	1,822,928		$	618,503	$	(2,303,497	)	$	1,867,412


LIABILITIES AND MEMBERS’/PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	542		$	—		$	105,489		$	—	$	—		$	106,031		$	—		$	—		$	111,021		$	—	$	—		$	111,021
Accrued interest		8,698			—			—			—		—			8,698			11,146			—			775			—		—			11,921
Accrued tax liability		696			—			—			—		—			696			672			—			—			—		—			672
Risk management liabilities		—			—			7,392			—		—			7,392			—			—			9,671			—		—			9,671
Other current liabilities		3,793			—			12,956			—		—			16,749			2,637			—			6,721			—		—			9,358

Total current liabilities		13,729			—			125,837			—		—			139,566			14,455			—			128,188			—		—			142,643

Long-term debt		582,757			—			—			—		—			582,757			852,818			—			—			—		—			852,818
Deferred tax provision		1,807			—			35			—		—			1,842			1,862			—			—			—		—			1,862
Risk management and other noncurrent liabilities		219			—			5,911			—		—			6,130			317			—			9,746			—		—			10,063
Members’/Partners’ capital:
Series A convertible preferred units		292,781			—			—			—		—			292,781			—			—			—			—		—			—
Common units		1,159,400			—			—			—		—			1,159,400			879,504			—			—			—		—			879,504
Class D units		—			—			—			—		—			—			112,454			—			—			—		—			112,454
Paid-in capital		49,559			1			1,161,958			586,872		(1,748,831	)		49,559			42,518			1			1,191,268			595,775		(1,787,044	)		42,518
Accumulated (deficit) earnings		(289,001	)		(2	)		548,997			2,940		(551,935	)		(289,001	)		(158,267	)		(1	)		509,909			22,728		(532,636	)		(158,267	)
Other comprehensive (loss) income		(15,889	)		—			(15,889	)		—		15,889			(15,889	)		(16,183	)		—			(16,183	)		—		16,183			(16,183	)

		1,196,850			(1	)		1,695,066			589,812		(2,284,877	)		1,196,850			860,026			—			1,684,994			618,503		(2,303,497	)		860,026

Total liabilities and members’/partners’ capital	$	1,795,362		$	(1	)	$	1,826,849		$	589,812	$	(2,284,877	)	$	1,927,145		$	1,729,478		$	—		$	1,822,928		$	618,503	$	(2,303,497	)	$	1,867,412

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long Term Debt (Continued)


	Three Months Ended September 30,
	2010																	2009
									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	$	—		$	—	$	87,524		$	—		$	—		$	87,524		$	—		$	—	$	66,747		$	—		$	—		$	66,747
Natural gas liquids sales		—			—		118,999			—			—			118,999			—			—		99,098			—			—			99,098
Transportation, compression and processing fees		—			—		17,909			—			—			17,909			—			—		13,926			—			—			13,926
Condensate and other		—			—		13,272			—			—			13,272			—			—		9,760			—			—			9,760

Total revenue		—			—		237,704			—			—			237,704			—			—		189,531			—			—			189,531

Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		174,461			—			—			174,461			—			—		129,617			—			—			129,617
Transportation		—			—		5,340			—			—			5,340			—			—		6,484			—			—			6,484
Operations and maintenance		—			—		13,004			—			—			13,004			—			—		13,202			—			—			13,202
Depreciation and amortization		10			—		15,208			—			—			15,218			10			—		14,565			—			—			14,575
General and administrative		4,692			—		5,177			—			—			9,869			4,250			—		4,950			—			—			9,200
Taxes other than income		—			—		1,315			—			—			1,315			—			—		836			—			—			836
Equity in loss (earnings) from unconsolidated affiliates		—			—		(2,049	)		(2,049	)		2,049			(2,049	)		—			—		(2,529	)		(2,529	)		2,529			(2,529	)

Total costs and expenses		4,702			—		212,456			(2,049	)		2,049			217,158			4,260			—		167,125			(2,529	)		2,529			171,385

Operating (loss) income		(4,702	)		—		25,248			2,049			(2,049	)		20,546			(4,260	)		—		22,406			2,529			(2,529	)		18,146
Other income (expense):
Interest and other income		—			—		15			—			—			15			—			—		1,065			—			—			1,065
Interest and other financing costs		(11,725	)		—		(1,218	)		—			—			(12,943	)		(13,364	)		—		(2,076	)		—			—			(15,440	)

(Loss) income before income taxes, discontinued operations and equity in earnings from consolidated subsidiaries		(16,427	)		—		24,045			2,049			(2,049	)		7,618			(17,624	)		—		21,395			2,529			(2,529	)		3,771
Provision for income taxes		(285	)		—		(35	)		—			—			(320	)		(304	)		—		—			—			—			(304	)

(Loss) income before discontinued operations and equity in earnings from consolidated subsidiaries		(16,712	)		—		24,010			2,049			(2,049	)		7,298			(17,928	)		—		21,395			2,529			(2,529	)		3,467
Discontinued operations, net of tax		—			—		—			—			—			—			—			—		262			—			—			262

(Loss) income before equity earnings from consolidated subsidiaries		(16,712	)		—		24,010			2,049			(2,049	)		7,298			(17,928	)		—		21,657			2,529			(2,529	)		3,729
Equity in earnings from consolidated subsidiaries		24,010			—		—			—			(24,010	)		—			21,657			—		—			—			(21,657	)		—

Net income (loss)		7,298			—		24,010			2,049			(26,059	)		7,298			3,729			—		21,657			2,529			(24,186	)		3,729
Preferred unit distributions		(7,500	)		—		—			—			—			(7,500	)		—			—		—			—			—			—

Net (loss) income to common units	$	(202	)	$	—	$	24,010		$	2,049		$	(26,059	)	$	(202	)	$	3,729		$	—	$	21,657		$	2,529		$	(24,186	)	$	3,729

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,
	2010																	2009
									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	$	—		$	—	$	292,559		$	—		$	—		$	292,559		$	—		$	—	$	226,243		$	—		$	—		$	226,243
Natural gas liquids sales		—			—		353,119			—			—			353,119			—			—		271,392			—			—			271,392
Transportation, compression and processing fees		—			—		47,539			—			—			47,539			—			—		42,838			—			—			42,838
Condensate and other		—			—		41,204			—			—			41,204			—			—		30,319			—			—			30,319

Total revenue		—			—		734,421			—			—			734,421			—			—		570,792			—			—			570,792

Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		551,939			—			—			551,939			—			—		395,114			—			—			395,114
Transportation		—			—		16,619			—			—			16,619			—			—		18,211			—			—			18,211
Operations and maintenance		—			—		38,337			—			—			38,337			—			—		38,764			—			—			38,764
Depreciation and amortization		30			—		45,972			—			—			46,002			30			—		41,041			—			—			41,071
General and administrative		15,718			—		15,593			—			—			31,311			14,169			—		15,077			—			—			29,246
Taxes other than income		—			—		3,658			—			—			3,658			—			—		2,349			—			—			2,349
Equity in loss (earnings) from unconsolidated affiliates		—			—		19,788			19,788			(19,788	)		19,788			—			—		(6,112	)		(6,112	)		6,112			(6,112	)

Total costs and expenses		15,748			—		691,906			19,788			(19,788	)		707,654			14,199			—		504,444			(6,112	)		6,112			518,643

Operating (loss) income		(15,748	)		—		42,515			(19,788	)		19,788			26,767			(14,199	)		—		66,348			6,112			(6,112	)		52,149
Other income (expense):
Interest and other income		—			—		59			—			—			59			—			—		1,119			—			—			1,119
Gain on retirement of unsecured debt		—			—		—			—			—			—			3,939			—		—			—			—			3,939
Interest and other financing costs		(37,789	)		—		(3,450	)		—			—			(41,239	)		(39,583	)		—		(2,306	)		—			—			(41,889	)

(Loss) income before income taxes, discontinued operations and equity in earnings from consolidated subsidiaries		(53,537	)		—		39,124			(19,788	)		19,788			(14,413	)		(49,843	)		—		65,161			6,112			(6,112	)		15,318
Provision for income taxes		(625	)		—		(35	)		—			—			(660	)		(1,039	)		—		—			—			—			(1,039	)

(Loss) income before discontinued operations and equity in earnings from consolidated subsidiaries		(54,162	)		—		39,089			(19,788	)		19,788			(15,073	)		(50,882	)		—		65,161			6,112			(6,112	)		14,279
Discontinued operations, net of tax		—			—		—			—			—			—			—			—		1,393			—			—			1,393

(Loss) income before equity earnings from consolidated subsidiaries		(54,162	)		—		39,089			(19,788	)		19,788			(15,073	)		(50,882	)		—		66,554			6,112			(6,112	)		15,672
Equity in earnings from consolidated subsidiaries		39,089			—		—			—			(39,089	)		—			66,554			—		—			—			(66,554	)		—

Net (loss) income		(15,073	)		—		39,089			(19,788	)		(19,301	)		(15,073	)		15,672			—		66,554			6,112			(72,666	)		15,672
Preferred unit distributions		(7,500	)		—		—			—			—			(7,500	)		—			—		—			—			—			—

Net (loss) income to common units	$	(22,573	)	$	—	$	39,089		$	(19,788	)	$	(19,301	)	$	(22,573	)	$	15,672		$	—	$	66,554		$	6,112		$	(72,666	)	$	15,672

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,
	2010																		2009
										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 (used in) provided by operating activities	$	(63,627	)	$	—		$	158,116		$	16,999		$	(16,999	)	$	94,489		$	14,822		$	—	$	85,927		$	18,333		$	(18,333	)	$	100,749

Cash Flows From Investing Activities:
Additions to property, plant and equipment and intangibles		—			—			(103,524	)		—			—			(103,524	)		—			—		(59,299	)		—			—			(59,299	)
Investment in unconsolidated affiliates		—			—			(11,186	)		(11,186	)		11,186			(11,186	)		—			—		(3,240	)		(3,240	)		3,240			(3,240	)
Distributions from unconsolidated affiliates		—			—			2,555			2,555			(2,555	)		2,555			—			—		3,191			3,191			(3,191	)		3,191
Investment in consolidated affiliates		(61,832	)		1			—			—			61,831			—			(105	)		—		—			—			105			—
Distributions from consolidated affiliates		95,255			—			—			—			(95,255	)		—			37,675			—		—			—			(37,675	)		—
Proceeds from sale of assets		—			—			279			—			—			279			—			—		—			—			—			—
Other		—			—			280			—			—			280			—			—		(1,358	)		—			—			(1,358	)

Net cash provided by (used in) investing activities		33,423			1			(111,596	)		(8,631	)		(24,793	)		(111,596	)		37,570			—		(60,706	)		(49	)		(37,521	)		(60,706	)

Cash Flows From Financing Activities:
Proceeds from long-term debt		80,000			—			—			—			—			80,000			50,000			—		—			—			—			50,000
Repayments of long-term debt		(350,000	)		—			—			—			—			(350,000	)		(10,000	)		—		—			—			—			(10,000	)
Deferred financing costs		(995	)		—			—			—			—			(995	)		—			—		—			—			—			—
Retirement of unsecured debt		—			—			—			—			—			—			(14,286	)		—		—			—			—			(14,286	)
Distributions to unitholders		(107,612	)		—			—			—			—			(107,612	)		(94,217	)		—		—			—			—			(94,217	)
Equity offering of common units		164,786			—			—			—			—			164,786			—			—		—			—			—			—
Equity offering of common units-offering costs		(6,236	)		—			—			—			—			(6,236	)		—			—		—			—			—			—
Equity offering of Series A convertible preferred units		291,065			—			—			—			—			291,065			—			—		—			—			—			—
Contributions from parent		—			—			61,831			—			(61,831	)		—			—			—		105			—			(105	)		—
Distributions to parent		—			—			(95,255	)		—			95,255			—			—			—		(37,675	)		—			37,675			—
Other		3,188			—			—			11,186			(11,186	)		3,188			154			—		—			3,240			(3,240	)		154

Net cash provided by (used in) financing activities		74,196			—			(33,424	)		11,186			22,238			74,196			(68,349	)		—		(37,570	)		3,240			34,330			(68,349	)

Net increase (decrease) in cash and cash equivalents		43,992			1			13,096			19,554			(19,554	)		57,089			(15,957	)		—		(12,349	)		21,524			(21,524	)		(28,306	)
Cash and cash equivalents, beginning of year		3,861			(1	)		40,832			59,896			(59,896	)		44,692			20,417			—		43,267			30,212			(30,212	)		63,684

Cash and cash equivalents, end of period	$	47,853		$	—		$	53,928		$	79,450		$	(79,450	)	$	101,781		$	4,460		$	—	$	30,918		$	51,736		$	(51,736	)	$	35,378

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 6 —	Members’ Capital and Distributions

Series A Convertible Preferred Units

On July 21, 2010, we issued 10,327,022 Series A convertible preferred units (“Series A preferred units”) in a private placement to TPG Copenhagen, L.P. (“TPG”), an affiliate of TPG Capital, L.P. for gross proceeds of $300 million. The preferred units were priced at $29.05 per unit, a 10% premium to the 30-day volume-weighted average closing price of our common units on July 19, 2010, two trading days before the date we issued the preferred units. We used $180.0 million of the net proceeds to repay the outstanding balance under our Credit Facility and expect to use the remaining net proceeds to fund our expansion strategy in the Eagle Ford Shale resource play and other growth initiatives in Texas and Oklahoma.

The Series A preferred units are classified as permanent equity, as they do not meet the criteria of a liability within the scope of ASC 480-10 “Distinguishing Liabilities from Equity,” nor do they meet the criteria of the mezzanine level under ASC 815 “Accounting for Derivative Instruments and Hedging Activities.” Additionally, none of the identified embedded derivatives relating to the terms of the Series A preferred units requires bifurcation, as each embedded derivative was determined to be clearly and closely related to the host contract of the Series A preferred units under ASC 815-15 “Embedded Derivatives.” As discussed below, the distribution payment under the terms of the Series A preferred units is not discretionary during the first three years and, therefore, the commitment date was determined to be the date of original issuance under ASC 470-20-30 “Debt With Conversions and Other Options.” Further, the change of control provision under the agreement does not preclude the establishment of a commitment date, as it is outside the control of Copano and the Series A preferred unitholder.

Distributions. The Series A preferred units are senior to our common units with respect to rights to distributions. For the first three years after the date on which they were issued, the Series A preferred units are entitled to quarterly distributions in kind (paid in the form of additional Series A preferred units). In-kind distributions will equal $0.72625 per preferred unit per quarter (or 10% per year of the purchase price of a Series A preferred unit) divided by the $29.05 issue price. Beginning with the distribution for the quarter ending September 30, 2013, and through the distribution for the quarter ending June 30, 2016, we are entitled to elect whether to pay preferred distributions in cash, in kind or in a combination of both. For quarters ending after June 30, 2016, we will be obligated to pay preferred distributions in cash unless our available cash (after reserves established by our Board of Directors) is not sufficient to fund the distribution or we and the preferred unitholder agree that a distribution will be paid in kind. Cash distributions on the Series A preferred units will equal the greater of $0.72625 per preferred unit per quarter or the quarterly per-unit distribution paid to our common unitholders for the applicable quarter. In kind distributions for the three months ended September 30, 2010 totaled $7,500,000.

Voting Rights. Each Series A preferred unit entitles the holder to one vote. The Series A preferred units generally have voting rights identical to and vote as a single class with our common units, except that the number of Series A preferred units that may vote is limited to 19.9% of our total common units outstanding, which is the maximum amount our common unitholders can be diluted without a unitholder vote (the “common unit cap”). On November 17, 2010, we are holding a special meeting of common unitholders to approve the conversion provisions of the Series A preferred units.

Conversion. Beginning on July 21, 2013, the Series A preferred units generally will become convertible into common units by us or by the preferred unitholder, subject to the limitations described below. After July 21, 2013, the preferred unitholder may elect to convert all or any portion of its Series A preferred units into common units at any time, but only to the extent that conversion will not cause our estimated ratio of total distributable cash flow to per-unit distributions (for all of our outstanding common and Series A preferred units) to fall below 100% over any of the forecasted succeeding four quarters. In addition, we will have the right to force conversion of all or any portion of the Series A preferred units if the daily volume-weighted average trading price and the average daily trading volume of our common units exceed $37.77 and 500,000 units, respectively, for 20 trading days out of the trailing 30-day period prior to our notice of conversion. On the date of conversion, the rights of the converting

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 6 —	Members’ Capital and Distributions (Continued)

Series A preferred units will cease; the converting Series A preferred units will no longer be outstanding and will represent only the right to receive common units at the rate of one common unit for each preferred unit.

Rights upon a Change of Control. The preferred unitholder has conversion rights with respect to certain change of control events. Before consummating a transaction in which any person, other than the preferred unitholder, becomes the beneficial owner, directly or indirectly, of more than 50% of our voting securities, we will make an irrevocable offer (a “change of control offer”) to the preferred unitholder to convert all, but not less than all, of such holder’s Series A preferred units into common units, subject to certain conditions and limitations, including the common unit cap. Series A preferred units converting in the context of a change of control offer would not convert into common units on a one-for-one basis. Instead, the number of common units we would issue upon conversion of Series A preferred units would equal the quotient of (a) 110% of the aggregate preferred unit issue price for such preferred unitholder’s converting Series A preferred units and all accrued and unpaid distributions on such Series A preferred units as of the date of the change of control offer, divided by (b) $29.05. The preferred unitholder is under no obligation to accept a change of control offer.

Dissolution and Liquidation. The Series A preferred units are senior to our common units with respect to rights on dissolution and liquidation. Common units issued upon conversion of Series A preferred units will rank equally with the rest of our common units with respect to rights on dissolution and liquidation.

Common Units

In March 2010, we issued 7,446,250 common units in an underwritten public offering (including units issued upon the underwriters’ exercise of their option to purchase additional units). We used the net proceeds from the offering to repay a portion of our then-outstanding indebtedness under our Credit Facility.

Distributions. The following table summarizes our quarterly cash distributions during 2010:


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

December 31, 2009	$0.575	January 13, 2010	February 1, 2010	February 11, 2010	$31,911,000
March 31, 2010	$0.575	April 14, 2010	April 30, 2010	May 13, 2010	$38,134,000
June 30, 2010	$0.575	July 14, 2010	August 2, 2010	August 12, 2010	$38,295,000
September 30, 2010	$0.575	October 13, 2010	November 1, 2010	November 11, 2010	$38,349,000

Class D Units

Class D units totaling 3,245,817 as of December 31, 2009 converted into our common units on a one-for-one basis in February 2010.

Accounting for Equity-Based Compensation

We use ASC 718, “Stock Compensation,” to account for equity-based compensation expense related to awards issued under our long-term incentive plan (“LTIP”). As of September 30, 2010, the number of units available for grant under our LTIP totaled 1,374,085, of which up to 804,535 units were eligible to be issued as restricted common units, phantom units or unit awards.

Equity Awards. We recognized non-cash compensation expense of $5,790,000 and $5,476,000 related to the amortization of equity-based compensation under our LTIP during the nine months ended September 30, 2010 and 2009, respectively. See Item 8 in our Annual Report on Form 10-K, as amended, for the year ended December 31, 2009 for details on our equity-based compensation.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 6 —	Members’ Capital and Distributions (Continued)

On May 10, 2010 and June 4, 2010, we granted employees a total of 180,000 phantom units with a fair value of $4,408,000. Each phantom unit grant vests in equal one-third annual installments commencing on May 15, 2011 or earlier upon change of control, death or disability. The compensation expense will be recognized over the vesting period.

On June 4, 2010, we granted 83,000 performance-based phantom units to certain management employees. The number of performance-based phantom units to vest is dependent on the level of achievement of a specified performance goal during the period from the grant date through the cliff vesting date of May 15, 2013. The fair value of the number of awards expected to vest is $4,059,000 and will be recognized as compensation expense over the vesting period. Additionally, we will recognize cumulative adjustments for changes in the probability of the performance goal being met. For awards containing performance conditions that affect vesting, compensation expense is recognized equal to the ultimate outcome of the performance condition.

Liability Awards. Since ASC 480, “Accounting for Certain Financial Instruments With Characteristics of Both Liabilities and Equity,” requires unconditional obligations in the form of units that the issuer must or may settle by issuing a variable number of units to be classified as a liability, we classify equity awards issued to settle Employee Incentive Compensation Program (“EICP”) and Management Incentive Compensation Plan (“MICP”) obligations as liability awards. During the nine months ended September 30, 2010, we issued 83,598 common units to settle our EICP and 2009 MICP obligations. As of September 30, 2010, we accrued $586,000 and $1,096,000 for the third quarter 2010 EICP bonuses and an estimate of the 2010 MICP incentive bonuses, respectively. As of September 30, 2010, the estimated unrecognized compensation costs related to these liability awards totaled $557,000 and $609,000 for the EICP and MICP, respectively, which are expected to be recognized as expense on a straight-line basis through December 2010 for EICP awards and through February 2011 for MICP awards.


Note 7 —	Net Income (Loss) Per Unit

Basic net income (loss) per unit excludes dilution and is computed by dividing net income (loss) 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 (loss) 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 (loss) per unit. Dilutive net income (loss) per unit is computed by dividing net income (loss) 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.


	Three Months Ended September 30,				Nine Months Ended September 30,
	2010		2009		2010		2009
	(In thousands)

Basic weighted average units		65,658		54,565		63,193		54,313
Potentially dilutive common equity:
Employee options		—		114		—		93
Restricted units		—		15		—		5
Phantom units		—		33		—		58
Contingent incentive plan unit awards		—		63		—		63
Class C units		—		—		—		175
Class D units		—		3,246		—		3,246

Dilutive weighted average units⁽¹⁾		65,658		58,036		63,193		57,953

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 7 —	Net Income (Loss) Per Unit (Continued)


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


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009
			(In thousands)

Employee options		1,096		1,253		1,096		1,273
Unit appreciation rights		359		283		359		283
Restricted units		54		93		54		102
Phantom units		884		658		884		633
Contingent incentive plan unit awards		33		—		61		—
Series A preferred units		8,082		—		2,724		—


Note 8 —	Related Party Transactions

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,
	2010			2009		2010			2009

Affiliates of Mr. Lawing:⁽¹⁾
Natural gas sales⁽²⁾	$	14		$	—	$	16		$	1
Gathering and compression services⁽³⁾		2			5		7			16
Natural gas purchases⁽⁴⁾		67			183		455			748
Reimbursable costs⁽⁵⁾		57			—		207			—
Reimbursements paid⁽⁶⁾		—			691		—			2,616
Payable by us as of September 30, 2010⁽⁷⁾							8
Webb Duval:
Natural gas sales⁽²⁾		33			209		45			804
Natural gas purchases⁽⁴⁾		(179	)		87		(66	)		320
Transportation costs⁽⁸⁾		56			77		187			260
Management fees⁽⁹⁾		56			56		168			166
Reimbursable costs⁽⁹⁾		503			158		642			458
Payable to us as of September 30, 2010⁽¹⁰⁾							715
Payable by us as of September 30, 2010⁽⁷⁾							1
Eagle Ford:
Management fees⁽⁹⁾		41			—		—			—
Reimbursable costs⁽⁹⁾		1,389			—		—			—
Payable to us as of September 30, 2010⁽¹⁰⁾							1,422
Southern Dome:
Management fees⁽⁹⁾		63			63		188			188
Reimbursable costs⁽⁹⁾		96			107		253			262
Payable to us as of September 30, 2010⁽¹⁰⁾							680
Payable by us as of September 30, 2010⁽⁷⁾							33

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 8 —	Related Party Transactions (Continued)


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2010		2009		2010		2009

Bighorn:
Compressor rental fees⁽¹¹⁾		417		399		1,250		564
Gathering costs⁽⁸⁾		—		65		16		286
Natural gas purchases⁽⁴⁾		—		—		3		—
Management fees⁽⁹⁾		139		135		417		406
Reimbursable costs⁽⁹⁾		648		597		1,873		1,760
Payable to us as of September 30, 2010⁽¹⁰⁾						78
Payable by us as of September 30, 2010⁽⁷⁾						219
Fort Union:
Gathering costs⁽⁸⁾		1,288		2,054		3,926		6,093
Treating costs⁽⁴⁾		—		127		52		461
Management fees⁽⁹⁾		60		57		180		170
Reimbursable costs⁽⁹⁾		32		40		161		207
Payable to us as of September 30, 2010⁽¹⁰⁾						5
Other:
Natural gas sales⁽²⁾		50		70		175		167
Payable to us as of September 30, 2010⁽¹⁰⁾						9


(1)		These entities were controlled by John R. Eckel, Jr., our former Chairman and Chief Executive Officer, until his death in November 2009, and since that time have been controlled by Douglas L. Lawing, our Executive Vice President, General Counsel and Secretary.

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

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

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

(5)		Reimbursable costs received from Copano/Operations, Inc. (“Copano Operations”) for its use of shared personnel, facilities and equipment, which was the only compensation we received from Copano Operations.

(6)		Reimbursable costs paid to Copano Operations for our use of shared personnel, office space, equipment, goods and services under an agreement that terminated on January 1, 2010. Effective January 1, 2010, we hired the personnel we share with Copano Operations, assumed responsibility for procuring the shared office space, equipment, goods and services and entered into a new agreement under which we provide Copano Operations with access to shared personnel, facilities and equipment in exchange for a monthly charge and rights to use certain assets owned by Copano Operations.

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

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

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

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

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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 8 —	Related Party Transactions (Continued)

Director Designation Agreement

Upon the issuance of the Series A preferred units, we entered into a director designation agreement with TPG. Pursuant to the director designation agreement, our Board of Directors expanded its number from seven to eight directors and appointed Michael G. MacDougall, a partner with TPG, to serve as a director until our next annual meeting. We will be obligated to nominate Mr. MacDougall or another designee of TPG for election to our Board of Directors at each annual meeting until: (i) TPG and its affiliates own, in the aggregate, less than 5,163,511 Series A preferred units, together with any common units (or Class B units, if applicable) issued upon conversion of Series A preferred units, or (ii) after July 21, 2013, TPG and its affiliates own, in the aggregate, a number of Series A preferred units, together with any common units (or Class B units, if applicable) issued upon conversion of Series A preferred units that constitutes less than 5% of our common units then outstanding.

During the three months ended September 30, 2010, certain of our operating subsidiaries paid an affiliate of TPG $30,000 for compression services.

Other Transactions

Certain of our operating subsidiaries and unconsolidated affiliates 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 $2,984,000 and $587,000 for the three months ended September 30, 2010 and 2009, respectively, and $7,104,000 and $2,721,000 for the nine months ended September 30, 2010 and 2009, 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.

During 2010, we purchased approximately 20,000 feet of 24-inch pipe from Fort Union for use in our Texas operations for a purchase price of $810,000 which was equal to Fort Union’s carrying value.

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, 2010 and 2009, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $773,000 and $1,455,000, respectively. For the nine months ended September 30, 2010 and 2009, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $2,506,000 and $6,041,000, respectively.

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 $2,469,000 for the remainder of 2010, $9,876,000 in 2011, $9,867,000 in 2012, $8,978,000 in 2013, $5,509,000 in 2014 and $19,204,000 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 $1.9 million, 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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 9 —	Commitments and Contingencies (Continued)

obligated to pay approximately $1,288,000 for the remainder of 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. These commitments expire on November 30, 2017.

We have fixed-quantity contractual commitments to Targa North Texas LP (“Targa”) in settlement of a dispute regarding what portion, if any, of natural gas we purchase from producers that had been contractually dedicated for resale to Targa. As of September 30, 2010, we had fixed contractual commitments to provide Targa a total of 2.373 billion cubic feet of natural gas for October 1, 2009 through December 31, 2010 and for each of 2011, 2012 and 2013. As of September 30, 2010, we have accrued $1,854,000 of our obligation. Under the terms of the agreement, we are obligated to pay annual fees ($1.00 per thousand cubic feet (“Mcf”), $1.10 per Mcf, $1.15 per Mcf and $1.25 per Mcf for 2010, 2011, 2012 and 2013, respectively) to the extent our natural gas deliveries to Targa fall below the committed quantity.

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, results of operations or cash flows.

Litigation

Please read Note 9, “Commitments and Contingencies,” to our unaudited consolidated financial statements included in Part I, Item 1 of our Quarterly Reports on Form 10-Q for the quarterly periods ended March 31, 2010 and June 30, 2010, which are incorporated herein by reference.

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


Note 10 —	Supplemental Disclosures to the Statements of Cash Flows


	Nine Months Ended
	September 30,
	2010		2009
	(In thousands)

Cash payments for interest, net of $2,685,000 and $2,982,000 capitalized in 2010 and 2009, respectively	$	40,042	$	41,820
Cash payments for federal and state income taxes	$	655	$	790
In-kind distributions to Series A convertible preferred unitholders	$	7,500	$	—

We incurred a change in liabilities for investing activities that had not been paid as of September 30, 2010 and 2009 of $5,512,000 and $9,908,000, respectively. 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, 2010 and 2009, we accrued $10,761,000 and $3,975,000, 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

We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as puts, calls, swaps and other financial instruments to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements.

Commodity Risk Hedging Program

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

Our Risk Management Committee monitors and ensures compliance with the risk management policy and consists of senior level executives in the operations, finance and legal departments. The Audit Committee of our Board of Directors monitors the implementation of the policy and we have engaged an independent firm to provide additional oversight. The risk management policy provides that all derivative transactions must be executed by our Chief Financial Officer and must be authorized in advance of execution by our Chief Executive Officer. The policy requires derivative transactions to take place either on the New York Mercantile Exchange (NYMEX) through a clearing member firm or with over-the-counter counterparties with investment grade ratings from both Moody’s Investors Service and Standard & Poor’s Ratings Services with complete industry standard contractual documentation. Under this documentation, the payment obligations in connection with our swap transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.

Financial instruments that we acquire pursuant to our risk management policy are generally designated as cash flow hedges under ASC 815 and are recorded on our consolidated balance sheets at fair value. For derivatives designated as cash flow hedges, we recognize the effective portion of changes in fair value as other comprehensive income (“OCI”) and reclassify them to revenue within the consolidated statements of operations 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 operations. 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 operations.

As of September 30, 2010, we estimated that $11,031,000 of OCI will be reclassified as a decrease to earnings in the next 12 months as a result of monthly physical settlements of crude oil, NGLs and natural gas.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

The following tables summarize our commodity hedge portfolio as of September 30, 2010 (all hedges are settled monthly):

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)

2010	$	7.3500	$	10.0000		7,100	$	10.0000		10,000
2011	$	6.9500	$	10.0000		7,100	$	10.0000		10,000

Purchased Mt. Belvieu Purity Ethane Puts and Entered into Swaps


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

2010	$	0.5550		1,600	$	0.5700		500
2011	$	0.5300		1,700	$	0.5450		500
2011	$	0.5300		500	$	—		—
2011	$	0.6200		500	$	—		—
2012	$	0.5900		1,000	$	—		—

Purchased Mt. Belvieu TET Propane Puts and Entered into Swaps


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

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	$	—		—
2012	$	1.1500		700	$	—		—

Purchased Mt. Belvieu TET Propane Put Spread Options


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

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)

2010	$	1.0350		300	$	—		—
2010	$	1.1145		100	$	1.2025		100
2011⁽¹⁾	$	1.0205		300	$	—		—
2011	$	1.1100		100	$	1.1800		100
2011	$	1.3900		160	$	—		—
2011	$	1.7100		200	$	—		—
2012	$	1.3900		300	$	—		—
2012	$	1.3900		150	$	—		—


(1)		Instrument is not designated as a cash flow hedge under hedge accounting as of August 2010.

Purchased Mt. Belvieu Non-TET Isobutane Put Spread Options


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

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)

2010	$	1.0300		300	$	—		—
2010	$	1.1000		200	$	1.1850		200
2011⁽¹⁾	$	1.0205		300	$	—		—
2011	$	1.0850		200	$	1.1700		200
2011	$	1.3500		140	$	—		—
2011	$	1.7100		350	$	—		—
2012	$	1.3500		250	$	—		—
2012	$	1.3600		350	$	—		—


(1)		Instrument is not designated as a cash flow hedge under hedge accounting as of August 2010.

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


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

2010	$	1.8800	$	1.1000		200
2010	$	1.8800	$	1.0300		300

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

Purchased Mt. Belvieu Non-TET Natural Gasoline Puts


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

2010	$	1.4080		300
2011	$	1.4100		300

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


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

2010	$	2.5400	$	1.4080		300

Natural Gas Basis Swaps


	Purchased Houston Ship
	Channel Index				Sold CenterPoint East Index
	Price		Volume		Price		Volume
	(per MMBtu)		(MMBtu/d)		(per MMBtu)		(MMBtu/d)

2010⁽²⁾	$	0.0450		10,000	$	0.2300		10,000
2011⁽²⁾	$	0.1050		10,000	$	0.3050		10,000


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

Purchased WTI Crude Oil Puts


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

2010	$	55.00		1,000
2010	$	60.00		400
2011⁽¹⁾	$	55.00		1,000
2011	$	60.00		400
2011	$	77.00		700
2011	$	79.00		400
2011	$	85.00		200
2012	$	79.00		300
2012	$	83.00		350
2012	$	83.00		300
2012	$	85.00		350


(1)		Instrument is not designated as a cash flow hedge under hedge accounting as of September 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
	(Per barrel)				Volumes
	Bought		Sold		(Bbls/d)

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, 2010, we hold a notional amount of $95.0 million in interest rate swaps with a weighted average fixed rate of 4.30% that mature between October 2010 and October 2012. As of September 30, 2010, our interest rate swaps are not designated as cash flow hedges.

As of September 30, 2010, we estimate that $361,000 of OCI will be reclassified as an decrease to earnings in the next 12 months as the underlying instruments expire.

ASC 820 “Fair Value Measurement” and ASC 815 “Disclosures about Derivative Instruments and Hedging Activities”

We recognize the fair value of our assets and liabilities that require periodic re-measurement as necessary based upon the requirements of 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 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 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 tables set 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 of September 30, 2010 and December 31, 2009. As required by 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, 2010
	Level 1		Level 2			Level 3		Total
			(In thousands)

Assets:
Natural Gas:
Short-term — Designated^(b)	$	—	$	—		$	42	$	42
Long-term — Designated^(c)		—		—			76		76
Long-term — Not designated^(c)		—		13			—		13
Natural Gas Liquids:
Short-term — Designated^(b)		—		—			12,500		12,500
Long-term — Designated^(c)		—		—			10,047		10,047
Long-term — Not designated^(c)		—		—			74		74
Crude Oil:
Short-term — Designated^(b)		—		—			6,896		6,896
Long-term — Designated^(c)		—		—			6,197		6,197
Long-term — Not designated^(c)		—		—			178		178

Total	$	—	$	13		$	36,010	$	36,023

Liabilities:
Natural Gas:
Short-term — Not designated^(d)	$	—		68			—		68
Natural Gas Liquids:
Short-term — Designated^(d)		—		—			2,966		2,966
Long-term — Designated^(e)		—		—			621		621
Interest Rate:
Short-term — Not designated^(d)		—		4,358			—		4,358
Long-term — Not designated^(e)		—		3,441			—		3,441

Total	$	—	$	7,867		$	3,587	$	11,454

Total designated assets	$	—	$	—		$	32,171	$	32,171

Total not designated (liabilities)/assets	$	—	$	(7,854	)	$	252	$	(7,602	)


(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.”

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)


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

Assets
Commodity derivatives:
Short-term — Designated^(b)	$	—	$	—		$	36,588	$	36,588
Short-term — Not designated^(b)		—		27			—		27
Long-term — Designated^(c)		—		—			14,805		14,805
Long-term — Not designated^(c)		—		—			576		576

Total	$	—	$	27		$	51,969	$	51,996

Liabilities
Commodity derivatives:
Short-term — Designated^(d)	$	—	$	—		$	4,763	$	4,763
Long-term — Designated^(e)		—		—			4,600		4,600
Interest rate derivatives:
Short-term — Not designated^(d)		—		4,909			—		4,909
Long-term — Not designated^(e)		—		3,238			—		3,238

Total	$	—	$	8,147		$	9,363	$	17,510

Total designated assets	$	—	$	—		$	42,030	$	42,030

Total not designated (liabilities)/assets	$	—	$	(8,120	)	$	576	$	(7,544	)


(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.”

We use the income approach incorporating market-based inputs in determining fair value for our derivative contracts.

Valuation of our Level 2 derivative contracts are based on observable market prices (1-month or 3-month LIBOR interest rate curves or CenterPoint East and Houston Ship Channel market curves) incorporating discount rates and credit risk.

Valuation of our Level 3 derivative contracts incorporates the use of valuation models using significant unobservable inputs. To the extent certain model inputs are observable (prices of WTI Crude, Mt. Belvieu NGLs and Houston Ship Channel natural gas), we include observable market price and volatility data as inputs to our valuation model in addition to incorporating discount rates and credit risk. For those input parameters that are not readily available (implied volatilities for Mt. Belvieu NGL prices or prices for illiquid periods of price curves), the modeling methodology incorporates available market information to generate these inputs through techniques such as regression based extrapolation.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 11 —	Financial Instruments (Continued)

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


	Three Months Ended September 30, 2010
	Natural Gas			Natural Gas Liquids			Crude Oil			Total
				(In thousands)

Assets balance, beginning of period	$	653		$	36,237		$	21,529		$	58,419
Total gains or losses:
Non-cash amortization of option premium		(1,489	)		(4,154	)		(2,520	)		(8,163	)
Other amounts included in earnings		—			5,699			5,063			10,762
Included in accumulated other comprehensive loss		954			(15,048	)		(6,733	)		(20,827	)
Purchases		—			2,051			1,315			3,366
Settlements		—			(5,752	)		(5,382	)		(11,134	)
Transfers in and/or out of Level 3		—			—			—			—

Asset balance, end of year	$	118		$	19,033		$	13,272		$	32,423

Change in unrealized losses (income) included in earnings related to instruments still held as of the end of the period	$	—		$	(135	)	$	316		$	181


	Nine Months Ended September 30, 2010
	Natural Gas			Natural Gas Liquids			Crude Oil			Total
				(In thousands)

Assets balance, beginning of period	$	2,752		$	15,641		$	24,213		$	42,606
Total gains or losses:
Non-cash amortization of option premium		(4,417	)		(12,317	)		(7,476	)		(24,210	)
Other amounts included in earnings		—			12,332			15,283			27,615
Included in accumulated other comprehensive loss		1,783			6,208			(8,069	)		(78	)
Purchases		—			9,433			4,740			14,173
Settlements		—			(12,264	)		(15,419	)		(27,683	)
Transfers in and/or out of Level 3		—			—			—			—

Asset balance, end of period	$	118		$	19,033		$	13,272		$	32,423

Change in unrealized losses (income) included in earnings related to instruments still held as of the end of the period	$	—		$	(165	)	$	470		$	305

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents

Table of Contents