10-Q

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

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.

3

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.

4

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.

5

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.

6

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

7

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

8

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

9

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.

10

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

11

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

12

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.

13

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.

14

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

15

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

16

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

17

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

18

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.

19

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.

20

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

21

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

22

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.

23

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

24

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.

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.

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.

25

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

26

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,

27

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

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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

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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.

30

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.

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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.

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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.

33

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.

34

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			(189	)	Condensate and other
Interest rate swaps		252			174			—		Interest and other financing costs
Total	$	23,692		$	35,103		$	(201	)

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

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

Derivatives Not Designated as	Amount of Gain or
Hedging Instruments	(Loss) Recognized in			Statement of Operations
Under Statement 133	Income on Derivative			Location
Three months ended September 30, 2009
Natural gas liquids	$	438		Natural gas liquids sales
Interest rate		(621	)	Interest and other financing costs
Total	$	(183	)
Nine months ended September 30, 2009
Natural gas liquids	$	81		Natural gas liquids sales
Interest rate		1,563		Interest and other financing costs
Total	$	1,644

35

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 12 — Fair Value of Financial Instruments

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

	September 30, 2009
	Carrying		Estimated
	Value		Fair Value
	(In thousands)
Cash and cash equivalents	$	35,378	$	35,378
Credit Facility		260,000		249,882
2016 Notes		332,665		326,843
2018 Notes		249,525		238,920

Note 13 — Discontinued Operations

Because we initiated a plan to sell our crude oil pipeline and related assets included in our Oklahoma segment, we designated our crude oil pipeline operations as held for sale at September 30, 2009. Upon making this designation, we classified the results of operations and financial position of our crude oil pipeline as “discontinued operations” for all periods presented.

In October 2009, we completed the sale of our crude oil pipeline and related assets. The sale was effective as of October 1, 2009. In the fourth quarter of 2009, we will recognize a gain on the sale of the crude oil pipeline system of approximately $1.1 million.

Selected financial data for the crude oil pipeline and related assets are as follows (in thousands):

	September 30,			December 31,
	2009			2008
Prepayment and other current assets	$	120		$	113
Property, plant and equipment, net		4,785			4,475
Intangibles, net		128			534
Other assets, net		575			343
		5,608			5,465
Other current liabilities		(384	)		—
Net assets	$	5,224		$	5,465

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2009		2008		2009		2008
Crude oil sales	$	25,971	$	50,763	$	64,039	$	149,128
Cost of crude oil purchases		24,964		50,359		60,733		146,222
Income from discontinued operations before taxes	$	262	$	166	$	1,393	$	2,224
Income tax expense		—		—		—		—
Net income from discontinued operations	$	262	$	166	$	1,393	$	2,224

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 14 — Segment Information

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

•  Oklahoma, which includes midstream natural gas services in central and east Oklahoma, including gathering and transmission of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our equity investment in Southern Dome and, through September 30, 2009, a crude oil pipeline located in south Oklahoma and north Texas.

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

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

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

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

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 14 — Segment Information (Continued)

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

							Rocky			Total			Corporate
	Oklahoma(a)			Texas			Mountains			Segments			and Other			Consolidated
Three Months Ended September 30, 2009:
Total segment gross margin	$	18,284		$	26,875		$	634		$	45,793		$	7,637		$	53,430
Operations and maintenance expenses		6,111			7,089			2			13,202			—			13,202
Depreciation and amortization		8,183			5,222			763			14,168			407			14,575
General and administrative expenses		2,028			2,376			549			4,953			4,247			9,200
Taxes other than income		442			378			16			836			—			836
Equity in earnings from unconsolidated affiliates		(383	)		(75	)		(2,071	)		(2,529	)		—			(2,529	)
Operating income	$	1,903		$	11,885		$	1,375		$	15,163		$	2,983		$	18,146
Sales to external customers	$	86,714		$	89,233		$	5,947		$	181,894		$	7,637		$	189,531
Intersegment sales		(310	)		310			—			—			—			—
Interest and other financing costs		—			—			—			—			15,440			15,440
Net income (loss)		2,155			11,888			2,447			16,490			(12,761	)		3,729
Three Months Ended September 30, 2008:
Total segment gross margin	$	33,132		$	41,392		$	1,257		$	75,781		$	(14,408	)	$	61,373
Operations and maintenance expenses		6,170			9,041			—			15,211			—			15,211
Depreciation and amortization		7,584			4,147			671			12,402			298			12,700
General and administrative expenses		1,978			2,018			576			4,572			6,470			11,042
Taxes other than income		399			324			—			723			—			723
Equity in earnings from unconsolidated affiliates		(866	)		(162	)		(1,142	)		(2,170	)		—			(2,170	)
Operating income (loss)	$	17,867		$	26,024		$	1,152		$	45,043		$	(21,176	)	$	23,867
Sales to external customers	$	188,310		$	217,492		$	11,476		$	417,278		$	(14,408	)	$	402,870
Intersegment sales		(594	)		594			—			—			—			—
Interest and other financing costs		—			—			—			—			15,470			15,470
Net income (loss)		18,213			26,143			1,182			45,538			(36,815	)		8,723

(a) All information excludes the results of discontinued operations for the sale of the crude oil pipeline and related assets (Note 13) except for the information related to intersegment sales, interest and other financing costs and net income (loss).

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COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 14 — Segment Information (Continued)

							Rocky			Total			Corporate
	Oklahoma(a)			Texas			Mountains			Segments			and Other			Consolidated
Nine Months Ended September 30, 2009:
Total segment gross margin	$	50,058		$	70,775		$	2,144		$	122,977		$	34,490		$	157,467
Operations and maintenance expenses		17,335			21,423			6			38,764			—			38,764
Depreciation and amortization		23,848			13,988			2,155			39,991			1,080			41,071
General and administrative expenses		6,093			6,910			1,900			14,903			14,343			29,246
Taxes other than income		1,198			1,133			18			2,349			—			2,349
Equity in earnings from unconsolidated affiliates		(1,170	)		(47	)		(4,895	)		(6,112	)		—			(6,112	)
Operating income (loss)	$	2,754		$	27,368		$	2,960		$	33,082		$	19,067		$	52,149
Sales to external customers	$	248,950		$	266,264		$	21,088		$	536,302		$	34,490		$	570,792
Intersegment sales		(966	)		966			—			—			—			—
Interest and other financing costs		—			—			—			—			41,889			41,889
Net income (loss)		4,174			27,389			4,032			35,595			(19,923	)		15,672
Segment assets		713,007			409,994			696,213			1,819,214			63,345			1,882,559
Nine Months Ended September 30, 2008:
Total segment gross margin	$	115,052		$	123,467		$	3,438		$	241,957		$	(49,694	)	$	192,263
Operations and maintenance expenses		17,860			21,910			—			39,770			—			39,770
Depreciation and amortization		22,496			11,495			2,011			36,002			927			36,929
General and administrative expenses		5,658			6,002			2,138			13,798			20,030			33,828
Taxes other than income		1,213			980			—			2,193			—			2,193
Equity in earnings from unconsolidated affiliates		(2,991	)		(1,008	)		(3,355	)		(7,354	)		—			(7,354	)
Operating income (loss)	$	70,816		$	84,088		$	2,644		$	157,548		$	(70,651	)	$	86,897
Sales to external customers	$	576,072		$	645,963		$	35,190		$	1,257,225		$	(49,694	)	$	1,207,531
Intersegment sales		(1,639	)		1,639			—			—			—			—
Interest and other financing costs		—			—			—			—			42,939			42,939
Net income (loss)		73,551			84,498			2,738			160,787			(114,360	)		46,427

(a) All information excludes the results of discontinued operations for the sale of the crude oil pipeline and related assets (Note 13) except for the information related to intersegment sales, interest and other financing costs and net income (loss).

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Item 2.   Management’s Discussion and Analysis of Financial Condition and Results of Operations.

You should read the following discussion of our financial condition and results of operations in conjunction with the unaudited consolidated financial statements and notes thereto included elsewhere in this report.

As generally used in the energy industry and in this report, the following terms have the following meanings:

/d:	Per day
Bcf:	One billion cubic feet
Btu:	One British thermal unit
Lean Gas:	Natural gas that is low in NGL content
MMBtu:	One million British thermal units
Mcf:	One thousand cubic feet
MMcf:	One million cubic feet
NGLs:	Natural gas liquids, which consist primarily of ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate
Residue gas:	The pipeline quality natural gas remaining after natural gas is processed
Rich gas:	Natural gas that is high in NGL content
Throughput:	The volume of natural gas or NGLs transported or passing through a pipeline, plant, terminal or other facility

Overview

We are a Delaware limited liability company formed in 2001 to acquire entities operating under the Copano name since 1992, and to serve as a holding company for our operating subsidiaries. Through our subsidiaries, we own and operate natural gas gathering and intrastate transmission pipeline assets, natural gas processing and fractionation facilities, NGL pipelines and, through September 2009, a crude oil pipeline. We operate in Oklahoma, Texas, Wyoming and Louisiana.

We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into three operating segments: Oklahoma, Texas and Rocky Mountains.

•  Our Oklahoma segment provides midstream natural gas services in central and east Oklahoma, including gathering and transmission of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our equity investment in Southern Dome, and through September 2009, included a crude oil pipeline located in south Oklahoma and north Texas.

•  Our Texas segment provides midstream natural gas services in south and north Texas, including gathering and intrastate transmission of natural gas, and related services such as compression, dehydration, treating, conditioning or processing and marketing. Our Texas segment also provides NGL fractionation and transportation through our Houston Central plant and our NGL pipelines. In addition, our Texas segment includes a processing plant located in southwest Louisiana and our equity investment in Webb Duval.

•  Our Rocky Mountains segment provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas. This segment also includes our equity investments in Bighorn and Fort Union.

Corporate and other relate to our risk management activities, intersegment eliminations and other activities we perform or assets we hold that have not been allocated to any of our reporting segments.

Trends and Uncertainties

This section, which describes recent changes in factors affecting our business, should be read in conjunction with “— How We Evaluate Our Operations” and “— How We Manage Our Operations” below. Many of the factors affecting our business are beyond our control and are difficult to predict.

Commodity Prices and Producer Activity

Our gross margins and total distributable cash flow are influenced by the prices of natural gas and NGLs, and by drilling activity. Generally, prices affect the cash flow and profitability of our Texas and Oklahoma segments

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directly. To the extent that they influence the level of drilling activity, commodity prices also affect all of our segments indirectly. Please read “— How We Evaluate Our Operations” and “— How We Manage Our Operations” for further discussion. For a discussion of how we use hedging to reduce the effects of commodity price fluctuations on our cash flow and profitability, please read “Item 3. Quantitative and Qualitative Disclosures About Market Risk.”

The long term growth and sustainability of our business depends on natural gas prices being at levels sufficient to provide incentives, capital and adequate returns for producers to maintain and increase natural gas exploration and production. Commodity price fluctuations and the availability of capital are among the factors that influence natural gas producers as they schedule drilling projects. Low natural gas prices, particularly in combination with high operating costs, act as a disincentive to producers. In an unfavorable pricing environment, producers typically re-evaluate their drilling schedules and related capital expenditures and, depending on the severity and duration of the pricing trends, may suspend drilling and completion of wells to the degree they have become uneconomic. We believe that future natural gas prices will be influenced by regional drilling activity takeaway capacity, the severity of winter and summer weather, natural gas storage levels, liquefied natural gas imports, NGL transportation and fractionation capacity and the overall economy.

The financial and economic crises of late 2008 were accompanied by sharp declines in prices for oil, natural gas and NGLs. Prices for oil and NGLs have continued the recovery that began in the second quarter of 2009, while natural gas prices showed some improvement but remained low. Forward pricing on NYMEX reflects market expectations that oil and natural gas prices in the coming months will be consistently higher compared to recent months. While recent economic indicators increasingly support the view that the recession has ended, the strength and sustainability of an economic recovery remain uncertain. A renewed slowdown in economic activity would likely result in continued lower natural gas prices and renewed declines in NGL prices, which in turn would delay a recovery in drilling activity.

Pricing Trends in Texas.  During the third quarter of 2009, NGL prices in Texas continued to recover, and natural gas prices declined. Prices for both natural gas and NGLs have improved for the fourth quarter 2009 to date. The first-of-the-month price for natural gas on the Houston Ship Channel index was $4.23 per MMBtu for November 2009, and average month-to-date prices for NGLs at Mt. Belvieu through November 2, 2009 were $43.23 per barrel. The following graph and table summarize monthly and quarterly average prices on the primary indices we use to price natural gas and NGLs in Texas.

Texas Average Prices for Natural Gas and NGLs⁽¹⁾

(1) NGL prices for November are month-to-date through November 2, 2009. Average monthly NGL prices are calculated based on our weighted-average product production mix at Mt. Belvieu for the period indicated. Average monthly NGL prices for October and November are based on our third-quarter-weighted average production mix.

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	Quarterly Data for Texas:
	Q1 2008		Q2 2008		Q3 2008		Q4 2008		Q1 2009		Q2 2009		Q3 2009
Houston Ship Channel ($/MMBtu)	$	7.73	$	10.58	$	9.98	$	6.37	$	4.21	$	3.44	$	3.32
Mt. Belvieu ($/barrel)	$	58.94	$	68.89	$	69.12	$	35.70	$	25.81	$	30.12	$	35.09
Texas Service Throughput (MMBtu/d)		696,658		700,545		666,686		679,142		644,752		630,674		613,234
Texas Plant Inlet (MMBtu/d)		601,736		629,334		596,225		600,719		558,115		559,597		543,994
Texas Segment Gross Margin (in thousands)	$	41,576	$	40,499	$	41,392	$	19,256	$	20,580	$	23,320	$	26,875

Oklahoma Prices.  During the third quarter of 2009, Oklahoma NGL prices continued to recover from the lows experienced in the first quarter, and natural gas prices improved initially but declined in September. Natural gas prices have recovered during the first part of the fourth quarter, and NGL prices have continued to strengthen. The first of month price for natural gas on CenterPoint East was $4.22 per MMBtu for November, and month-to-date average prices for NGLs at Conway through November 2, 2009 were $39.42 per barrel. The following graph and table summarize the average monthly and quarterly prices on the primary indices we use to price natural gas and NGLs in Oklahoma.

Oklahoma Average Prices for Natural Gas and NGLs⁽¹⁾

(1) NGL prices for November are month-to-date through November 2, 2009. Average monthly NGL prices are calculated based on our weighted-average product production mix at Conway for the period indicated. Average monthly NGL prices for October and November are based on our third quarter weighted-average production mix. Segment gross margin results exclude activities attributable to our crude oil pipeline and related assets. See Item 1, Note 13 to our unaudited consolidated financial statements entitled “Discontinued Operations.”

	Quarterly Data for Oklahoma:
	Q1 2008		Q2 2008		Q3 2008		Q4 2008		Q1 2009		Q2 2009		Q3 2009
CenterPoint East ($/MMBtu)	$	7.20	$	9.26	$	8.41	$	3.58	$	3.37	$	2.70	$	2.98
Conway ($/barrel)	$	56.33	$	62.27	$	59.42	$	27.36	$	24.13	$	25.57	$	27.62
Oklahoma Service Throughput (MMBtu/d)		222,006		228,941		243,000		261,107		271,222		267,576		260,296
Oklahoma Plant Inlet (MMBtu/d)		150,060		155,430		158,047		160,074		160,181		166,846		166,884
Oklahoma Segment Gross Margin (in thousands)	$	35,637	$	46,284	$	33,132	$	18,122	$	14,300	$	17,472	$	18,284

NGL Basis Trends.  While NGL prices at both Mt. Belvieu and Conway improved during the third quarter, the rate of improvement on Mt. Belvieu was faster than at Conway. As a result, we experienced a widening basis differential affecting NGL prices during the third quarter, which in August reached $9.95 per barrel. However, Conway prices for September and the beginning of the fourth quarter have indicated a reversal of this trend. At November 2, 2009 the basis differential between Mt. Belvieu and Conway had narrowed to $2.87 per barrel.

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Trends in Drilling and Production Activity.  Drilling activity has continued to be lower due to the weaker pricing environment. We experienced a modest decrease in overall volumes compared to the third quarter of 2008, largely due to lower volumes in Texas and modestly lower volumes in the Rocky Mountains (including Bighorn and Fort Union). These volume decreases are attributable partly to lower drilling activity; however, a decrease in low-margin gas from a third party pipeline was also a significant factor in Texas. Compared to the second quarter of 2009, third quarter volumes reflect modest decreases in Texas and Oklahoma, while Rocky Mountains volumes (including Bighorn and Fort Union) remained flat. Although commodity prices and financial market conditions have begun to recover, improvements in drilling activity remain sporadic, and it remains unclear when producers will undertake sustained increases in drilling activity throughout the areas in which we operate.

We anticipate that producers may increase new drilling activity once natural gas prices reach a level sufficient to make drilling and production economic. The level at which drilling and production become economic depends on various factors, including the producer’s drilling, completion and other operating costs, which are influenced by the characteristics of the hydrocarbon reservoir, among other things. While these costs have declined significantly since late 2008, additional considerations, such as demand for and competing supplies of natural gas, and their anticipated effects on natural gas prices, will also influence producers’ decisions regarding drilling. For producers of rich gas who share in the benefits of improved processing economics under their sales contracts, the disincentive of low natural gas prices could be offset as prices for condensate and NGLs increase. In addition, improving oil prices could lead to increased production of casinghead natural gas associated with oil production.

If the pricing environment of the third quarter of 2009 continues, we anticipate that we will see sustained or increasing drilling activity in areas that produce rich gas, for example the Eagle Ford Shale trend in South Texas, and a continued low level of drilling activity in areas that produce lean gas, for example the Woodford Shale in Oklahoma and the Powder River Basin in Wyoming. We expect that many producers of lean gas will wait to see sustained increases in natural gas prices before resuming significant drilling activity. Forward pricing on NYMEX suggest that natural gas prices could improve in the near future; however, forward curves only reflect market expectations, and it is uncertain to what extent they will influence producers’ drilling decisions. Once drilling activity increases, a recovery in volumes will be subject to delays for processes involved in completing and attaching new wells. Any prolonged reduction in oil and natural gas prices would further depress the current levels of exploration, development and production activity.

Other Industry Trends.  Due to higher NGL prices and the completion of projects increasing NGL output, NGL fractionation facilities are experiencing capacity constraints, which we believe could lead to erosion in the processing margins received from NGLs. For a portion of the third quarter of 2009, we realized lower revenue for sales of mixed NGLs from the tailgate of our Houston Central plant under a short term pricing arrangement. If NGL fractionation capacity remains constrained, the effect on NGL revenue could offset the benefits of improving NGL market prices to some extent. In August, we entered into a new contract to sell NGLs from Houston Central at a higher price. In addition, we are expanding our fractionation capacity at Houston Central, which will allow us to sell purity ethane and purity propane through separate pipelines and purity iso-butane and purity normal butane through truck racks, helping to offset the effect of fractionation capacity constraints on our NGL revenue. We anticipate completing this project in early 2010.

Credit and Capital Market Disruptions.  The effects of late-2008 disruptions in financial markets worldwide continue to influence the availability of debt and equity capital, although to a lesser degree. Generally, we believe that the markets have recovered significantly since the height of the financial crisis, although the cost of capital remains higher than before the financial crisis. To the extent we access financial markets in the near term, we believe that we would be able to raise debt and equity on acceptable terms, although the cost of either would depend on then-existing market conditions.

Renewed instability in the financial markets, as a result of developments in the recent recession or otherwise, would have a negative impact on the cost and accessibility of capital for us, and for our customers and suppliers.

Factors Affecting Operating Results and Financial Condition

Our results for the three and nine months ended September 30, 2009 reflect the lower prices and modestly lower volumes we encountered during these periods compared to the high commodity prices and increasing

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volumes that prevailed during the same periods in 2008. A comparison of the second and third quarters of 2009, however, reveals the continuing benefits of strengthening NGL prices. Higher NGL prices overall combined with lower natural gas prices in Texas during the third quarter of 2009 have led to improvement in our processing margins compared to the second quarter. This improvement was offset in part by lower NGL revenue due to fractionation capacity constraints. In addition, while our overall volumes were lower, the volume of natural gas that we processed increased slightly compared to the second quarter. As a result of the increased margins and volumes for processed gas, our combined operating segment gross margins increased 7% compared to the second quarter of 2009.

Consistent with our business strategy, we have used derivative instruments to mitigate the effects of commodity price fluctuations on our cash flow and profitability so that we can continue to meet our debt service and capital expenditure requirements, and our distribution objectives. For the three and nine months ended September 30, 2009, we received $16.4 million and $62.3 million, respectively, in cash settlements from our commodity hedge portfolio, which helped to offset the decline in operating revenues attributable to lower commodity prices. The basis spread between Mt. Belvieu and Conway limited the benefit we received from our NGL hedging portfolio because we hedge Oklahoma NGL volume with hedge instruments based on Mt. Belvieu prices. For the three and nine months ended September 30, 2008, we paid $7.0 million and $19.4 million, respectively, in cash settlements to satisfy commodity swap obligations. Our results also reflect lower general and administrative and operating expenses due to our continuing cost control efforts.

How We Evaluate Our Operations

We believe that investors benefit from having access to the various financial and operating measures that our management uses in evaluating our performance. These measures include the following: (i) throughput volumes; (ii) segment gross margin and total segment gross margin; (iii) operations and maintenance expenses; (iv) general and administrative expenses; (v) EBITDA and adjusted EBITDA and (vi) total distributable cash flow. Segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow are non-GAAP financial measures. A reconciliation of each non-GAAP measure to its most directly comparable GAAP measure is provided below.

Throughput Volumes.  Throughput volumes associated with our business are an important part of our operational analysis. We continually evaluate volumes delivered to our plants and flowing through our pipelines to ensure that we have adequate throughput to meet our financial objectives. Our performance at our processing plants is significantly influenced by the volume of natural gas delivered to the plant, the NGL content of the natural gas, the quality of the natural gas and the plant’s recovery capability. In addition, we monitor fuel consumption because it has a significant impact on the gross margin realized from our processing or conditioning operations. Although we monitor fuel costs and losses associated with our pipeline operations, these costs are frequently passed on to our producers.

It is also important that we continually add new volumes to our gathering systems to offset or exceed the normal decline of existing volumes. In monitoring our pipeline volumes, managers of our Oklahoma and Texas segments evaluate what we refer to as service throughput, which consists of two components:

•  the volume of natural gas transported or gathered through our pipelines, which we call pipeline throughput; and

•  the volume of natural gas delivered to our wholly owned processing plants by third-party pipelines, excluding any volumes already included in our pipeline throughput.

In our Texas segment, we also compare pipeline throughput and service throughput to evaluate the volumes generated from our pipelines, as opposed to third-party pipelines. In Oklahoma, because no gas is delivered to our wholly owned plants other than by our pipelines, pipeline throughput and service throughput are equivalent.

In our Rocky Mountains segment, we evaluate producer services throughput, which we define as volumes we purchased for resale, volumes gathered using our firm capacity gathering agreements with Fort Union and volumes transported using our firm transportation agreements with WIC, or using additional capacity that we obtain on WIC. We also regularly assess the pipeline throughput of Bighorn and Fort Union.

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Segment Gross Margin and Total Segment Gross Margin.  We define segment gross margin as an operating segment’s revenue minus cost of sales. Cost of sales includes the following: cost of natural gas and NGLs we purchase, cost of crude oil we purchase and costs for transportation of our volumes. We view segment gross margin as an important performance measure of the core profitability of our operations. Segment gross margin allows our senior management to compare volume and price performance of our segments and to more easily identify operational or other issues within a segment. With respect to our Oklahoma and Texas segments, our management analyzes segment gross margin per unit of service throughput. With respect to our Rocky Mountains segment, our management analyzes segment gross margin per unit of producer services throughput. Also, our management analyzes the cash distributions our Rocky Mountains segment receives from Bighorn and Fort Union.

Our Oklahoma margins are, on the whole, positively correlated with NGL prices and natural gas prices. In Texas, increases in natural gas prices or decreases in NGL prices generally have a negative impact on margins, and, conversely, a reduction in natural gas prices or an increase in NGL prices generally has a positive impact. However, when we operate our Houston Central plant in conditioning mode, increases in natural gas prices have a positive impact on our margins. The profitability of our Rocky Mountains operations is not directly affected by commodity prices. Substantially all of our Rocky Mountains contract portfolio, as well as Bighorn’s and Fort Union’s contract portfolios, consist of fixed-fee arrangements providing for an agreed gathering fee per unit of natural gas throughput. Our revenues from these arrangements are directly related to the volume of natural gas that flows through these systems and is not directly affected by commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, however, our revenues under these arrangements would also decline.

To measure the overall financial impact of our contract portfolio, we use total segment gross margin, which is the sum of our operating segments’ gross margins and the results of our risk management activities, which are included in corporate and other. Our total segment gross margin is determined primarily by five interrelated variables: (i) the volume of natural gas gathered or transported through our pipelines, (ii) the volume of natural gas processed, conditioned, fractionated or treated at our processing plants or on our behalf at third-party processing plants, (iii) natural gas and NGL prices and the relative price differential between NGLs and natural gas, (iv) our contract portfolio and (v) the results of our risk management activities. The results of our risk management activities consist of (i) net cash settlements paid or received on expired commodity derivative instruments, (ii) amortization expense relating to the option component of our commodity derivative instruments and (iii) unrealized mark-to-market gain or loss on our commodity derivative instruments that have not been designated as cash flow hedges.

Because our profitability is a function of the difference between the revenues we receive from our operations, including revenues from the products we sell, and the costs associated with conducting our operations, including the costs of products we purchase, increases or decreases in our revenues alone are not necessarily indicative of increases or decreases in our profitability. To a large extent, our contract portfolio and the pricing environment for natural gas and NGLs will dictate increases or decreases in our profitability. Our profitability is also dependent upon the market demand for natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors.

Both segment gross margin and total segment gross margin are reviewed monthly for consistency and trend analysis.

Operations and Maintenance Expenses.  The most significant portion of our operations and maintenance expenses consists of direct labor, insurance, repair and maintenance, utilities and contract services. These expenses remain relatively stable across broad volume ranges and fluctuate slightly depending on the activities performed during a specific period. A portion of our operations and maintenance expenses is incurred through Copano Operations, an affiliate of our company controlled by John R. Eckel, Jr., the Chairman of our Board of Directors and our Chief Executive Officer. See Note 8 of the notes to the unaudited consolidated financial statements included in Item 1 of this report. Under the terms of our arrangement with Copano Operations, we have agreed to reimburse it, at cost, for the operations and maintenance expenses it incurs on our behalf, which consist primarily of payroll costs. We monitor operations and maintenance expenses to assess the impact of such costs on the profitability of a particular asset or group of assets and to evaluate the efficiency of our operations.

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General and Administrative Expenses.  Our general and administrative expenses include the cost of employee and officer compensation and related benefits, office lease and expenses, professional fees, information technology expenses, as well as other expenses not directly associated with our field operations. A portion of our general and administrative expenses are incurred through Copano Operations, an affiliate of our company. See Note 8 of the notes to the unaudited consolidated financial statements included in Item 1 of this report. Under the terms of our arrangement with Copano Operations, we have agreed to reimburse it, at cost, for the general and administrative expenses it incurs on our behalf. To help ensure the appropriateness of our general and administrative expenses, we monitor such expenses through comparison with general and administrative expenses incurred by similar midstream companies and with the annual financial plan approved by our Board of Directors.

EBITDA and Adjusted EBITDA.  We define EBITDA as net income (loss) plus interest and other financing costs, provision for income taxes and depreciation, amortization and impairment expense. Because a portion of our net income (loss) is attributable to equity in earnings (loss) from our equity investees (which include Bighorn, Fort Union, Webb Duval and Southern Dome), our management also calculates adjusted EBITDA to reflect the depreciation, amortization and impairment expense and interest and other financing costs embedded in the equity in earnings (loss) from unconsolidated affiliates. Specifically, our management determines adjusted EBITDA by adding to EBITDA (i) the amortization expense attributable to the difference between our carried investment in each unconsolidated affiliate and the underlying equity in its net assets, (ii) the portion of each unconsolidated affiliate’s depreciation and amortization expense which is proportional to our ownership interest in that unconsolidated affiliate and (iii) the portion of each unconsolidated affiliate’s interest and other financing costs which is proportional to our ownership interest in that unconsolidated affiliate.

External users of our financial statements such as investors, commercial banks and research analysts use EBITDA or adjusted EBITDA, and our management uses adjusted EBITDA, as a supplemental financial measure to assess:

•  the financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•  the ability of our assets to generate cash sufficient to pay interest costs and support our indebtedness;

•  our operating performance and return on capital as compared to those of other companies in the midstream energy sector, without regard to financing or capital structure; and

•  the viability of acquisitions and capital expenditure projects and the overall rates of return on alternative investment opportunities.

EBITDA is also a financial measure that, with certain negotiated adjustments, is reported to our lenders and used to compute financial covenants under our revolving credit facility. Neither EBITDA nor adjusted EBITDA should be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of liquidity or financial performance presented in accordance with GAAP.

Total Distributable Cash Flow.  We define total distributable cash flow as net income plus: (i) depreciation, amortization and impairment expense (including amortization expense relating to the option component of our risk management portfolio); (ii) cash distributions received from investments in unconsolidated affiliates and equity losses from such unconsolidated affiliates; (iii) provision for deferred income taxes; (iv) the subtraction of maintenance capital expenditures; (v) the subtraction of equity in earnings from unconsolidated affiliates and (vi) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period, such as equity-based compensation, mark-to-market changes in derivative instruments, and our line fill contributions to third-party pipelines and gas imbalances. Maintenance capital expenditures are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows.

Total distributable cash flow is a significant performance metric used by senior management to compare basic cash flows generated by us (prior to the establishment of any retained cash reserves by our Board of Directors) to the cash distributions we expect to pay our unitholders, and it also correlates with the metrics of our existing debt

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covenants. Using total distributable cash flow, management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Total distributable cash flow is also an important non-GAAP financial measure for our unitholders because it serves as an indicator of our success in providing a cash return on investment — specifically, whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Total distributable cash flow is also used by industry analysts with respect to publicly traded partnerships and limited liability companies because the market value of such entities’ equity securities is significantly influenced by the amount of cash they can distribute to unitholders.

Although we have previously reported both distributable cash flow and total distributable cash flow, we determined that total distributable cash flow is a better measure of the rate at which cash available for distribution is generated by our operations than distributable cash flow, which does not add back the amortization expense relating to the option component of our risk management portfolio. Total distributable cash flow should not be considered an alternative to net income, operating income, cash flow from operating activities or any other measure of financial performance presented in accordance with GAAP.

Non-GAAP Financial Measures.  The following table presents a reconciliation of the non-GAAP financial measures of (i) total segment gross margin (which consists of the sum of individual segment gross margins and the results of our risk management activities, which are included in corporate and other) to the GAAP financial measure of operating income, (ii) EBITDA and adjusted EBITDA to the GAAP financial measures of net income and cash flows from operating activities and (iii) total distributable cash flow to the GAAP financial measure of net income, for each of the periods indicated.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(In thousands)
Reconciliation of total segment gross margin to operating income:
Operating income	$	18,146		$	23,867		$	52,149		$	86,897
Add: Operations and maintenance expenses		13,202			15,211			38,764			39,770
Depreciation and amortization		14,575			12,700			41,071			36,929
General and administrative expenses		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 segment gross margin	$	53,430		$	61,373		$	157,467		$	192,263
Reconciliation of EBITDA and adjusted EBITDA to net income:
Net income	$	3,729		$	8,723		$	15,672		$	46,427
Add: Depreciation and amortization(1)		14,628			12,755			41,628			37,092
Interest and other financing costs		15,440			15,470			41,889			42,939
Provision for income taxes		304			197			1,039			846
EBITDA		34,101			37,145			100,228			127,304
Add: Amortization of difference between the carried investment and the underlying equity in net assets of equity investments		4,792			4,607			14,395			13,808
Copano’s share of depreciation and amortization included in equity in earnings from unconsolidated affiliates		1,707			1,266			5,040			3,854
Copano’s share of interest and other financing costs incurred by our equity method investments		615			471			1,093			1,697
Adjusted EBITDA	$	41,215		$	43,489		$	120,756		$	146,663

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	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	(In thousands)
Reconciliation of EBITDA and adjusted EBITDA to cash flows from operating activities:
Cash flow provided by operating activities	$	21,121		$	23,236		$	100,749		$	101,221
Add: Cash paid for interest and other financing costs		14,545			14,537			38,829			40,387
Equity in earnings from unconsolidated affiliates		2,529			2,170			6,112			7,354
Distributions from unconsolidated affiliates		(6,894	)		(6,669	)		(18,333	)		(18,387	)
Risk management activities		(4,983	)		(11,999	)		(23,462	)		16,466
Increase (decrease) in working capital and other		7,783			15,870			(3,667	)		(19,737	)
EBITDA		34,101			37,145			100,228			127,304
Add: Amortization of difference between the carried investment and the underlying equity in net assets of equity investments		4,792			4,607			14,395			13,808
Copano’s share of depreciation and amortization included in equity in earnings from unconsolidated affiliates		1,707			1,266			5,040			3,854
Copano’s share of interest and other financing costs incurred by our equity method investments		615			471			1,093			1,697
Adjusted EBITDA	$	41,215		$	43,489		$	120,756		$	146,663
Reconciliation of net income to total distributable cash flow:
Net income	$	3,729		$	8,723		$	15,672		$	46,427
Add: Depreciation and amortization(1)		14,628			12,755			41,628			37,092
Amortization of commodity derivative options		9,236			8,425			27,715			24,482
Amortization of debt issue costs		895			933			3,060			2,552
Equity-based compensation		2,345			3,285			6,600			5,277
Distributions from unconsolidated affiliates		7,297			7,763			21,524			20,358
Unrealized (gain) loss associated with line fill contributions and gas imbalances		(556	)		2,117			(29	)		(490	)
Unrealized loss (gain) on derivative activity		194			(516	)		(1,442	)		9,485
Deferred taxes and other		68			(6	)		740			161
Less: Equity in earnings from unconsolidated affiliates		(2,529	)		(2,170	)		(6,112	)		(7,354	)
Maintenance capital expenditures		(1,886	)		(2,675	)		(7,932	)		(8,828	)
Total distributable cash flow	$	33,421		$	38,634		$	101,424		$	129,162

(1) Includes activity related to the discontinued operations of the crude oil pipeline and related assets discussed in Item 1, Note 13 to our unaudited consolidated financial statements.

How We Manage Our Operations

Our management team uses a variety of tools to manage our business. These tools include: (i) our economic models and standardized processing margin, (ii) flow and transaction monitoring systems, (iii) producer activity evaluation and reporting and (iv) imbalance monitoring and control.

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Economic Models and Standardized Processing Margin.  We use our economic models to determine (i) whether we should reduce the ethane extracted from natural gas processed by some of our processing plants and third party plants and (ii) whether we should process or condition natural gas at our Houston Central or Saint Jo plants.

To isolate and consistently track changes in commodity price relationships and their impact on our Texas segment’s results from its processing operations, we calculate a hypothetical “standardized” processing margin at our Houston Central plant. Our processing margin refers to the difference between the market value of:

•  NGLs we extract in processing; and

•  the thermal equivalent of natural gas attributable to those NGLs plus the natural gas consumed as fuel in extracting those NGLs.

Our “standardized” processing margin is based on a fixed set of assumptions, with respect to NGL composition and fuel consumption per recovered gallon, which we believe is generally reflective of our business. Because these assumptions are held stable over time, changes in underlying natural gas and NGL prices drive changes in the standardized processing margin. Our results of operations may not necessarily correlate to the changes in our standardized processing margin because of the impact of factors other than commodity prices, such as volumes, changes in NGL composition, recovery rates and variable contract terms. However, we believe this calculation is representative of the current operating commodity price environment of our Texas processing operations, and we use this calculation to track commodity price relationships. Our standardized processing margins averaged $0.45 and $0.56 per gallon during the three months ended September 30, 2009 and 2008, respectively. Our standardized processing margins averaged $0.33 and $0.57 per gallon during the nine months ended September 30, 2009 and 2008, respectively. The average standardized processing margin for the period from January 1, 1989 through September 30, 2009 is $0.14 per gallon.

Flow and Transaction Monitoring Systems.  We use automated systems that track commercial activity on each of our Texas segment pipelines and monitor the flow of natural gas on all of our pipelines. In our Texas segment, we designed and implemented software that tracks each of our natural gas transactions, which allows us to continuously track volumes, pricing, imbalances and estimated revenues from our pipeline assets. Additionally, we use automated Supervisory Control and Data Acquisition (“SCADA”) systems, which assist management in monitoring and operating our Texas segment. These SCADA systems allow us to monitor our assets at remote locations and respond to changes in pipeline operating conditions. For our Oklahoma segment, we electronically monitor pipeline volumes and operating conditions at certain key points along our pipeline systems and use a SCADA system on one of our gathering systems. Bighorn, which our Rocky Mountains segment operates, also uses a SCADA system.

Producer Activity Evaluation and Reporting.  We monitor producer drilling and completion activity in our Texas, Oklahoma and Rocky Mountains areas of operation to identify anticipated changes in production and potential new well connection opportunities. The continued connection of natural gas production to our pipeline systems is critical to our business and directly impacts our financial performance. Using a third-party electronic reporting system, we receive daily reports of new drilling permits and completion reports filed with the state regulatory agency that governs these activities in Texas and Oklahoma. Additionally, our field personnel report the locations of new wells in their respective areas and anticipated changes in production volumes to supply representatives and operating personnel. These processes enhance our awareness of new well activity in our operating areas and allow us to be responsive to producers in connecting new volumes of natural gas to our pipelines. In all our operating segments, we meet with producers to better understand their drilling and production plans, and to obtain drilling schedules, if available, to assist us in anticipating future activity on our pipelines.

Imbalance Monitoring and Control.  We continually monitor volumes received and volumes delivered on behalf of third parties to ensure we remain within acceptable imbalance limits during the calendar month. We seek to reduce imbalances because of the inherent commodity price risk that results when receipts and deliveries of natural gas are not balanced concurrently. We have implemented “cash-out” provisions in many of our transportation and gathering agreements to reduce this commodity price risk. Cash-out provisions require that any imbalance that exists between a third party and us at the end of a calendar month is settled in cash based upon

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a pre-determined pricing formula. These provisions ensure that imbalances under such contracts are not carried forward from month-to-month and revalued at higher or lower prices.

Our Long-Term Growth Strategy

As part of our long-term growth strategy, we continue to review complementary acquisitions of midstream assets in our operating areas as well as capital expenditures to enhance our ability to increase cash flows from our existing assets. We pursue acquisitions and capital projects that we believe will allow us to capitalize on our existing infrastructure, personnel and relationships with producers and customers to provide midstream services. We also evaluate acquisitions in new geographic areas to the extent they offer highly visible cash flows and present growth opportunities similar to those we are pursuing in our existing areas of operations, as well as installation or construction of significant new facilities in such areas. To consummate larger acquisitions or complete significant organic expansion or greenfield projects, we will require access to additional capital on competitive terms. Generally, we believe that, over the long term, our cost of equity capital relative to master limited partnerships (“MLPs”) of similar size will be favorable because, unlike many of our competitors that are MLPs, neither our management nor any other party holds incentive distribution rights that entitle them to increasing percentages of cash distributions as per-unit cash distributions increase. If possible under then-existing market conditions, we intend to finance future large acquisitions primarily through the issuance of debt and equity. For a more detailed discussion of our capital resources, including the effects of capital market conditions on our ability to implement our growth strategy, please read “— Liquidity and Capital Resources.”

In analyzing a particular acquisition, expansion or greenfield project, we consider the operational, financial and strategic benefits of the transaction. Our analysis includes location of the assets or projects, strategic fit in relation to our business strategy, expertise and management personnel required, capital required to integrate and maintain the assets involved, and the surrounding competitive environment. From a financial perspective, we analyze the rate of return the assets will generate in comparison to our cost of capital under various commodity price scenarios, comparative market parameters and the anticipated earnings and cash flow capabilities of the assets.

Forward-Looking Statements

This report contains certain “forward-looking statements” within the meaning of the federal securities laws. All statements, other than statements of historical fact included in this report, including, but not limited to, those under “— Our Results of Operations” and “— Liquidity and Capital Resources” are forward-looking statements. Statements included in this report that are not historical facts, but that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as references to future goals or intentions or other such references are forward-looking statements. These statements can be identified by the use of forward-looking terminology including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements include assertions related to plans for growth of our business, future capital expenditures and competitive strengths and goals. We make these statements based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed, implied or forecasted in these statements. Any differences could be caused by a number of factors, including, but not limited to:

•  our ability to successfully integrate any acquired asset or operations;

•  the volatility of prices and market demand for natural gas and NGLs;

•  our ability to continue to obtain new sources of natural gas supply;

•  our ability to access NGL fractionation capacity;

•  the ability of key producers to continue to drill and successfully complete and attach new natural gas supplies;

•  our ability to retain key customers;

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•  the availability of local, intrastate and interstate transportation systems and other facilities for natural gas and NGLs;

•  our ability to access our revolving credit facility and to obtain additional financing on acceptable terms;

•  the effectiveness of our hedging program;

•  general economic conditions;

•  the effects of government regulations and policies; and

•  other financial, operational and legal risks and uncertainties detailed from time to time in our filings with the SEC.

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this report, including in conjunction with the forward-looking statements referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth under Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2008 and our Quarterly Report on Form 10-Q for the three months ended June 30, 2009. All forward-looking statements included in this report and all subsequent written or oral forward-looking statements attributable to us or persons acting on our behalf are expressly qualified in their entirety by these cautionary statements. The forward-looking statements speak only as of the date made, and we undertake no obligation to publicly update or revise any forward-looking statements, other than as required by law, whether as a result of new information, future events or otherwise.

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Our Results of Operations

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2009			2008			2009			2008
	($ in thousands)
Total segment gross margin(1)(2)	$	53,430		$	61,373		$	157,467		$	192,263
Operations and maintenance expenses(2)		13,202			15,211			38,764			39,770
Depreciation and amortization(2)		14,575			12,700			41,071			36,929
General and administrative expenses		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	)
Operating income(2)		18,146			23,867			52,149			86,897
Gain on retirement of unsecured debt		—			—			3,939			—
Interest and other financing costs, net		(14,375	)		(15,113	)		(40,770	)		(41,848	)
Provision for income taxes		(304	)		(197	)		(1,039	)		(846	)
Discontinued operations, net of tax		262			166			1,393			2,224
Net income	$	3,729		$	8,723		$	15,672		$	46,427
Segment gross margin:
Oklahoma(2)	$	18,284		$	33,132		$	50,058		$	115,052
Texas		26,875			41,392			70,775			123,467
Rocky Mountains		634			1,257			2,144			3,438
Segment gross margin(2)		45,793			75,781			122,977			241,957
Corporate and other(3)		7,637			(14,408	)		34,490			(49,694	)
Total segment gross margin(1)(2)	$	53,430		$	61,373		$	157,467		$	192,263
Segment gross margin per unit:
Oklahoma:
Service throughput ($/MMBtu) (2)(4)	$	0.76		$	1.48		$	0.69		$	1.81
Texas:
Service throughput ($/MMBtu)(5)	$	0.48		$	0.67		$	0.41		$	0.65
Rocky Mountains:
Producer services throughput ($/MMBtu)(6)	$	0.03		$	0.06		$	0.04		$	0.05
Volumes:
Oklahoma:(4)(7)
Service throughput (MMBtu/d)		260,296			243,000			266,306			231,358
Plant inlet volumes (MMBtu/d)		166,884			158,047			164,741			154,708
NGLs produced (Bbls/d)		16,474			15,238			15,928			15,083
Texas:(5)(8)
Service throughput (MMBtu/d)		613,234			666,686			629,367			688,694
Pipeline throughput (MMBtu/d)		296,003			301,279			296,621			314,740
Plant inlet volumes (MMBtu/d)		543,994			596,225			553,876			610,470
NGLs produced (Bbls/d)		18,197			16,957			17,846			17,584
Rocky Mountains:
Producer services throughput (MMBtu/d)(6)		157,362			230,859			168,168			229,038
Capital Expenditures:
Maintenance capital expenditures	$	1,886		$	2,675		$	7,932		$	8,828
Expansion capital expenditures		17,283			45,928			42,119			128,593
Total capital expenditures	$	19,169		$	48,603		$	50,051		$	137,421
Operations and maintenance expenses:
Oklahoma(2)	$	6,111		$	6,170		$	17,335		$	17,860
Texas		7,089			9,041			21,423			21,910
Rocky Mountains		2			—			6			—
Total operations and maintenance expenses(2)	$	13,202		$	15,211		$	38,764		$	39,770

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(1)	Total segment gross margin is a non-GAAP financial measure. See “— How We Evaluate Our Operations” for a reconciliation of total segment gross margin to its most directly comparable GAAP measure of operating income.
(2)	Excludes results attributable to our crude oil pipeline and related assets. See Item 1, Note 13 to our unaudited consolidated financial statements entitled “Discontinued Operations.”
(3)	Corporate and other includes results attributable to Copano’s commodity risk management activities.
(4)	Excludes volumes associated with our interest in Southern Dome. For the three months ended September 30, 2009, plant inlet volumes for Southern Dome averaged 13,857 MMBtu/d and NGLs produced averaged 523 Bbls/d. For the three months ended September 30, 2008, plant inlet volumes for Southern Dome averaged 11,557 MMBtu/d and NGLs produced averaged 389 Bbls/d. For the nine months ended September 30, 2009, plant inlet volumes for Southern Dome averaged 13,304 MMBtu/d and NGLs produced averaged 490 Bbls/d. For the nine months ended September 30, 2008, plant inlet volumes for Southern Dome averaged 10,503 MMBtu/d and NGLs produced averaged 387 Bbls/d.
(5)	Excludes results and volumes associated with our interest in Webb Duval. Volumes transported by Webb Duval, net of intercompany volumes, were 72,985 MMBtu/d and 97,906 MMBtu/d for the three months ended September 30, 2009 and 2008, respectively. Volumes transported by Webb Duval, net of intercompany volumes, were 82,001 MMBtu/d and 91,047 MMBtu/d for the nine months ended September 30, 2009 and 2008, respectively.
(6)	Producer services throughput consists of volumes we purchased for resale, volumes gathered under our firm capacity gathering agreements with Fort Union and volumes transported using our firm capacity agreements with WIC. Excludes results and volumes associated with our interests in Bighorn and Fort Union. Volumes transported by Bighorn were 190,229 MMBtu/d and 211,353 MMBtu/d for the three months ended September 30, 2009 and 2008, respectively. Volumes transported by Fort Union were 761,897 MMBtu/d and 735,131 MMBtu/d for the three months ended September 30, 2009 and 2008, respectively. Volumes transported by Bighorn were 192,500 MMBtu/d and 215,568 MMBtu/d for the nine months ended September 30, 2009 and 2008, respectively. Volumes transported by Fort Union were 786,908 MMBtu/d and 712,791 MMBtu/d for the nine months ended September 30, 2009 and 2008, respectively.
(7)	Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Oklahoma segment at all plants, including our owned plants and plants owned by third parties. For the three months ended September 30, 2009, plant inlet volumes averaged 129,832 MMBtu/d and NGLs produced averaged 13,410 Bbls/d for plants owned by the Oklahoma segment. For the three months ended September 30, 2008, plant inlet volumes averaged 119,332 MMBtu/d and NGLs produced averaged 12,042 Bbls/d for plants owned by the Oklahoma segment. For the nine months ended September 30, 2009, plant inlet volumes averaged 127,067 MMBtu/d and NGLs produced averaged 12,970 Bbls/d for plants owned by the Oklahoma segment. For the nine months ended September 30, 2008, plant inlet volumes averaged 111,137 MMBtu/d and NGLs produced averaged 11,343 Bbls/d for plants owned by the Oklahoma segment.
(8)	Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Texas segment at all plants, including plants owned by the Texas segment and plants owned by third parties. Plant inlet volumes averaged 537,099 MMBtu/d and NGLs produced averaged 17,653 Bbls/d for the three months ended September 30, 2009 for plants owned by the Texas segment. Plant inlet volumes averaged 586,243 MMBtu/d and NGLs produced averaged 16,177 Bbls/d for the three months ended September 30, 2008 for plants owned by the Texas segment. Plant inlet volumes averaged 537,382 MMBtu/d and NGLs produced averaged 16,504 Bbls/d for the nine months ended September 30, 2009 for plants owned by the Texas segment. Plant inlet volumes averaged 601,831 MMBtu/d and NGLs produced averaged 16,423 Bbls/d for the nine months ended September 30, 2008 for plants owned by the Texas segment.

Three Months Ended September 30, 2009 Compared with Three Months Ended September 30, 2008

Net income decreased by 57% to $3.7 million, or $0.06 per unit on a diluted basis, for the three months ended September 30, 2009 compared to net income of $8.7 million, or $0.15 per unit on a diluted basis, for the three months ended September 30, 2008. The drivers of our net income for 2009 compared to 2008 included:

•  a decrease in total segment gross margin of $7.9 million consisting of a $29.9 million decrease in operating segment gross margins primarily reflecting average NGL price declines of 54% in the Conway index and 49% in the Mt. Belvieu index and lower overall service throughput volumes, offset by an increase of $22 million from our commodity risk management activities; and

•  an increase in depreciation and amortization expenses of $1.9 million primarily related to our expanded operations in north Texas;

partially offset by:

•  a decrease in operations and maintenance expenses of $2.0 million and general and administrative expenses of $1.8 million primarily related to our successful cost reduction efforts, including reduced employee compensation expense and third-party service provider fees;

•  an increase of $0.4 million in equity in earnings of our unconsolidated affiliates; and

•  an increase in interest and other income of $0.7 million.

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Oklahoma Segment Gross Margin.  Oklahoma segment gross margin was $18.3 million for the three months ended September 30, 2009 compared to $33.1 million for the three months ended September 30, 2008, a decrease of $14.8 million, or 45%. The decrease in segment gross margin resulted primarily from period over period decreases in average natural gas and NGL prices of 65% and 54%, respectively. The Oklahoma segment gross margin per unit of service throughput decreased $0.72 per MMBtu to $0.76 per MMBtu for the three months ended September 30, 2009 compared with $1.48 per MMBtu for the third quarter of 2008. The reduction in segment gross margin was partially offset by increases in NGLs produced, plant inlet volumes and service throughput of 8%, 6% and 7%, respectively. NGLs produced at the Paden plant increased 13% during the three months ended September 30, 2009 as compared to the three months ended September 30, 2008. The increase in throughput is primarily attributable to the residual effects of drilling activity initiated during the favorable pricing environment in early 2008. Please read “— Trends and Uncertainties — Market and Industry Trends.” The Oklahoma segment included our crude oil pipeline activities through September 30, 2009. The segment gross margin results above exclude $0.7 million and $0.4 million related to our crude oil pipeline activities for the three months ended September 30, 2009 and 2008, respectively.

Texas Segment Gross Margin.  Texas segment gross margin was $26.9 million for the three months ended September 30, 2009 compared to $41.4 million for the three months ended September 30, 2008, a decrease of $14.5 million, or 35%. The decrease in segment gross margin was primarily attributable to a decline in average NGL prices which decreased 49% from the three months ended September 30, 2008 and an 8% and 9% decline in service throughput and plant inlet volumes, respectively, from the three months ended September 30, 2008. Volumes originating from the Texas segment and delivered to the plant decreased approximately 7% from the third quarter of last year whereas natural gas delivered to the plant and originated from sources other than the Texas segment decreased approximately 23% from the third quarter of 2008. The decrease in Texas segment gross margin was partially offset by lower average natural gas prices, which decreased 67% compared to the three months ended September 30, 2008 and a 7% increase in NGLs produced compared to the three months ended September 30, 2008. The Texas segment gross margin per unit of service throughput decreased $0.19 per MMBtu to $0.48 per MMBtu for the three months ended September 30, 2009, compared with $0.67 per MMBtu for the three months ended September 30, 2008. The decrease in segment gross margin per unit of service throughput was attributable to lower realized prices for NGLs. Please read “— Trends and Uncertainties — Market and Industry Trends.”

Rocky Mountains Segment Gross Margin.  Rocky Mountains gross margin was $0.6 million for the three months ended September 30, 2009 compared with $1.3 million for the three months ended September 30, 2008, a decrease of $0.7 million, or 54%. This decrease is primarily the result of lower volumes and unit margins, as producers have cut back drilling programs and temporarily ceased production on marginal wells in response to the continuing weaker price environment.

Corporate and Other.  Corporate and other gross margin includes our commodity risk management activities and was a gain of $7.6 million for the three months ended September 30, 2009 compared to a loss of $14.4 million for the three months ended September 30, 2008. The gain for the three months ended September 30, 2009 includes $16.4 million of net cash settlements received on expired commodity derivative instruments and $0.4 million of unrealized mark-to-market gains on our commodity derivative instruments offset by $9.2 million of non-cash amortization expense relating to the option component of our commodity derivative instruments. The loss for the three months ended September 30, 2008 consists of $8.4 million of non-cash amortization expense relating to the option component of our commodity derivative instruments, $1.0 million of unrealized mark-to-market losses on our commodity derivative instruments and $7.0 million of net cash settlements paid on expired commodity derivative instruments.

Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $13.2 million for the three months ended September 30, 2009 compared with $15.2 million for the three months ended September 30, 2008. The reduction in operations and maintenance expenses is due to lower lease expenses since we completed our Saint Jo plant, decreased costs for chemicals, utilities and repair and maintenance and our cost control efforts.

Depreciation and Amortization.  Depreciation and amortization totaled $14.6 million for the three months ended September 30, 2009 compared with $12.7 million for the three months ended September 30, 2008, an increase of 15%. This increase relates primarily to additional depreciation and amortization recognized for capital expenditures made subsequent to September 30, 2008, including expenditures relating to construction of our Saint Jo plant.

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General and Administrative Expenses.  General and administrative expenses totaled $9.2 million for the three months ended September 30, 2009 compared with $11.0 million for the three months ended September 30, 2008. The 16% decrease consists primarily of (i) $1.6 million reduction in personnel, consultants, insurance, compensation and benefits costs, (ii) a reduction in legal and accounting fees of $0.2 million, (iii) a $0.1 million reduction of costs associated with our Rocky Mountains segment and (iv) a $0.2 million reduction of costs associated with our Oklahoma segment. These reductions in costs were partially offset by (i) an increase of $0.1 million non-cash compensation expense related to amortization of the fair value of restricted units, phantom units, unit options and unit appreciation rights issued under our LTIP, (ii) an increase in costs of preparing and processing tax K-1s to unitholders of $0.1 million and (iii) an increase of $0.1 million in expenses associated with acquisition initiatives.

Interest and Other Financing Costs.  Interest and other financing costs totaled $15.4 million for the three months ended September 30, 2009 compared with $15.5 million for the three months ended September 30, 2008, a decrease of $0.1 million, or 1%. Interest expense related to our revolving credit facility totaled $2.4 million (including net settlements paid under our interest rate swaps of $1.5 million and net of $0.6 million of capitalized interest) and $1.2 million (including net settlements paid under our interest rate swaps of $0.7 million and net of $0.8 million of capitalized interest) for the three months ended September 30, 2009 and 2008, respectively. Interest and other financing costs for the three months ended September 30, 2009 includes unrealized mark-to-market losses of $0.6 million on undesignated interest rate swaps. Interest on our senior unsecured notes decreased to $11.6 million for the three months ended September 30, 2009 from $12.9 million for the three months ended September 30, 2008 because we retired $67.8 million aggregate principal of our senior unsecured notes in the fourth quarter of 2008 and the first quarter of 2009. Amortization of debt issue costs totaled $0.9 million for each of the three months ended September 30, 2009 and 2008. Average borrowings under our credit arrangements for the three months ended September 30, 2009 and 2008 were $852.1 million and $751.7 million with average interest rates of 7.2% and 8.3%, respectively. Please read “— Liquidity and Capital Resources — Description of Our Indebtedness.”

Nine Months Ended September 30, 2009 Compared with Nine Months Ended September 30, 2008

Net income decreased by 66% to $15.7 million, or $0.27 per unit on a diluted basis, for the nine months ended September 30, 2009 compared to net income of $46.4 million, or $0.80 per unit on a diluted basis, for the nine months ended September 30, 2008. The drivers of our net income for 2009 compared to 2008 included:

•  a decrease in total segment gross margin of $34.8 million consisting of a $119.0 million decrease in operating segment gross margins, primarily reflecting average NGL price declines of 57% in the Conway index and 54% in the Mt. Belvieu index and lower overall service throughput volumes, offset by an increase of $84.2 million from our commodity risk management activities;

•  an increase in depreciation and amortization expenses of $4.1 million primarily related to our expanded operations in north Texas;

•  a decrease of $1.3 million in equity in earnings of our unconsolidated affiliates; and

•  a decrease in discontinued operations and income taxes of $1.0 million;

partially offset by:

•  a gain of $3.9 million related to the repurchase and retirement of $18.2 million aggregate principal amount of our 7.75% senior unsecured notes due 2018 at market prices averaging 78% of the face amount of the notes;

•  a decrease in general and administrative expenses of $4.6 million and operations and maintenance expenses of $1.0 million primarily related to our successful cost reduction efforts, including reduced employee compensation expense and third-party service provider fees; and

•  a decrease of $1.0 million in interest expense as a result of (i) a decrease of non-cash mark-to-market charges on our interest rate swaps of $5.2 million offset by (ii) an increase in interest expense of $4.2 million due to increased average outstanding borrowings and slightly offset by lower average interest rates between the periods.

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Oklahoma Segment Gross Margin.  Oklahoma segment gross margin was $50.1 million for the nine months ended September 30, 2009 compared to $115.1 million for the nine months ended September 30, 2008, a decrease of $65.0 million, or 56%. The decrease in segment gross margin resulted primarily from period over period decreases in average natural gas and NGL prices of 64% and 57%, respectively. The Oklahoma segment gross margin per unit of service throughput decreased $1.12 per MMBtu to $0.69 per MMBtu for the nine months ended September 30, 2009 compared with $1.81 per MMBtu for the nine month ended September 30, 2008. The reduction in segment gross margin was partially offset by increases in NGLs produced, plant inlet volumes and service throughput of 6%, 6% and 15%, respectively. NGLs produced at the Paden plant increased 16% during the nine months ended September 30, 2009 as compared to the nine months ended September 30, 2008. The increase in throughput is primarily attributable to the residual effects of drilling activity initiated during the favorable pricing environment in early 2008. Please read “— Trends and Uncertainties — Market and Industry Trends.” The Oklahoma segment included our crude oil pipeline activities through September 30, 2009. The segment gross margin results above exclude $2.7 million and $2.9 million related to our crude oil pipeline activities for the nine months ended September 30, 2009 and 2008, respectively.

Texas Segment Gross Margin.  Texas segment gross margin was $70.8 million for the nine months ended September 30, 2009 compared to $123.5 million for the nine months ended September 30, 2008, a decrease of $52.7 million, or 43%. The decrease in segment gross margin was primarily attributable to a decline in average NGL prices which decreased 54% from the nine months ended September 30, 2008 and a 9% and 9% decline in service throughput and plant inlet volume, respectively, from the nine months ended September 30, 2008. Volumes originating from the Texas segment and delivered to the plant decreased approximately 8% from the third quarter of last year whereas natural gas delivered to the plant and originated from sources other than the Texas segment decreased approximately 17% from the third quarter of 2008. The decrease in Texas segment gross margin was partially offset by lower average natural gas prices, which decreased 61% compared to the nine months ended September 30, 2008. The Texas segment gross margin per unit of service throughput decreased $0.24 per MMBtu to $0.41 per MMBtu for the nine months ended September 30, 2009, compared with $0.65 per MMBtu for the nine months ended September 30, 2008. The decrease in segment gross margin per unit of service throughput was attributable to the decrease in the realized prices for NGLs. Please read “— Trends and Uncertainties — Market and Industry Trends.”

Rocky Mountains Segment Gross Margin.  Rocky Mountains gross margin was $2.1 million for the nine months ended September 30, 2009 compared with $3.4 million for the nine months ended September 30, 2008, a decrease of $1.3 million, or 38%. This decrease is primarily the result of lower volumes, which in the first three months of 2009 were largely attributable to unfavorable weather conditions. In the third quarter of 2009, lower volumes have continued as producers have cut back drilling programs and temporarily ceased production on marginal wells in response to the continuing weaker price environment.

Corporate and Other.  Corporate and other gross margin includes our commodity risk management activities and was a gain of $34.5 million for the nine months ended September 30, 2009 compared to a loss of $49.7 million for the nine months ended September 30, 2008. The gain for the nine months ended September 30, 2009 includes $62.3 million of net cash settlements received on expired commodity derivative instruments offset by $0.1 million of unrealized mark-to-market losses on our commodity derivative instruments and $27.7 million of non-cash amortization expense relating to the option component of our commodity derivative instruments. The loss for the nine months ended September 30, 2008 consists of $24.5 million of non-cash amortization expense relating to the option component of our commodity derivative instruments, $5.8 million of unrealized mark-to-market losses on our commodity derivative instruments and $19.4 million of net cash settlements paid on expired commodity derivative instruments.

Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $38.8 million for the nine months ended September 30, 2009 compared with $39.8 million for the nine months ended September 30, 2008. The 3% decrease is primarily attributable to our cost control efforts and decreased costs for chemicals, utilities and repair and maintenance.

Depreciation and Amortization.  Depreciation and amortization totaled $41.1 million for the nine months ended September 30, 2009 compared with $36.9 million for the nine months ended September 30, 2008, an increase

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of 11%. This increase relates primarily to additional depreciation and amortization recognized due to capital expenditures made subsequent to September 30, 2008, including expenditures relating to construction of our Saint Jo plant.

General and Administrative Expenses.  General and administrative expenses totaled $29.2 million for the nine months ended September 30, 2009 compared with $33.8 million for the nine months ended September 30, 2008. The 14% decrease consists primarily of (i) a $4.3 million reduction in personnel, consultants, insurance, compensation and benefits costs, (ii) a reduction in legal and accounting fees of $1.0 million, (iii) a $0.7 million reduction of costs associated with our Rocky Mountains segment, (iv) reduction in costs of preparing and processing tax K-1s to unitholders of $0.3 million and (v) a 0.7 million reduction of costs associated with our Oklahoma segment. These reductions in costs were partially offset by (i) an increase of $0.8 million in expenses associated with acquisition initiatives, and (ii) non-cash compensation expense of $1.5 million related to amortization of the fair value of restricted units, phantom units, unit options and unit appreciation rights issued under our LTIP.

Interest and Other Financing Costs.  Interest and other financing costs totaled $41.9 million for the nine months ended September 30, 2009 compared with $42.9 million for the nine months ended September 30, 2008, a decrease of $1.0 million, or 2%. Interest expense related to our revolving credit facility totaled $5.5 million (including net settlements paid under our interest rate swaps of $3.9 million and net of $3.0 million of capitalized interest) and $6.6 million (including net settlements paid under our interest rate swaps of $1.5 million and net of $2.3 million of capitalized interest) for the nine months ended September 30, 2009 and 2008, respectively. Interest and other financing costs for the nine months ended September 30, 2009 includes unrealized mark-to-market gains of $1.6 million on undesignated interest rate swaps. Interest on our senior unsecured notes increased to $34.9 million for the nine months ended September 30, 2009 from $30.1 million for the nine months ended September 30, 2008 primarily as a result of issuing $300 million of senior unsecured notes on May 16, 2008 partially offset by interest savings as a result of retiring $67.8 million of senior unsecured notes from November 2008 through March 2009. Amortization of debt issue costs totaled $3.1 million and $2.5 million for the nine months ended September 30, 2009 and 2008, respectively. Average borrowings under our credit arrangements for the nine months ended September 30, 2009 and 2008 were $847.5 million and $687.3 million with average interest rates of 7.2% and 7.8%, respectively. Please read “— Liquidity and Capital Resources — Description of Our Indebtedness.”

Gain on Unsecured Debt Retirement.  During the first nine months of 2009, we repurchased and retired $18.2 million aggregate principal amount of our 7.75% senior unsecured notes due 2018 using available cash and borrowings under our revolving credit facility. As a result of repurchasing the notes below par value, we recognized a gain of $3.9 million in the first nine months of 2009.

Cash Flows

The following table summarizes our cash flows for each of the periods indicated as reported in the historical consolidated statements of cash flows found in Item 1 of this report.

	Nine Months Ended September 30,
	2009			2008
	(In thousands)
Net cash provided by operating activities	$	100,749		$	101,221
Net cash used in investing activities		(60,706	)		(146,825	)
Net cash (used in) provided by financing activities		(68,349	)		146,764

Our cash flows are affected by a number of factors, some of which we cannot control. These factors include industry and economic conditions, as well as conditions in the financial markets, prices and demand for our services, volatility in commodity prices or interest rates, effectiveness of our hedging program, operational risks and other factors.

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Operating Cash Flows.  Net cash provided by operating activities was $100.8 million for the nine months ended September 30, 2009 compared to $101.2 million for the nine months ended September 30, 2008. The decrease in cash provided by operating activities of $0.4 million was attributable to the following changes:

•  risk management activities provided an additional $58.9 million of cash flow for the nine months ended September 30, 2009 as compared to the same period in 2008, primarily because we purchased $4.4 million of commodity derivative instruments during the nine months ended September 30, 2009, whereas in the nine months ended September 30, 2008, we used $60.2 million to purchase commodity derivative instruments;

partially offset by:

•  a $55.7 million reduction in operating income (adjusted for the timing of related cash receipts and disbursements) for the nine months ended September 30, 2009 compared with the same period in 2008; and

•  a $3.6 million increase in interest payments for the nine months ended September 30, 2009 compared to the same period in 2008.

Investing Cash Flows.  Net cash used in investing activities was $60.7 million and $146.8 million for the nine months ended September 30, 2009 and 2008, respectively. Investing activities for the nine months ended September 30, 2009 included (i) $59.3 million of capital expenditures related to the construction of our Saint Jo plant and related projects, progress payments for the purchase of compression and constructing well interconnects to attach volumes in new areas, (ii) $3.2 million of investment in Bighorn and (iii) other investing activities of $1.4 million, offset by $3.2 million of distributions from Bighorn, Southern Dome and Webb Duval in excess of equity earnings and other. Investing activities for the nine months ended September 30, 2008 included (i) $120.1 million of capital expenditures related to bolt-on pipeline acquisitions, the expansion and modification of our Paden plant, progress payments for the purchase of compression, construction of the Saint Jo plant and constructing well interconnects to attach volumes in new areas, (ii) $25.6 million of investment in Bighorn and Fort Union and (iii) other investing activities of $3.1 million, offset by (iv) $2.0 million of distributions from Bighorn, Southern Dome and Webb Duval in excess of equity earnings and other.

Financing Cash Flows.  Net cash used in financing activities totaled $68.3 million during the nine months ended September 30, 2009 and included (i) borrowings under our revolving credit facility of $50.0 million and (ii) proceeds from the exercise of unit options of $0.2 million offset by (a) the retirement of $14.3 million aggregate principal amount of our 7.75% senior unsecured notes due 2018, (b) distributions to our unitholders of $94.2 million and (c) the repayment of $10.0 million of our revolving credit facility. Net cash used in financing activities totaled $146.8 million during the nine months ended September 30, 2008 and included (i) borrowing under our revolving credit facility of $225.0 million, (ii) capital contributions of $4.1 million from our pre-IPO investors and (iii) proceeds from the exercise of unit options of $1.0 million, offset by (a) distributions to our unitholders of $76.6 million and (b) deferred financing costs of $6.7 million.

Liquidity and Capital Resources

Sources of Liquidity.  Cash generated from operations, borrowings under our revolving credit facility and funds from equity and debt offerings are our primary sources of liquidity. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations or generate additional revenues, interest payments on our revolving credit facility and senior unsecured notes, distributions to our unitholders and acquisitions of new assets or businesses. Short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our unitholders, are expected to be funded through operating cash flows. Long-term cash requirements for expansion projects and acquisitions are expected to be funded by several sources, including cash flows from operating activities, borrowings under our revolving credit facility and issuances of additional equity and debt securities, as appropriate and subject to market conditions.

Effects of Recent Economic Changes; Outlook.  Commodity prices at the end of 2008 and during 2009, together with the constrained capital and credit markets and overall economic downturn, led to a decline in drilling activity, and in turn a decline in the volumes of natural gas we gathered and processed in the third quarter. Although commodity prices and financial market conditions have begun to recover, improvements in drilling activity remain sporadic, and it remains unclear when producers will undertake sustained increases in drilling activity throughout the areas in which we operate. We have been able to offset the effects of lower prices using commodity derivative

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instruments; however, we cannot use these instruments to offset the effects of lower volumes. In addition, the strike prices of derivative instruments we could acquire today would be reflective of current commodity price forward curve, and therefore would not be as beneficial as strike prices of derivative instruments we acquired during the first half of 2008. Our ability to generate cash from operations, and to comply with the covenants under our debt instruments, will be adversely affected if we experience declining volumes in combination with unfavorable commodity prices over a sustained period.

We believe that cash from operations and our revolving credit facility will provide sufficient liquidity to meet our short-term capital requirements and to fund our committed capital expenditures for at least the next 12 months. If our plans or assumptions change, are inaccurate, or if we make further acquisitions, we may need to raise additional capital. Acquisitions and organic expansion have been, and our management believes will continue to be, key elements of our business strategy. In addition, we consider opportunities for strategic greenfield projects. The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. We may seek to fund all or part of any such efforts with proceeds from debt or equity issuances, or both. Our ability to obtain capital to implement our growth strategy over the longer term will depend upon our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and in the financial markets and other financial and business factors, many of which are beyond our control.

Generally, we believe that financial markets now offer greater liquidity than was available at the height of the financial crisis, but at a higher cost than we would have experienced before the financial crisis.

Capital Expenditures.  The natural gas gathering, transmission and processing businesses are capital-intensive, requiring significant investment to maintain and upgrade existing operations. Our capital requirements have consisted primarily of, and we anticipate will continue to be:

•  maintenance capital expenditures, which are capital expenditures employed to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and

•  expansion capital expenditures, which are capital expenditures made to expand or increase the efficiency of the existing operating capacity of our assets. Expansion capital expenditures include expenditures that facilitate an increase in volumes within our operations, whether through construction or acquisition. Expenditures that reduce our operating costs will be considered expansion capital expenditures only if the reduction in operating expenses exceeds cost reductions typically resulting from routine maintenance.

During the nine months ended September 30, 2009, our capital expenditures totaled $50.1 million, consisting of $8.0 million of maintenance capital and $42.1 million of expansion capital. We funded our capital expenditures with funds from operations and borrowings under our senior credit facility. Expansion capital expenditures were related to the construction and completion of our Saint Jo plant and related downstream natural gas and NGL pipelines for approximately $13.4 million as well as purchasing compressors and constructing well interconnects to attach volumes in new areas. Based on our current scope of operations, we anticipate incurring approximately $10 million to $12 million of maintenance capital expenditures over the next 12 months.

Subject to FERC approval of our acquisition of the McMullen Lateral pipeline, we anticipate that we will incur approximately $95 million in combined acquisition and integration costs. We anticipate making these capital expenditures primarily in 2010 and expect to finance these expenditures with cash from operations and borrowings under our revolving credit facility.

Cash Distributions.  The amount needed to pay the current distribution of $0.575 per unit, or $2.30 per unit annualized, to our common unitholders is as follows (in thousands):

	One Quarter		Four Quarters
Common units(1)	$	31,860	$	127,438

(1) Includes distributions on restricted common units and phantom units issued under our LTIP. Distributions made on restricted units and phantom units issued to date are subject to the same vesting provisions as the restricted units and phantom units. As of November 2, 2009, we had 107,521 outstanding restricted units and 686,475 outstanding phantom units.

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Our Indebtedness

As of September 30, 2009 and December 31, 2008, our aggregate outstanding indebtedness totaled $842.8 million and $821.1 million, respectively, and we were in compliance with our debt covenants.

Credit Ratings.  Moody’s Investors Service has assigned a Corporate Family Rating to us of Ba3 with a stable outlook, a B1 rating for our senior unsecured notes and a Speculative Grade Liquidity rating of SGL-2. Standard & Poor’s Ratings Services has assigned a Corporate Credit Rating of BB- with a stable outlook and a B+ rating for our senior unsecured notes.

Revolving Credit Facility.  As of September 30, 2009, we had $260 million of outstanding borrowings under our $550 million senior secured revolving credit facility with Bank of America, N.A., as Administrative Agent. Our revolving credit facility matures on October 18, 2012. Our revolving credit facility includes 29 lenders with commitments ranging from $1 million to $60 million, with the largest commitment representing 10.9% of the total commitments. Future borrowings under the facility are available for acquisitions, capital expenditures, working capital and general corporate purposes, and the facility may be drawn on and repaid without restriction so long as we are in compliance with its terms, including the financial covenants described below. Our revolving credit facility provides for up to $50 million in standby letters of credit. As of September 30, 2009 and December 31, 2008, we had no letters of credit outstanding. Guaranty Financial Group Inc., a lender under our revolving credit facility whose commitment represents approximately 3% of the total lender commitments, was closed by the Office of Thrift Supervision on August 21, 2009 and all deposits and selected bank assets, including its commitment under our revolving credit facility, were sold to another of our current lenders, BBVA Compass,. We have not experienced any difficulties in obtaining funding from any of our lenders, but the lack of or delay in funding by one or more members of our banking group could negatively affect our liquidity position.

The effective average interest rate on borrowings under the revolving 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 revolving credit facility for those periods, was 0.25%. Interest and other financing costs related to the revolving credit facility totaled $6.2 million and $9.0 million for the nine months ended September 30, 2009 and 2008, respectively.

At September 30, 2009, our ratio of EBITDA (as defined in our revolving credit facility) 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 revolving credit facility at September 30, 2009 was approximately $290 million.

Senior Notes.  At September 30, 2009, we had $332.7 million aggregate principal amount of our 8.125% senior unsecured notes due 2016 (“2016 Notes”) outstanding and $249.5 million aggregate principal amount of our 7.75% senior unsecured notes due 2018 (“2018 Notes”) outstanding. We refer to the 2016 Notes and the 2018 Notes collectively as the “Senior Notes.”

Interest and other financing costs relating to the 2016 Notes totaled $20.9 million and $22.0 million for the nine months ended September 30, 2009 and 2008, respectively. Interest and other financing costs relating to the 2018 Notes, which we issued in May 2008, totaled $15.5 million and $9.0 million for the nine months ended September 30, 2009 and 2008, respectively.

In addition, 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.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of September 30, 2009.

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Recent Accounting Pronouncements

For information on new accounting pronouncements, please read Note 2 to the unaudited consolidated financial statements.

Critical Accounting Policies

Impairment of Long-Lived Assets.  In accordance with FASB ASC 360, “Accounting for the Impairment or Disposal of Long-Lived Assets,” (SFAS No. 144) we evaluate whether long-lived assets, including related intangibles, have been impaired when events or changes in circumstances indicate, in management’s judgment, that the carrying value of such assets may not be recoverable. For such long-lived assets, an impairment exists when its carrying value exceeds the sum of management’s estimate of the undiscounted future cash flows expected to result from the use and eventual disposition of the asset. If the carrying value of the long-lived asset is not recoverable based on these estimated future undiscounted cash flows, the impairment loss is measured as the excess of the asset’s carrying value over its fair value, such that the asset’s carrying value is adjusted to its estimated fair value. For assets identified to be disposed of in the future, the carrying value of these assets is compared to the estimated fair value less the cost to sell to determine if impairment is required. Until the assets are disposed of, an estimate of the fair value is recalculated when related events or circumstances change.

When determining whether impairment of one of our long-lived assets has occurred, we must estimate the undiscounted cash flows attributable to the asset or asset group. Our estimate of cash flows is based on assumptions regarding the asset, including future NGL and natural gas prices and estimated future natural gas production in the region (which is dependent in part on natural gas and NGL prices). Projections of gas volumes and future commodity prices are inherently subjective and contingent upon a number of variable factors, including but not limited to:

•  changes in general economic conditions in which our assets are located;

•  the availability and prices of natural gas supply;

•  improvements in exploration and production technology;

•  the finding and development cost for producers to exploit reserves in a particular area;

•  our ability to negotiate favorable agreements with producers and customers;

•  our dependence on certain significant customers, producers, gatherers and transporters of natural gas; and

•  competition from other midstream service providers, including major energy companies.

Any significant variance in any of the above assumptions or factors could materially affect our cash flows, which could require us to record an impairment of an asset. An estimate of the sensitivity of these assumptions to our estimated future undiscounted cash flows used in our impairment review is not practicable given the extensive array of our assets and the number of assumptions involved in these estimates. However, based on current period assumptions, a decrease in our estimated future undiscounted cash flows associated with certain assets of 10% to 25% could result in a potential impairment of these assets.

A discussion of our additional critical accounting policies for revenue recognition and equity method of accounting for unconsolidated affiliates, which remain unchanged, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Critical Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2008.

Item 3.   Quantitative and Qualitative Disclosures about Market Risk.

Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as options, swaps and other derivatives 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 flows sufficient to meet debt service, required

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capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes.

During the first half of 2008, we acquired commodity derivative instruments at strike prices substantially higher than those available in the current market. Derivative instruments we could acquire today would reflect current commodity price forward curves, and therefore would not be as beneficial as those we acquired during the first half of 2008.

Commodity Price Risk

NGL and natural gas prices are volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty, availability of NGL transportation and fractionation capacity and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices primarily as a result of: (i) processing or conditioning at our processing plants or third-party processing plants and (ii) purchasing and selling or gathering and transporting volumes of natural gas at index-related prices. The following discussion describes our commodity price risks as of September 30, 2009. To the extent that they influence the level of drilling activity, commodity prices also affect all of our segments indirectly.

Oklahoma.  A majority of the processing contracts in our Oklahoma segment are percentage-of-proceeds arrangements. Under these arrangements, we purchase and process natural gas from producers and sell the resulting residue gas and NGL volumes. As payment, we retain an agreed-upon percentage of the sales proceeds, which results in effectively long positions in both natural gas and NGLs. Accordingly, our revenues and gross margins increase as natural gas and NGL prices increase and revenues and gross margins decrease as natural gas and NGL prices decrease. Our Oklahoma segment also has fixed fee-contracts and percentage-of-index contracts.

Texas.  Our Texas pipeline systems purchase natural gas for transportation and resale and also transport and provide other services on a fee-for-service basis. A significant portion of the margins we realize from purchasing and reselling the natural gas is based on a percentage of a stated index price. Accordingly, these margins decrease in periods of low natural gas prices and increase during periods of high natural gas prices. The fees we charge to transport natural gas for the accounts of others are primarily fixed, but our Texas contracts also include a percentage-of-index component in a number of cases.

A significant portion of the gas processed by our Texas segment is processed under keep-whole with fee arrangements. Under these arrangements, increases in NGL prices or decreases in natural gas prices generally have a positive impact on our processing gross margins and, conversely, a reduction in NGL prices or increases in natural gas prices generally negatively impact our processing gross margins. However, the ability of our Houston Central plant to operate in a conditioning mode provides an operational hedge that allows us to reduce our Texas processing operations’ commodity price exposure. In conditioning mode, increases in natural gas prices have a positive impact on our margins.

Rocky Mountains.  Substantially all of our Rocky Mountains contractual arrangements as well as the contractual arrangements of Fort Union and Bighorn are fixed-fee arrangements pursuant to which the gathering fee income represents an agreed rate per unit of throughput. The cash flow from of these arrangements is directly related to natural gas volumes and is not directly affected by commodity prices. To the extent a sustained decline in commodity prices results in a decline in volumes, our cash flow would also decline.

Other Commodity Price Risks.  Although we seek to maintain a position that is substantially balanced between purchases and sales for future delivery obligations, we experience imbalances between our natural gas purchases and sales from time to time. For example, a producer could fail to deliver or deliver in excess of contracted volumes, or a customer could take more or less than contracted volumes. To the extent our purchases and sales of natural gas are not balanced, we face increased exposure to commodity prices with respect to the imbalance.

We purchase and sell natural gas under a variety of pricing arrangements, for example, by reference to first of the month index prices, daily index prices or a weighted average of index prices over a given period. Our goal is to minimize commodity price risk by aligning the combination of pricing methods and indices under which we purchase natural gas in each of our segments with the combination under which we sell natural gas in these segments, although it is not always possible to do so.

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Basis risk is the risk that the value of a hedge may not move in tandem with the value of the actual price exposure that is being hedged. Any disparity in terms, such as product, time or location, between the hedge and the underlying exposure creates the potential for basis risk. Our long position in natural gas in Oklahoma can serve as a hedge against our short position in natural gas in Texas. To the extent we rely on natural gas from our Oklahoma segment, which is priced primarily on the CenterPoint East index, to offset a short position in natural gas in our Texas segment, which is priced on the Houston Ship Channel index, we are subject to basis risk. In addition, we are subject to basis risk to the extent we hedge Oklahoma NGL volumes because, due to the extremely limited forward market for Conway-based hedge instruments, we use Mt. Belvieu priced hedge instruments for our Oklahoma NGL volumes. Although the CenterPoint East and Houston Ship Channel indices and the Mt. Belvieu and Conway indices historically have been highly correlated, they have displayed greater variability since late 2008.

Sensitivity.  In order to calculate the sensitivity of our total segment gross margin to commodity price changes, we adjusted our operating models for actual commodity prices, plant recovery rates and volumes. We have calculated that a $0.01 per gallon change in either direction of NGL prices would have resulted in a corresponding change of approximately $0.4 million to our total segment gross margin for the nine months ended September 30, 2009. We also calculated that a $0.10 per MMBtu increase in the price of natural gas would have resulted in approximately a $0.6 million decrease to our total segment gross margin, and vice versa, for the nine months ended September 30, 2009. These relationships are not necessarily linear. As actual prices have fallen below the strike prices of our hedges in 2009, sensitivity to further changes in commodity prices have been reduced. Also, if processing margins are negative, we can operate our Houston Central plant in a conditioning mode so that additional increases in natural gas prices would have a positive impact on our total segment gross margin.

Risk Management Oversight

We seek to mitigate the price risk of natural gas and NGLs, and our interest rate risk discussed below under “— Interest Rate Risk,” through the use of derivative instruments. These activities are governed by our risk management policy. Our Risk Management Committee is responsible for our compliance with our risk management policy and consists of our Chief Executive Officer, Chief Operating Officer, Chief Financial Officer, and General Counsel, and the President of any operating subsidiary. The Audit Committee of our Board of Directors monitors the implementation of our risk management policy, and we have engaged an independent firm to monitor compliance with our risk management policy.

Derivatives transactions may be executed by our Chief Financial Officer, our Chief Executive Officer or our Chief Operating Officer. All derivatives transactions must be authorized in advance of execution by both our Chief Executive Officer and our Chief Operating Officer.

As of September 30, 2009, we were in compliance with our risk management policy.

Commodity Price Hedging Activities

Permitted Derivative Instruments.  Our risk management policy allows our management to:

•  purchase put options or “put spreads” (purchase of a put and a sale of a put at a lower strike price) on WTI crude oil to hedge NGLs produced or condensate collected by us or an entity or asset to be acquired by us if a binding purchase and sale agreement has been executed (a “Pending Acquisition”);

•  purchase put or call options, enter into collars (purchase of a put together with the sale of a call) or “call or put spreads” ((i) purchase of a call and a sale of a call at a higher strike price or (ii) purchase of a put and a sale of a put at a lower strike price),fixed-for-floating swaps, or floating-for-floating swaps (basis swaps) on natural gas at Henry Hub, Houston Ship Channel or other highly liquid points relevant to our operations or a Pending Acquisition;

•  purchase put options, enter into collars or “put spreads” (purchase of a put and a sale of a put at a lower strike price) and/or sell fixed for floating swaps on NGLs to which we, or a Pending Acquisition, has direct price exposure, priced at Mt. Belvieu or Conway; and

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•  purchase put options and collars and/or sell fixed for floating swaps on the “fractionation spread” or the “processing margin spread” for any processing plant relevant to our operations or a Pending Acquisition.

Limitations.  Our policy also limits the maturity and notional amounts of our derivatives transactions as follows:

•  Maturities with respect to the purchase of any crude oil, natural gas, NGLs, fractionation spread or processing margin spread hedge instruments must be limited to five years from the date of the transaction;

•  Except as provided below under “Exception to Volume Limitations,” we may not (i) purchase crude oil or NGLs put options, (ii) purchase natural gas put or call options, (iii) purchase fractionation spread or processing margin spread put options or (iv) enter into any crude oil, natural gas or NGLs spread options permitted by the policy if, as a result of the proposed transaction, net notional hedged volumes with respect to the underlying hedged commodity would exceed 80% of the projected requirements or output, as applicable, for the hedged period . We are required to divest outstanding hedge positions only to the extent net notional hedged volumes with respect to an underlying hedged commodity exceed 100% of the projected requirements or output, as applicable, for the hedged period;

•  The aggregate volumetric exposure associated with swaps (other than basis swaps), collars and written calls relating to any product must not exceed the lesser of 50% of the aggregate hedged position or 35% of the projected requirements or output with respect to such product; and

•  We may not enter into a basis swap if, as a result of the proposed transaction, net notional hedged volumes with respect to the underlying hedged basis would exceed 80% of the projected requirements or output, as applicable, for the hedged period. We are required to divest outstanding basis swaps only to the extent net notional hedged volumes with respect to an underlying hedged basis exceed 100% of the projected requirements or output, as applicable, for the hedged period.

Our policy of limiting swaps (other than basis swaps) relating to any product to the lesser of a percentage of our overall hedge position or a percentage of the related projected requirements or output is intended to avoid risk associated with potential fluctuations in output volumes that may result from conditioning elections or other operational circumstances.

Exception to Volume Limitations.  The volume limitations under our risk management policy provide that the notional amounts of put options with strike prices that are greater than 33% out-of-the-money (market price exceeds strike price by greater than 33%) may be excluded from the notional volume limitations for so long as such put options remain out-of-the-money. In the event that the strike price of such a put option returns to being in-the-money, the instrument’s notional amount would again be included in the volume limitations. If the reversal of a prior exclusion results in an over-hedged notional position, we will be required to become compliant with the notional volume limitations within 30 days of the reversal.

Approved Markets.  Our risk management 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. All of our hedge counterparties are also lenders under our senior credit facility, and the payment obligations in connection with our hedge transactions are secured by a first priority lien on 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. We have not executed any derivative transactions on the NYMEX as of September 30, 2009.

We will seek, whenever possible, to enter into hedge transactions that meet the requirements for effective hedges as outlined in FASB ASC 815 (SFAS No. 133).

Oklahoma Segment.  Natural gas for our Oklahoma segment is hedged using the CenterPoint East index. Currently, the principal indices used to price the underlying commodity for our Oklahoma segment are the ONEOK

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Gas Transportation index and the CenterPoint East index. While this creates the potential for basis risk, statistical analysis reveals that the CenterPoint East index and the ONEOK Gas Transportation index historically have been highly correlated. With the exception of condensate, NGLs are contractually priced using the Conway index, but because there is an extremely limited forward market for Conway-based hedge instruments, we use the Mt. Belvieu index for NGL hedges. This creates the potential for basis risk. Since September 2008, prices on these indices have varied at differing rates, and in the third quarter of 2009, the basis between the Conway index and the Mt. Belvieu index widened. However, the recent price variations are inconsistent with historical statistical analysis indicating that the two indices have been highly correlated.

Texas Segment.  With the exception of condensate and a portion of our natural gasoline production, NGLs are hedged using the Mt. Belvieu index, the same index used to price the underlying commodities. We use natural gas call spread options to hedge a portion of our net operational short position in natural gas when we operate in a processing mode at our Houston Central plant. The call spread options are based on the Houston Ship Channel index, the same index used to price the underlying commodity. We do not hedge against potential declines in the price of natural gas for the Texas segment because our natural gas position is neutral to short due to our contractual arrangements and the ability of the Houston Central plant to switch between full recovery and conditioning mode.

Rocky Mountains Segment.  Because the profitability of our Rocky Mountains segment is only indirectly affected by the level of commodity prices, this segment has no outstanding transactions to hedge commodity price risk.

Our Commodity Hedge Portfolio.  As of September 30, 2009, our commodity hedge portfolio totaled a net asset of $70.2 million, which consists of assets aggregating $78.5 million and liabilities aggregating $8.3 million. See Note 11 to the consolidated financial statements included in Item 1 of this report for tables summarizing our commodity hedge portfolio as of September 30, 2009.

Interest Rates.  Our interest rate exposure results from variable rate borrowings under our revolving credit facility. We manage a portion of our interest rate exposure using interest rate swaps, which allow us to convert a portion of variable rate debt into fixed rate debt. These activities are governed by our risk management policy, which limits the maturity and notional amounts of our interest rate swaps as well as restricts counterparties to lenders under our revolving credit facility.

As of September 30, 2009, the fair value of our interest rate swaps liability totaled $9.5 million. See Note 11 to the consolidated financial statements included in Item 1 of the report for additional information on our interest rate swaps.

The interest rates we are charged under our revolving credit facility are subject to conditions in the financial markets. Our rates may increase in the event of adverse developments such as a lack of liquidity or instability of one or more major financial institutions. To the extent we have not used interest rate swaps to mitigate our exposure, increases in interest rates will affect our cash flow and profitability.

Counterparty Risk.  We are diligent in attempting to ensure that we provide credit only to credit-worthy customers. However, our purchase and resale of natural gas exposes us to significant credit risk, as our margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss could be very large relative to our overall profitability. For the nine months ended September 30, 2009, ONEOK Energy Services, L.P. (14%), ONEOK Hydrocarbons, L.P. (14%), Enterprise Products Operating, L.P. (11%), BP Oil Supply (9%), Kinder Morgan Texas Pipeline, L.P. (7%) Teppco Crude Oil, LLC (5%) and Duke Energy (5%) collectively, accounted for approximately 65% of our revenue. As of September 30, 2009, all of these companies, or their parent companies, were rated investment grade by Moody’s Investors Service and Standard & Poor’s Ratings Services. Companies accounting for another approximately 25% of our revenue either have an investment grade parent or are themselves investment grade, have provided us with credit support in the form of a letter of credit issued by an investment grade financial institution or have provided prepayment for our services.

We also diligently review the creditworthiness of other counterparties to which we may have credit exposure, including hedge counterparties. Our risk management policy requires that we review and report the credit ratings of our hedging counterparties on a monthly basis. As of September 30, 2009, Barclays Bank PLC (37%), Deutsche Bank AG (31%), The Goldman Sachs Group, Inc. (16%), JP Morgan, (6%) and Wells Fargo Bank, N.A. (5%)

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accounted for approximately 95% of the value of our net commodity hedging positions. As of September 30, 2009, all of these counterparties were rated A1 and A or better by Moody’s Investors Service and Standard & Poor’s Ratings Services. Our hedge counterparties have not posted collateral to secure their obligations to us.

We have historically experienced minimal collection issues with our counterparties; however, nonpayment or nonperformance by one or more significant counterparties could adversely impact our liquidity. Please read Item 1A, “Risk Factors,” in our annual report on Form 10-K for 2008.

Item 4.   Controls and Procedures.

Under the direction of our Chief Executive Officer and Chief Financial Officer, we evaluated our disclosure controls and procedures and internal control over financial reporting and our Chief Executive Officer and Chief Financial Officer concluded that (i) our disclosure controls and procedures were effective as of September 30, 2009 and (ii) no change in internal control over financial reporting occurred during the quarter ended September 30, 2009 that has materially affected, or is reasonably likely to materially affect, such internal control over financial reporting.

The quarter ended September 30, 2009 was our first reporting period using our newly implemented financial accounting system, which became operational July 1, 2009. The system implementation integrated all Copano entities on a single financial accounting and planning platform and was undertaken to enhance our reporting procedures, eliminate manual processes and reduce third-party costs. The implementation of our new accounting system was not in response to any identified deficiency or weakness in our internal controls over financial reporting.

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PART II-OTHER INFORMATION

Item 1.   Legal Proceedings.

See Part I, Item 1, Note 9 to our consolidated financial statements entitled “Commitments and Contingencies,” which is incorporated in this item by reference.

Item 1A.   Risk Factors.

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described under Item 1A, “Risk Factors,” in our Annual Report on Form 10-K for the year ended December 31, 2008 and our Quarterly Report on Form 10-Q for the three months ended June 30, 2009. These risks and uncertainties could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be materially adversely affected.

Item 6.   Exhibits.

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) and are filed herewith; all exhibits not so designated are incorporated herein by reference to a prior filing as indicated.

Number			Description
	2	.1	Purchase Agreement dated as of August 31, 2007 among Copano Energy, L.L.C., Copano Energy/Rocky Mountains, L.L.C., and Cantera Resources Holdings LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed October 25, 2007).
	2	.2	Contribution Agreement dated as of April 5, 2007 by and among Cimmarron Gathering GP, LLC, Taos Gathering, LP and Cimmarron Transportation, L.L.C. and Copano Energy, L.L.C. (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed April 11, 2007).
	3	.1	Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 filed July 30, 2004).
	3	.2	Certificate of Amendment to Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-1 filed July 30, 2004).
	3	.3	Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed April 30, 2007).
	3	.4	Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed May 4, 2007).
	3	.5	Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. dated October 19, 2007 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed October 25, 2007).
	3	.6	Amendment No. 3 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C., dated October 19, 2007 (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K filed October 25, 2007).
	4	.1	Indenture dated as of February 7, 2006, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Guarantors parties thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed February 8, 2006).
	4	.2	Rule 144A Global Note representing $224,500,000 principal amount of 8.125% Senior Notes due 2016 (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed February 8, 2006).
	4	.3	Regulation S Global Note representing $500,000 principal amount of 8.125% Senior Notes due 2016 (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed February 8, 2006).
	4	.4	Registration Rights Agreement dated as of May 1, 2007, by and among Copano Energy, L.L.C. and Cimmarron Gathering GP, LLC, Taos Gathering, LP and Cimmarron Transportation, LLC (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed May 4, 2007).

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Number			Description
	4	.5	Registration Rights Agreement by and between Copano Energy, L.L.C. and Cantera Resources Holdings LLC, dated October 19, 2007 (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed October 25, 2007).
	4	.6	Registration Rights Agreement by and among Copano Energy, L.L.C. and the Purchasers, dated October 19,2007 (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed October 25, 2007).
	4	.7	Indenture, dated May 16, 2008, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed May 19, 2008).
	4	.8	Form of Global Note representing 7.75% Senior Notes due 2018 (included in 144A/Regulation S Appendix to Exhibit 4.7 above).
	4	.9	Registration Rights Agreement, dated May 16, 2008, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Subsidiary Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed May 19, 2008).
	10	.1	Form of Unit Appreciation Right Award Agreement (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed May 18, 2009).
	10	.2	Amendment to Amended and Restated Copano Energy, L.L.C. Long-Term Incentive Plan (incorporated by reference to Exhibit 99.2 to Current Report on Form 8-K filed May 18, 2009).
	10	.3	Form of Unit Appreciation Right Award Agreement (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed August 18, 2009).
	31	.1*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
	31	.2*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
	32	.1*	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
	32	.2*	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.

* Filed herewith.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on November 6, 2009.

Copano Energy, L.L.C.

By:  /s/  R. Bruce Northcutt

R. Bruce Northcutt

President and Chief Operating Officer

(Principal Executive Officer)

By:  /s/  Carl A. Luna

Carl A. Luna

Senior Vice President and Chief Financial Officer

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INDEX TO EXHIBITS

Number			Description
	2	.1	Purchase Agreement dated as of August 31, 2007 among Copano Energy, L.L.C., Copano Energy/Rocky Mountains, L.L.C., and Cantera Resources Holdings LLC (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed October 25, 2007).
	2	.2	Contribution Agreement dated as of April 5, 2007 by and among Cimmarron Gathering GP, LLC, Taos Gathering, LP and Cimmarron Transportation, L.L.C. and Copano Energy, L.L.C. (incorporated by reference to Exhibit 2.1 to Current Report on Form 8-K filed April 11, 2007).
	3	.1	Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 filed July 30, 2004).
	3	.2	Certificate of Amendment to Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-1 filed July 30, 2004).
	3	.3	Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed April 30, 2007).
	3	.4	Amendment No. 1 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed May 4, 2007).
	3	.5	Amendment No. 2 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. dated October 19, 2007 (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed October 25, 2007).
	3	.6	Amendment No. 3 to Third Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C., dated October 19, 2007 (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K filed October 25, 2007).
	4	.1	Indenture dated as of February 7, 2006, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Guarantors parties thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed February 8, 2006).
	4	.2	Rule 144A Global Note representing $224,500,000 principal amount of 8.125% Senior Notes due 2016 (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed February 8, 2006).
	4	.3	Regulation S Global Note representing $500,000 principal amount of 8.125% Senior Notes due 2016 (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed February 8, 2006).
	4	.4	Registration Rights Agreement dated as of May 1, 2007, by and among Copano Energy, L.L.C. and Cimmarron Gathering GP, LLC, Taos Gathering, LP and Cimmarron Transportation, LLC (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed May 4, 2007).
	4	.5	Registration Rights Agreement by and between Copano Energy, L.L.C. and Cantera Resources Holdings LLC, dated October 19, 2007 (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed October 25, 2007).
	4	.6	Registration Rights Agreement by and among Copano Energy, L.L.C. and the Purchasers, dated October 19,2007 (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed October 25, 2007).
	4	.7	Indenture, dated May 16, 2008, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed May 19, 2008).
	4	.8	Form of Global Note representing 7.75% Senior Notes due 2018 (included in 144A/Regulation S Appendix to Exhibit 4.7 above).
	4	.9	Registration Rights Agreement, dated May 16, 2008, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Subsidiary Guarantors named therein and the Initial Purchasers named therein (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed May 19, 2008).
	10	.1	Form of Unit Appreciation Right Award Agreement (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed May 18, 2009).
	10	.2	Amendment to Amended and Restated Copano Energy, L.L.C. Long-Term Incentive Plan (incorporated by reference to Exhibit 99.2 to Current Report on Form 8-K filed May 18, 2009).

Number			Description
	10	.3	Form of Unit Appreciation Right Award Agreement (incorporated by reference to Exhibit 99.1 to Current Report on Form 8-K filed August 18, 2009).
	31	.1*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
	31	.2*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
	32	.1*	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
	32	.2*	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.

* Filed herewith.

EX-31.1

Exhibit 31.1

CERTIFICATION

I, R. Bruce Northcutt, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Copano Energy, L.L.C.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 6, 2009

/s/ R. Bruce Northcutt  

R. Bruce Northcutt 

President and Chief Operating Officer 

(Principal Executive Officer) 

EX-31.2

Exhibit 31.2

CERTIFICATION

I, Carl A. Luna, certify that:

1.	I have reviewed this quarterly report on Form 10-Q of Copano Energy, L.L.C.;
2.	Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;
3.	Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;
4.	The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a)	Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;
b)	Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;
c)	Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and
d)	Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s Board of Directors (or persons performing the equivalent functions):

a)	All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and
b)	Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: November 6, 2009

/s/ Carl A. Luna  

Carl A. Luna 

Senior Vice President and Chief Financial Officer 

EX-32.1

Exhibit 32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the accompanying Quarterly Report of Copano Energy, L.L.C. (the “Company”) on Form 10-Q for the quarter ended September 30, 2009 (the “Report”) filed with the Securities and Exchange Commission on November 6, 2009, I, R. Bruce Northcutt, President and Chief Operating Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ R. Bruce Northcutt  

R. Bruce Northcutt 

President and Chief Operating Officer 

(Principal Executive Officer) 

EX-32.2

Exhibit 32.2

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ADOPTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

     In connection with the accompanying Quarterly Report of Copano Energy, L.L.C. (the “Company”) on Form 10-Q for the quarter ended September 30, 2009 (the “Report”) filed with the Securities and Exchange Commission on November 6, 2009, I, Carl A. Luna, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that to my knowledge:

(1)	The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 as amended; and
(2)	The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

November 6, 2009	/s/ Carl A. Luna
	Carl A. Luna
	Senior Vice President and Chief Financial Officer