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

e10vq

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q


þ		QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
		For the quarterly period ended September 30, 2007
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 is a large accelerated filer, an accelerated filer, or a non-accelerated filer. See definition of “accelerated filer and large accelerated filer” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer o Accelerated filer þ Non-accelerated filer o

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 47,323,377 common units of Copano Energy, L.L.C. outstanding at November 1, 2007. Copano Energy, L.L.C.’s common units trade on The NASDAQ National Market 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, 2007 and December 31, 2006		3
		Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2007 and 2006		4
		Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2007 and 2006		5
		Unaudited Consolidated Statement of Members’ Capital and Comprehensive Income (Loss) for the Nine Months Ended September 30, 2007		6
		Notes to Unaudited Consolidated Financial Statements		7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		30
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		45
	Item 4.	Controls and Procedures		51

PART II — OTHER INFORMATION
	Item 1.	Legal Proceedings		51
	Item 1A.	Risk Factors		51
	Item 6.	Exhibits		55
First Amendment to Administrative and Operating Services Agreement
Certification of CEO Pursuant to Section 302
Certification of CFO Pursuant to Section 302
Certification of CEO Pursuant to Section 906
Certification of CFO Pursuant to Section 906


Item 1.	*Financial Statements.*

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS


	September 30,			December 31,
	2007			2006
	(Unaudited)
	(In thousands, except unit information)

ASSETS
Current assets:
Cash and cash equivalents	$	47,846		$	39,484
Accounts receivable, net		90,486			67,095
Risk management assets		5,734			13,973
Prepayments and other current assets		4,121			3,166

Total current assets		148,187			123,718

Property, plant and equipment, net		665,052			566,927
Intangible assets, net		138,699			93,372
Investment in unconsolidated affiliates		17,982			19,378
Risk management assets		16,043			23,826
Other assets, net		13,975			11,837

Total assets	$	999,938		$	839,058


LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable	$	117,908		$	91,668
Notes payable		—			1,495
Risk management liabilities		12,498			944
Other current liabilities		14,347			11,615

Total current liabilities		144,753			105,722

Long-term debt		359,000			255,000
Deferred tax provision		898			—
Risk management and other noncurrent liabilities		18,260			5,750
Commitments and contingencies (Note 9)
Members’ capital:
Common units, no par value, 42,357,653 units and 35,190,590 units issued and outstanding as of September 30, 2007 and December 31, 2006, respectively		491,978			480,797
Class C units, no par value, 1,579,409 units issued and outstanding as of September 30, 2007		54,000			—
Subordinated units, no par value, 7,038,252 units issued and outstanding as of December 31, 2006		—			10,379
Paid-in capital		19,934			10,585
Accumulated (deficit) earnings		(9,053	)		2,918
Accumulated other comprehensive loss		(79,832	)		(32,093	)

		477,027			472,586

Total liabilities and members’ capital	$	999,938		$	839,058

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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2007			2006			2007			2006
	(Unaudited)
	(In thousands, except unit information)

Revenue:
Natural gas sales	$	124,091		$	114,624		$	375,420		$	346,430
Natural gas liquids sales		132,835			106,534			336,748			277,536
Transportation, compression and processing fees		3,880			3,919			12,320			11,174
Condensate and other		32,270			6,234			61,298			19,758

Total revenue		293,076			231,311			785,786			654,898

Costs and expenses:
Cost of natural gas and natural gas liquids		235,952			174,525			641,799			512,003
Transportation		1,239			814			3,342			2,241
Operations and maintenance		10,525			8,519			28,700			23,527
Depreciation and amortization		10,130			8,182			28,426			23,657
General and administrative		8,615			8,108			23,831			19,919
Taxes other than income		1,010			622			2,566			1,610
Equity in (earnings) loss from unconsolidated affiliates		(401	)		(549	)		(2,019	)		(644	)

Total costs and expenses		267,070			200,221			726,645			582,313

Operating income		26,006			31,090			59,141			72,585
Interest and other income		706			718			2,032			1,310
Interest and other financing costs		(6,943	)		(9,525	)		(18,314	)		(25,312	)

Income before income taxes		19,769			22,283			42,859			48,583
Provision for income taxes		(102	)		—			(1,182	)		—

Net income	$	19,667		$	22,283		$	41,677		$	48,583

Basic net income per common unit:
Net income per common unit	$	0.46		$	0.61		$	1.00		$	1.33
Weighted average number of common units		42,330			29,393			41,154			29,357
Diluted net income per common unit:
Net income per common unit	$	0.44		$	0.60		$	0.96		$	1.32
Weighted average number of common units		44,233			36,863			43,606			36,767
Basic net income per subordinated unit:
Net income per subordinated unit	$	—		$	0.61		$	0.49		$	1.33
Weighted average number of subordinated units		—			7,038			1,134			7,038
Diluted net income per subordinated unit:
Net income per subordinated unit	$	—		$	0.61		$	0.49		$	1.33
Weighted average number of subordinated units		—			7,038			1,134			7,038

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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Nine Months Ended September 30,
	2007			2006
	(Unaudited)
	(In thousands)

Cash Flows From Operating Activities:
Net income	$	41,677		$	48,583
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization		28,426			23,657
Amortization of debt issue costs		921			3,524
Equity in earnings from unconsolidated affiliates		(2,019	)		(644	)
Distributions from unconsolidated affiliates		2,888			—
Equity-based compensation		2,180			1,315
Deferred tax provision		898			—
Other noncash items		(98	)		94
Changes in assets and liabilities, net of acquisitions:
Accounts receivable		(12,135	)		19,765
Prepayments and other current assets		(562	)		1,661
Risk management activities		(19,137	)		6,914
Accounts payable		13,200			(7,447	)
Other current liabilities		12,099			(795	)

Net cash provided by operating activities		68,338			96,627

Cash Flows From Investing Activities:
Additions to property, plant and equipment		(57,247	)		(30,148	)
Additions to intangible assets		(2,604	)		(308	)
Acquisitions, net of cash acquired		(55,471	)		(9,074	)
Investment in unconsolidated affiliate		—			(11,053	)
Distributions from unconsolidated affiliate		375			—
Other		(990	)		(504	)

Net cash used in investing activities		(115,937	)		(51,087	)

Cash Flows From Financing Activities:
Repayments of long-term debt		—			(376,500	)
Proceeds from long-term debt		104,000			353,500
Repayments of short-term notes payable		(1,494	)		(1,477	)
Deferred financing costs		(608	)		(7,013	)
Distributions to unitholders		(53,441	)		(33,277	)
Proceeds from private placement of common units		—			25,000
Capital contributions from Pre-IPO Investors		7,169			4,006
Proceeds from option exercises		850			199
Equity offering costs		(515	)		(640	)

Net cash provided by (used in) financing activities		55,961			(36,202	)

Net increase in cash and cash equivalents		8,362			9,338
Cash and cash equivalents, beginning of year		39,484			25,297

Cash and cash equivalents, end of period	$	47,846		$	34,635

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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

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


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

Balance, December 31, 2006		35,191	$	480,797				$	—		7,038		$	10,379		$	10,585	$	2,918		$	(32,093	)	$	472,586		$	—
Capital contributions from Pre-IPO Investors		—		—			—		—		—			—			7,169		—			—			7,169			—
Conversion of subordinated units into common units		7,038		10,379			—		—		(7,038	)		(10,379	)		—		—			—			—			—
Private placement of units		—		—			1,579		54,000		—			—			—		—			—			54,000			—
Offering costs		—		(48	)		—		—		—			—			—		—			—			(48	)		—
Distributions to unitholders		—		—			—		—		—			—			—		(53,648	)		—			(53,648	)		—
Option exercises		61		850			—		—		—			—			—		—			—			850			—
Equity-based compensation		—		—			—		—		—			—			2,180		—			—			2,180			—
Vested restricted units		68		—			—		—		—			—			—		—			—			—			—
Net income		—		—			—		—		—			—			—		41,677			—			41,677			41,677
Derivative settlements reclassified to income		—		—			—		—		—			—			—		—			5,905			5,905			5,905
Unrealized loss-change in fair value of derivatives		—		—			—		—		—			—			—		—			(53,644	)		(53,644	)		(53,644	)

Comprehensive loss																											$	(6,062	)

Balance, September 30, 2007		42,358	$	491,978			1,579	$	54,000		—		$	—		$	19,934	$	(9,053	)	$	(79,832	)	$	477,027

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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS


Note 1 —	Organization and Basis of Presentation

Organization

Copano Energy, L.L.C., a Delaware limited liability company, was formed in August 2001 to acquire entities owning businesses operating under the Copano name since 1992. We, through our subsidiaries, provide midstream energy services, including gathering, transportation, treating, processing and conditioning services 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. and its subsidiaries.

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, power generation facilities and industrial consumers. Natural gas delivered to our gas processing plants, either on our pipelines or a third-party pipeline, is treated to remove contaminants, conditioned or processed to extract mixed natural gas liquids, or NGLs, and then fractionated or separated, to the extent commercially desirable, into select component NGL products, including ethane, propane, isobutane, normal butane, natural gasoline and stabilized condensate. We own and operate an NGL products pipeline extending from our Houston Central Processing Plant near Sheridan, Texas to the Houston area, and we lease an additional NGL pipeline that extends from the tailgate of this processing plant to the Enterprise Product Partners’ Seminole Pipeline near Brenham, Texas. We refer to our operations in central and eastern Oklahoma and in north Texas as “Mid-Continent Operations,” to our natural gas pipeline subsidiaries operating in the Texas Gulf Coast region collectively as “Texas Gulf Coast Pipelines” and to our Texas processing and related activities collectively as “Texas Gulf Coast Processing.” On October 19, 2007, Copano completed the acquisition of Cantera Natural Gas, LLC (“Cantera”) as discussed in Note 13, which expanded Copano’s geographic footprint into the Powder River Basin of the Rocky Mountains. We expect to manage our operations in Wyoming as the “Rocky Mountains Operations” 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. Although we, through certain of our subsidiaries, own a 62.5% equity investment in Webb/Duval Gatherers (“Webb Duval”), a Texas general partnership, and a majority interest in Southern Dome, LLC (“Southern Dome”), a Delaware limited liability company, we account for both of these investments using the equity method of accounting because the minority general partners or members have substantive participating rights with respect to the management of Webb Duval and Southern Dome. All significant 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.

On February 15, 2007, our Board of Directors approved a two-for-one split for all of our outstanding common units. The unit split entitled each unitholder of record at the close of business on March 15, 2007 to receive one additional common unit for every common unit held on that date. The additional common units were distributed to unitholders on March 30, 2007. Net income per unit, weighted average units outstanding and distributions per unit for all periods and any references to common units, restricted units and options to purchase common units have been retroactively adjusted to reflect this two-for-one split.

We do not provide for federal income taxes in the accompanying consolidated financial statements as such income is taxable directly to our unitholders. However, the State of Texas enacted a margin tax in May 2006, which is imposed at a maximum effective rate of 0.7% on our annual “margin,” as defined in the law. The first annual taxable period began January 1, 2007 and the first returns are due in 2008. The margin to which the tax rate will be applied generally will be calculated as our revenues for federal income tax purposes less the “cost of the products sold” as defined by the new Texas margin statute. Under the provisions of Statement of Financial Accounting Standards (“SFAS”) No. 109, “Accounting for Income Taxes,” we are required to record the effects on deferred taxes for a change in tax rates or tax law in the period that includes the enactment date. Under SFAS No. 109, taxes

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

based on income, like the Texas margin tax, are accounted for using the liability method under which deferred income taxes are recognized for the future tax effects of temporary differences between the financial statement carrying amounts and the tax basis of existing assets and liabilities using the enacted statutory tax rates in effect at the end of the period. A valuation allowance for deferred tax assets is recorded when it is more likely than not that the benefit from the deferred tax asset will not be realized. The provision for the Texas margin tax totaled $1,182,000 for the nine months ended September 30, 2007, comprised of $284,000 related to the current provision which is included in other current liabilities on the accompanying consolidated balance sheets and $898,000 deferred tax provision related to the cumulative effect of temporary book/tax timing differences associated with depreciation expense for periods prior to the enactment of the Texas margin tax.

The accompanying consolidated financial statements have been prepared without audit pursuant to the rules and regulations of the Securities and Exchange Commission (“SEC”). Accordingly, our 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. 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, 2006.


Note 2 —	New Accounting Pronouncements

Fair Value Measurements

In September 2006, the Financial Accounting Standards Board (“FASB”) issued SFAS No. 157, “Fair Value Measurements.” SFAS No. 157 establishes a framework for measuring fair values under generally accepted accounting principles and applies to other pronouncements that either permit or require fair value measurement, including SFAS No. 133, “Accounting for Derivative Instruments and Hedging Activities,” as amended and interpreted. The standard is effective for reporting periods beginning after November 15, 2007. We are evaluating SFAS No. 157 and currently do not expect it to have a material effect on our consolidated financial position or results of operations.

Fair Value Option for Financial Assets and Financial Liabilities

In February 2007, the FASB issued SFAS No. 159, “The Fair Value Option for Financial Assets and Financial Liabilities,” which permits entities to choose to measure many financial instruments and certain other items at fair value. SFAS No. 159 is effective for us as of January 1, 2008 and will have no impact on amounts presented for periods prior to the effective date. We cannot currently estimate the impact of SFAS No. 159 on our consolidated results of operations, cash flows or financial position and have not yet determined whether or not we will choose to measure items subject to SFAS No. 159 at fair value.

Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109

In June 2006, the FASB issued FASB Interpretation No. (“FIN”) 48, “Accounting for Uncertainty in Income Taxes — an Interpretation of FASB Statement No. 109.” FIN 48 clarifies the accounting for uncertainty in income taxes recognized in an entity’s financial statements in accordance with SFAS No. 109 by prescribing thresholds and attributes for the financial statement recognition and measurement of a tax position taken or expected to be taken in a tax return. The provisions of FIN 48 became effective as of the beginning of our 2007 fiscal year and our adoption of FIN 48 did not have a material impact on our consolidated financial position or results of operations.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 3 —	Intangible Assets

Our intangible assets consist of rights-of-way and easements, contracts and an acquired customer relationship, which we amortize over the term of the agreement or estimated useful life. Amortization expense was $1,815,000 and $1,349,000 for the three months ended September 30, 2007 and 2006, respectively. Amortization expense was $4,837,000 and $4,046,000 for the nine months ended September 30, 2007 and 2006, respectively. Estimated aggregate amortization expense remaining for 2007 and each of the succeeding periods indicated is approximately: 2007 — $1,838,000; 2008 — $7,316,000; 2009 — $7,247,000; 2010 — $7,219,000; 2011 — $7,209,000 and 2012 — $7,144,000. Intangible assets consisted of the following (in thousands):


	September 30,			December 31,
	2007			2006

Rights-of-way and easements, at cost	$	103,695		$	60,931
Less accumulated amortization for rights-of-way and easements		(7,717	)		(6,520	)
Contracts		48,522			42,444
Less accumulated amortization for contracts		(6,300	)		(4,009	)
Customer relationship		725			725
Less accumulated amortization for customer relationship		(226	)		(199	)

Intangible assets, net	$	138,699		$	93,372

As of September 30, 2007 and December 31, 2006, the weighted average amortization period for all of our intangible assets was 22 years and 19 years, respectively. The weighted average amortization period for our rights-of-way and easements and contracts was 25 years and 13 years, respectively, as of September 30, 2007. The weighted average amortization period for our rights-of-way and easements and contracts was 22.9 years and 13.6 years, respectively, as of December 31, 2006.


Note 4 —	Acquisitions

Acquisition of Cimmarron Gathering, L.P.

On May 1, 2007, we acquired all of the partnership interests in Cimmarron Gathering, L.P. (“Cimmarron”), a Texas limited partnership, for approximately $96.7 million in cash and securities (the “Consideration”) (the “Initial Cimmarron Acquisition”). The Consideration consisted of cash and 1,579,409 Class C units valued at approximately $54 million as described below. The cash portion of the Consideration was funded with borrowings under our Credit Facility discussed in Note 5. As a result of the Initial Cimmarron Acquisition, we acquired interests in natural gas and crude oil pipelines in central and eastern Oklahoma and in north Texas, including Cimmarron’s 70% undivided interest in the Tri-County gathering system located in north Texas (the “Tri-County System”).

Additionally, in June 2007, we acquired the remaining 30% interest in the Tri-County System for $15.3 million in cash (the “Additional Cimmarron Acquisition” and together with the Initial Cimmarron Acquisition, the “Cimmarron Acquisition”).

The following is an estimate of the purchase price for the Cimmarron Acquisition (in thousands):


Purchase price for the Cimmarron Acquisition	$	110,000
Net working capital adjustments		753
Acquisition costs		1,237

Total purchase price for the Cimmarron Acquisition	$	111,990

With the assistance of an independent third-party valuation firm, our management has prepared a preliminary assessment of the fair value of the property, plant and equipment and intangible assets of the Cimmarron

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Acquisition. Using the preliminary assessment, the purchase price has been allocated as presented below (in thousands). We do not anticipate any material adjustments to this preliminary purchase price allocation.


Cash and cash equivalents	$	3,257
Accounts receivable		11,027
Prepayments and other current assets		393
Property, plant and equipment		63,379
Intangibles		47,560
Other assets		476
Investment in unconsolidated affiliates		77
Accounts payable		(14,179	)

	$	111,990

All liabilities assumed were at their fair values. The fair value of intangibles is estimated to be $47,560,000, which includes $41,482,000 of rights-of-way and easements with a weighted average amortization period of 30 years and $6,078,000 of contracts with an estimated weighted average amortization period of 15 years. There were no identified intangibles which were determined to have indefinite lives. See Note 3.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The following table presents selected pro forma financial information incorporating the historical (pre-acquisition) results of Cimmarron as if the Cimmarron Acquisition had occurred at the beginning of each of the periods presented as opposed to the actual date that the acquisition occurred. The pro forma information is based upon preliminary data currently available and includes certain estimates and assumptions made by management. As a result, this preliminary information is not necessarily indicative of our financial results had the transactions actually occurred at the beginning of each of the periods presents. Likewise, the following pro forma financial information is not necessarily indicative of our future financial results.


	Three Months Ended
	September 30,				Nine Months Ended September 30,
	2007		2006		2007		2006
	(In thousands, except per unit information)

Pro Forma Earnings Data:
Revenue	$	293,076	$	259,128	$	823,398	$	726,702
Costs and expenses	$	267,070	$	228,293	$	764,142	$	655,061
Operating income	$	26,006	$	30,835	$	59,256	$	71,641
Income before extraordinary items	$	19,667	$	22,119	$	40,530	$	45,916
Net income	$	19,667	$	22,119	$	40,530	$	45,916
Basic net income per common unit:
As reported units outstanding		42,330		29,393		41,154		29,357
Pro forma units outstanding		42,725		29,788		41,285		29,488
As reported net income per unit	$	0.46	$	0.61	$	1.00	$	1.33
Pro forma net income per unit	$	0.46	$	0.60	$	0.97	$	1.26
Diluted net income per common unit:
As reported units outstanding		44,233		36,863		43,606		36,767
Pro forma units outstanding		44,233		30,958		42,482		30,854
As reported net income per unit	$	0.44	$	0.60	$	0.96	$	1.32
Pro forma net income per unit	$	0.44	$	0.58	$	0.93	$	1.21
Basic net income per subordinated unit:
As reported units outstanding		—		7,038		1,134		7,038
Pro forma units outstanding		—		7,038		1,134		7,038
As reported net income per unit	$	—	$	0.61	$	0.49	$	1.33
Pro forma net income per unit	$	—	$	0.60	$	0.31	$	1.26
Diluted net income per subordinated unit:
As reported units outstanding		—		7,038		1,134		7,038
Pro forma units outstanding		—		7,038		1,134		7,038
As reported net income per unit	$	—	$	0.61	$	0.49	$	1.33
Pro forma net income per unit	$	—	$	0.60	$	0.31	$	1.25

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 5 —	Long-Term Debt

A summary of our debt follows (in thousands):


	September 30,		December 31,
	2007		2006

Long-term debt:
Credit Facility	$	134,000	$	30,000
Senior Notes		225,000		225,000

Total	$	359,000	$	255,000

Credit Facility

Our senior secured revolving credit facility (the “Credit Facility”) is provided by Bank of America, N.A., as Administrative Agent, and a group of financial institutions, as lenders, and was established in August 2005. In January 2007, we modified the Credit Facility to, among others things, extend its maturity date to April 15, 2012, revise the interest rate provisions and the commitment fee provisions, increase the maximum ratio of our total debt to EBITDA (as defined under the Credit Facility) permitted under the Credit Facility and eliminate (i) the limitation on our use of the proceeds of loans under the Credit Facility to make certain types of capital expenditures, (ii) the requirement that we not exceed a maximum consolidated fixed charge coverage ratio (EBITDA minus maintenance capital expenditures to consolidated fixed charges as defined under the Credit Facility) and (iii) the requirement that we not exceed a consolidated senior leverage ratio (total senior debt to EBITDA as defined under the Credit Facility). On October 19, 2007, in connection with the Cantera acquisition discussed in Note 13, we further amended our Credit Facility to increase the aggregate borrowing capacity under the Credit Facility from $200 million to $550 million, extend the maturity date of the Credit Facility to October 18, 2012 and make certain other modifications.

Future borrowings under the Credit Facility are available for acquisitions, capital expenditures, working capital and general corporate purposes. The Credit Facility does not provide for the type of working capital borrowings that would be eligible, pursuant to our limited liability company agreement, to be considered cash available for distribution to our unitholders. The Credit Facility is available to be drawn on and repaid without restriction so long as we are in compliance with the terms of the Credit Facility, including certain financial covenants.

The effective average interest rate on borrowings under the Credit Facility was 6.9% and the quarterly commitment fee on the unused portion of the Credit Facility was 0.2% as of September 30, 2007. Interest and other financing costs related to the Credit Facility totaled $4,837,000 for the nine months ended September 30, 2007. Costs incurred in connection with the establishment of the Credit Facility are being amortized over the term of the Credit Facility and, as of September 30, 2007, the unamortized portion of debt issue costs totaled $2,355,000.

Our management believes that we are in compliance with the covenants under the Credit Facility as of September 30, 2007.

Senior Notes

In February 2006, we issued an aggregate of $225 million in principal amount of our 8.125% senior notes due 2016 (the “Senior Notes”). Interest and other financing costs related to the Senior Notes totaled $14,239,000 for the nine months ended September 30, 2007. Costs incurred in connection with the issuance of the Senior Notes are being amortized over the term of the Senior Notes and, as of September 30, 2007, the unamortized portion of debt issue costs totaled $5,927,000.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The Senior Notes are jointly and severally guaranteed by all of our current wholly-owned subsidiaries (other than Copano Energy Finance Corporation (“CEFC”), the co-issuer of the Senior Notes) and by certain of our future subsidiaries. The subsidiary guarantees rank equally in right of payment with all of the existing and future senior indebtedness of our guarantor subsidiaries, including their guarantees of our other senior indebtedness. The subsidiary guarantees are effectively subordinated to all existing and future secured indebtedness of our guarantor subsidiaries to the extent of the value of the assets securing that indebtedness and to all existing and future indebtedness and other liabilities, including trade payables, of any non-guarantor subsidiaries (other than indebtedness and other liabilities owed to our guarantor subsidiaries). The subsidiary guarantees rank senior in right of payment to any future subordinated indebtedness of our guarantor subsidiaries.

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

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING BALANCE SHEETS


	September 30, 2007																	December 31, 2006
										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	$	1,375		$	—		$	46,471		$	—	$	—		$	47,846		$	1,286		$	—		$	38,198		$	—	$	—		$	39,484
Accounts receivable, net		26			—			90,460			—		—			90,486			32			—			120,057			—		(52,994	)		67,095
Intercompany receivable		48,719			—			(24,876	)		—		(23,843	)		—			24,908			—			(71,028	)		—		46,120			—
Risk management assets		—			—			5,734			—		—			5,734			—			—			13,973			—		—			13,973
Prepayments and other current assets		1,162			—			2,959			—		—			4,121			44			—			3,122			—		—			3,166

Total current assets		51,282			—			120,748			—		(23,843	)		148,187			26,270			—			104,322			—		(6,874	)		123,718

Property, plant and equipment, net		275			—			664,777			—		—			665,052			299			—			566,628			—		—			566,927
Intangible assets, net		—			—			138,699			—		—			138,699			—			—			93,372			—		—			93,372
Investment in unconsolidated affiliates		—			—			17,982			17,982		(17,982	)		17,982			—			—			19,378			19,378		(19,378	)		19,378
Investment in consolidated subsidiaries		780,512			—			—			—		(780,512	)		—			674,105			—			—			—		(674,105	)		—
Risk management assets		—			—			16,043			—		—			16,043			—			—			23,826			—		—			23,826
Other assets, net		8,389			—			5,586			—		—			13,975			8,577			—			3,260			—		—			11,837

Total assets	$	840,458		$	—		$	963,835		$	17,982	$	(822,337	)	$	999,938		$	709,251		$	—		$	810,786		$	19,378	$	(700,357	)	$	839,058


LIABILITIES AND MEMBERS’/PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	66		$	—		$	117,842		$	—	$	—		$	117,908		$	434		$	—		$	130,919		$	—	$	(39,685	)	$	91,668
Intercompany payable		96			—			23,747			—		(23,843	)		—			(26,291	)		—			(6,520	)		—		32,811			—
Notes payable		—			—			—			—		—			—			—			—			1,495			—		—			1,495
Risk management liabilities		—			—			12,498			—		—			12,498			—			—			944			—		—			944
Other current liabilities		2,759			—			11,588			—		—			14,347			6,811			—			4,804			—		—			11,615

Total current liabilities		2,921			—			165,675			—		(23,843	)		144,753			(19,046	)		—			131,642			—		(6,874	)		105,722

Long-term debt		359,000			—			—			—		—			359,000			255,000			—			—			—		—			255,000
Deferred tax provision		898			—			—			—		—			898																	—
Risk management and other noncurrent liabilities		612			—			17,648			—		—			18,260			711			—			5,039			—		—			5,750
Members’/Partners’ capital:
Common units		491,978			—			—			—		—			491,978			480,797			—			—			—		—			480,797
Class C units		54,000			—			—			—		—			54,000			—			—			—			—		—			—
Subordinated units		—			—			—			—		—			—			10,379			—			—			—		—			10,379
Paid-in capital		19,934			1			772,335			14,463		(786,799	)		19,934			10,585			1			524,940			17,445		(542,386	)		10,585
Accumulated (deficit) earnings		(9,053	)		(1	)		88,009			3,519		(91,527	)		(9,053	)		2,918			(1	)		181,258			1,933		(183,190	)		2,918
Accumulated other comprehensive loss		(79,832	)		—			(79,832	)		—		79,832			(79,832	)		(32,093	)		—			(32,093	)		—		32,093			(32,093	)

		477,027			—			780,512			17,982		(798,494	)		477,027			472,586			—			674,105			19,378		(693,483	)		472,586

Total liabilities and members’/partners’ capital	$	840,458		$	—		$	963,835		$	17,982	$	(822,337	)	$	999,938		$	709,251		$	—		$	810,786		$	19,378	$	(700,357	)	$	839,058

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS


	Three Months Ended September 30,
	2007																	2006
									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	$	—		$	—	$	124,091		$	—		$	—		$	124,091		$	—		$	—	$	114,624		$	—		$	—		$	114,624
Natural gas liquids sales		—			—		132,835			—			—			132,835			—			—		106,534			—			—			106,534
Transportation, compression and processing fees		—			—		3,880			—			—			3,880			—			—		3,919			—			—			3,919
Condensate and other		—			—		32,270			—			—			32,270			—			—		6,234			—			—			6,234

Total revenue		—			—		293,076			—			—			293,076			—			—		231,311			—			—			231,311

Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		235,952			—			—			235,952			—			—		174,525			—			—			174,525
Transportation		—			—		1,239			—			—			1,239			—			—		814			—			—			814
Operations and maintenance		456			—		10,069			—			—			10,525			—			—		8,519			—			—			8,519
Depreciation and amortization		11			—		10,119			—			—			10,130			16			—		8,166			—			—			8,182
General and administrative		2,448			—		6,167			—			—			8,615			562			—		7,546			—			—			8,108
Taxes other than income		—			—		1,010			—			—			1,010			—			—		622			—			—			622
Equity in (earnings) loss from unconsolidated affiliates		—			—		(401	)		(401	)		401			(401	)		—			—		(549	)		(549	)		549			(549	)

Total costs and expenses		2,915			—		264,155			(401	)		401			267,070			578			—		199,643			(549	)		549			200,221

Operating (loss) income		(2,915	)		—		28,921			401			(401	)		26,006			(578	)		—		31,668			549			(549	)		31,090
Interest and other income		28			—		678			—			—			706			—			—		718			—			—			718
Interest and other financing costs		(7,011	)		—		68			—			—			(6,943	)		(9,597	)		—		72			—			—			(9,525	)

(Loss) income before income taxes and equity in earnings from consolidated subsidiaries		(9,898	)		—		29,667			401			(401	)		19,769			(10,175	)		—		32,458			549			(549	)		22,283
Provision for income taxes		(102	)		—		—			—			—			(102	)		—			—		—			—			—			—

(Loss) income before equity in earnings from consolidated subsidiaries		(10,000	)		—		29,667			401			(401	)		19,667			(10,175	)		—		32,458			549			(549	)		22,283
Equity in earnings (loss) from consolidated subsidiaries		29,667			—		—			—			(29,667	)		—			32,458			—		—			—			(32,458	)		—

Net income (loss)	$	19,667		$	—	$	29,667		$	401		$	(30,068	)	$	19,667		$	22,283		$	—	$	32,458		$	549		$	(33,007	)	$	22,283

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF OPERATIONS


	Nine Months Ended September 30,
	2007																	2006
									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	$	—		$	—	$	375,419		$	—		$	—		$	375,419		$	—		$	—	$	346,430		$	—		$	—		$	346,430
Natural gas liquids sales		—			—		336,748			—			—			336,748			—			—		277,536			—			—			277,536
Transportation, compression and processing fees		—			—		12,320			—			—			12,320			—			—		11,174			—			—			11,174
Condensate and other		—			—		61,298			—			—			61,298			—			—		19,758			—			—			19,758

Total revenue		—			—		785,785			—			—			785,785			—			—		654,898			—			—			654,898

Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		641,798			—			—			641,798			—			—		512,003			—			—			512,003
Transportation		—			—		3,342			—			—			3,342			—			—		2,241			—			—			2,241
Operations and maintenance		1,264			—		27,436			—			—			28,700			—			—		23,527			—			—			23,527
Depreciation and amortization		23			—		28,403			—			—			28,426			49			—		23,608			—			—			23,657
General and administrative		7,576			—		16,255			—			—			23,831			1,399			—		18,520			—			—			19,919
Taxes other than income		—			—		2,566			—			—			2,566			—			—		1,610			—			—			1,610
Equity in earnings from unconsolidated affiliates		—			—		(2,019	)		(2,019	)		2,019			(2,019	)		—			—		(644	)		(644	)		644			(644	)

Total costs and expenses		8,863			—		717,781			(2,019	)		2,019			726,644			1,448			—		580,865			(644	)		644			582,313

Operating (loss) income		(8,863	)		—		68,004			2,019			(2,019	)		59,141			(1,448	)		—		74,033			644			(644	)		72,585
Interest and other income		201			—		1,831			—			—			2,032			—			—		1,310			—			—			1,310
Interest and other financing costs		(18,399	)		—		85			—			—			(18,314	)		(25,384	)		—		72			—			—			(25,312	)

(Loss) income before income taxes and equity in earnings from consolidated subsidiaries		(27,061	)		—		69,920			2,019			(2,019	)		42,859			(26,832	)		—		75,415			644			(644	)		48,583
Provision for income taxes		(1,182	)		—		—			—			—			(1,182	)		—			—		—			—			—			—

(Loss) income before equity in earnings from consolidated subsidiaries		(28,243	)		—		69,920			2,019			(2,019	)		41,677			(26,832	)		—		75,415			644			(644	)		48,583
Equity in earnings (loss) from consolidated subsidiaries		69,920			—		—			—			(69,920	)		—			75,415			—		—			—			(75,415	)		—

Net income (loss)	$	41,677		$	—	$	69,920		$	2,019		$	(71,939	)	$	41,677		$	48,583		$	—	$	75,415		$	644		$	(76,059	)	$	48,583

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

CONDENSED CONSOLIDATING STATEMENTS OF CASH FLOWS


	Nine Months Ended September 30,
	2007																2006
									Investment in																Investment in
						Guarantor			Non-Guarantor													Guarantor			Non-Guarantor
	Parent			Co-Issuer		Subsidiaries			Subsidiaries		Eliminations			Total			Parent			Co-Issuer		Subsidiaries			Subsidiaries			Eliminations			Total
														(In thousands)

Cash Flows From Operating Activities:
Net cash (used in) provided by operating activities	$	(27,099	)	$	—	$	95,437		$	2,888	$	(2,888	)	$	68,338		$	(16,179	)	$	—	$	112,806		$	—		$	—		$	96,627

Cash Flows From Investing Activities:
Net cash (used in) provided by investing activities		(30,266	)		—		(115,896	)		375		29,850			(115,937	)		50,374			—		(51,086	)		(11,053	)		(39,322	)		(51,087	)

Cash Flows From Financing Activities:
Net cash provided by (used in) financing activities		57,454			—		28,732			—		(30,225	)		55,961			(34,725	)		—		(51,852	)		11,053			39,322			(36,202	)

Net increase (decrease) in cash and cash equivalents		89			—		8,273			3,263		(3,263	)		8,362			(530	)		—		9,868			—			—			9,338
Cash and cash equivalents, beginning of year		1,286			—		38,198			—		—			39,484			1,167			1		24,129			—			—			25,297

Cash and cash equivalents, end of period	$	1,375		$	—	$	46,471		$	3,263	$	(3,263	)	$	47,846		$	637		$	1	$	33,997		$	—		$	—		$	34,635

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 6 —	Members’ Capital and Distributions

Common Units and Subordinated Units

Effective February 14, 2007, our subordinated units converted on a one-for-one basis into common units as a result of the satisfaction of the financial tests required for conversion of the subordinated units into common units, as set forth in our limited liability company agreement. The subordinated units were issued by us to certain of our investors existing prior to our initial public offering (“IPO”) (our “Pre-IPO Investors”) in connection with our IPO in November 2004.

On March 30, 2007, we effected a two-for-one split of all of our outstanding common units, which entitled each unitholder of record at the close of business on March 15, 2007, to receive one additional common unit for every common unit held on that date.

On April 30, 2007, we amended and restated our limited liability agreement to reflect the conversion of our subordinated units as well as the unit split, including adjustment of our minimum quarterly distribution.

As of September 30, 2007, 42,357,653 common units (excluding restricted common units) were outstanding. Our management controlled an aggregate of 4,584,082 of these common units as of September 30, 2007.

Pursuant to our limited liability company agreement, the Pre-IPO Investors agreed to reimburse us for general and administrative expenses in excess of stated levels (subject to certain limitations) for a period of three years beginning on January 1, 2005. Specifically, to the extent general and administrative expenses exceed certain levels, the portion of the general and administrative expenses ultimately funded by us (subject to certain adjustments and exclusions) is limited, or capped. For the year ended December 31, 2007, the “cap” limits our general and administrative expense obligations to $1.8 million per quarter (subject to certain adjustments and exclusions). During this three-year period, the quarterly limitation on general and administrative expenses is increased by 10% of the amount by which EBITDA (as defined) for any quarter exceeds $5.4 million. During the nine months ended September 30, 2007, our Pre-IPO Investors made capital contributions to us in the aggregate amount of $7,169,000 as a reimbursement of excess general and administrative expenses for the fourth quarter of 2006 and for the first and second quarters of 2007. Based on the level of our general and administrative expenses for the third quarter of 2007, our Pre-IPO Investors will be obligated to make capital contributions to us in the aggregate amount of $2,796,000 as a reimbursement of excess general and administrative expenses for this period.

Class C Units

In connection with the Initial Cimmarron Acquisition, we delivered Class C units, a new class of equity interests, to the Sellers as part of the Consideration for Cimmarron. Pursuant to our acquisition agreement with the Sellers, we issued an aggregate of 1,579,409 Class C units to the Sellers, which represented approximately $54.0 million of the Consideration based upon the average closing price of our common units over the ten business days preceding the execution date of the acquisition agreement. The acquisition agreement provides for the automatic conversion of up to 25% of the Class C units issued at the closing to common units on each of the six-month, 12-month, 18-month and 24-month anniversaries of the closing of the Initial Cimmarron Acquisition (less any Class C units that have been released to us pursuant to the escrow arrangement described below in satisfaction of any post-closing indemnification obligations of the Sellers). Until such time as a Class C unit has converted to a common unit, such Class C unit is not entitled to receive any of the quarterly cash distributions that are made with respect to our common units. Otherwise, the Class C units have the same terms and conditions as our common units, including with respect to voting rights. The Class C units are not quoted for trading on The Nasdaq Stock Market LLC or any other securities exchange. On November 1, 2007, 394,852 of the Class C units representing 25% of the then outstanding Class C units converted to common units in accordance with the terms of the Class C units.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

At the closing of the Initial Cimmarron Acquisition, 453,838 Class C units otherwise issuable to the partners in Cimmarron (collectively, the “Sellers”) and representing approximately $17.5 million of the Consideration were deposited into escrow for up to one year to satisfy certain post-closing claims for indemnification by us, if any. The acquisition agreement provides that, at the six-month anniversary of the closing, no indemnity claims exist with respect to certain representations and warranties of the Sellers (including with respect to title to the Cimmarron partnership interests), the amount of Class C units held in escrow would be reduced to $5.0 million. On November 1, 2007, the six-month anniversary of the Initial Cimmarron Acquisition, we determined that no indemnity claims to be satisfied using Class C units existed. On November 2, 2007, we and the Sellers agreed to issue joint instructions to the escrow agent reducing the number of Class C units held in escrow to 133,648, representing $5.0 million.

At the closing, we entered into a registration rights agreement with the Sellers pursuant to which the Sellers will be entitled to an aggregate of one demand registration and unlimited rights to sell their units in the event we conduct a public equity offering, subject to certain limitations, (“piggyback registration rights”) with respect to the common units underlying the Class C units, in each case on the terms and conditions set forth therein.

Distributions

On January 18, 2007, our Board of Directors declared a cash distribution for the three months ended December 31, 2006 of $0.40 per unit for all outstanding common and subordinated units. The distribution, totaling $17,025,000, was paid on February 14, 2007 to holders of record at the close of business on February 1, 2007.

On April 18, 2007, our Board of Directors declared a cash distribution for the three months ended March 31, 2007 of $0.42 per unit for all outstanding common units. The distribution totaling $17,881,000 was paid on May 15, 2007 to holders of record at the close of business on May 1, 2007.

On July 18, 2007, our Board of Directors declared a cash distribution for the three months ended June 30, 2007 of $0.44 per unit for all outstanding common units. The distribution totaling $18,743,000 was paid on August 14, 2007 to holders of record at the close of business on August 1, 2007.

On October 17, 2007, our Board of Directors declared a cash distribution for the three months ended September 30, 2007 of $0.47 per unit for all outstanding common units eligible for distributions. The distribution will be paid on November 14, 2007 to holders of record of eligible outstanding common units at the close of business on November 1, 2007.

Accounting for Equity-Based Compensation

We use SFAS No. 123(R), “Share-Based Payment,” to account for awards issued under our long-term incentive plan, or LTIP. The equity-based compensation expense relates to awards issued under our LTIP discussed in “Restricted Common Units” and “Unit Options” below. As of September 30, 2007, the number of units available for grant under our LTIP totaled 2,453,842, of which up to 829,714 units are eligible to be issued as restricted units or phantom units.

Restricted Common Units. Restricted units are awarded under our LTIP and are common units that vest over a period of time and that during such time are subject to forfeiture. In addition, restricted units vest upon a change of control, unless provided otherwise by the Compensation Committee of our Board of Directors and may vest in other circumstances (for example, death or disability), as approved by our Compensation Committee and reflected in an award agreement. Distributions made on restricted units may be subjected to the same vesting provisions as the restricted units. The restricted units are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the common units. Therefore, plan participants do not pay any consideration for the common units they receive and we receive no remuneration for the units. As of September 30, 2007, 249,036 restricted common units were outstanding.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

The aggregate intrinsic value of the units net of anticipated forfeitures is amortized into expense over the respective vesting periods. We recognized non-cash compensation expense of $1,530,000 and $998,000 related to the amortization of restricted units outstanding during the nine months ended September 30, 2007 and 2006, respectively.

A summary of the restricted common unit activity for the nine months ended September 30, 2007 is provided below:


				Weighted
	Number of			Average
	Restricted			Grant-Date
	Units			Fair Value

Outstanding at beginning of year		315,936		$	20.84
Granted		5,500			37.17
Vested		(68,362	)		19.83
Forfeited		(4,038	)		21.07

Outstanding at end of period		249,036		$	21.47

As of September 30, 2007, unrecognized compensation costs related to the outstanding restricted units issued under our LTIP totaled $4,264,000. The expense is expected to be recognized over a weighted average period of four years. The total fair value of restricted common units vested during the nine months ended September 30, 2007 was $2,656,000.

Phantom Units. Phantom units are awarded under our LTIP and upon vesting, entitle the holder to receive our common units or an equivalent amount of cash, as determined by the Compensation Committee in its discretion. Generally, phantom units vest over a period of time, subject to forfeiture. In addition, phantom units vest upon a change of control, unless provided otherwise by the Compensation Committee of our Board of Directors, and may vest in other circumstances (for example, death or disability), as approved by our Compensation Committee and reflected in an award agreement. DERs, or distribution equivalent rights, made on phantom units may be subjected to the same vesting provisions as the phantom units. The phantom units are intended to serve as a means of incentive compensation for performance and not primarily as an opportunity to participate in the equity appreciation of the units. Therefore, plan participants do not pay any cash consideration for the phantom units they receive. As of September 30, 2007, 89,170 phantom units were outstanding. No phantom units had been awarded under our LTIP prior to June 12, 2007.

The aggregate intrinsic value of the phantom units net of anticipated forfeitures is amortized into expense over the respective vesting periods. We recognized non-cash compensation expense of $191,000 related to the amortization of phantom units outstanding during the nine months ended September 30, 2007.

A summary of the phantom unit activity for the nine months ended September 30, 2007 is provided below:


				Weighted
	Number of			Average
	Phantom			Grant-Date
	Units			Fair Value

Outstanding at beginning of year		—		$	—
Granted		89,715			41.38
Vested		—			—
Forfeited		(545	)		41.81

Outstanding at end of period		89,170		$	41.38

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

As of September 30, 2007, unrecognized compensation costs related to the outstanding phantom units issued under our LTIP totaled $3,146,000. The expense is expected to be recognized over a weighted average period of five years.

Unit Options. Unit options are granted under our LTIP and entitle the holder to purchase our common units at an exercise price that may not be less than the fair market value of the underlying units on the date of grant. In general, unit options become exercisable over a period determined by our Compensation Committee. In addition, unit options become exercisable upon a change in control, unless provided otherwise by our Compensation Committee and may vest in other circumstances (for example, death or disability), as approved by our Compensation Committee and reflected in an award agreement.

During the nine months ended September 30, 2007, we granted 263,700 options to purchase an equal number of common units at an average exercise price of $38.17 per unit to certain employees. 119,000 of these unit options were issued to employees of Cimmarron in connection with the Initial Cimmarron Acquisition discussed in Note 4. During the nine months ended September 30, 2006, we granted 148,745 options to purchase an equal number of common units at an average exercise price of $23.13 per unit to certain employees. These unit options vest in five equal annual installments commencing with the first anniversary of the grant date or earlier upon a change of control, or as otherwise approved by our Compensation Committee and reflected in the award agreement. These outstanding options have a contractual life of ten years from date of grant. All options granted during the nine months ended September 30, 2007 had an exercise price equal to the market value of the underlying common unit on the date of grant. We recognized non-cash compensation expense of $459,000 and $317,000 related to unit options net of anticipated forfeitures for the nine months ended September 30, 2007 and 2006, respectively.

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


	Nine Months Ended September 30,
	2007	2006

Weighted average exercise price	$38.17	$23.13
Expected volatility	20.57%-21.50%	21.45%-22.5%
Distribution yield	6.00%-6.05%	5.97%-6.02%
Risk-free interest rate	4.32%-5.11%	4.33%-5.14%
Expected term (in years)	6.5	6.5
Weighted average grant-date fair value of options granted	$4.55	$3.06
Total intrinsic value of options exercised	$1,315,000	$162,000

As of September 30, 2007, unrecognized compensation costs related to outstanding options issued under our LTIP totaled $2,486,000. The expense is expected to be recognized over a weighted average period of approximately five years.


Note 7 —	Net Income Per Unit

Net income per unit is calculated in accordance with SFAS No. 128, “Earnings Per Share,” and Emerging Issues Task Force Issue No. 03-6 (“Issue 03-6”), “Participating Securities and the Two-Class Method under Financial Accounting Standards Board Statement No. 128.” SFAS No. 128 and Issue 03-6 specify the use of the two-class method of computing earnings per unit when participating or multiple classes of securities exist. Under this method, undistributed earnings for a period are allocated based on the contractual rights of each security to share in those earnings as if all of the earnings for the period had been distributed. Since the Class C units do participate in current or undistributed earnings and are not entitled to receive cash distributions until they convert

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

into common units, the Class C units are not considered a potentially dilutive security for purposes of the diluted net income per unit calculation.

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 securities or other contracts to issue common units were exercised or converted into common units except when the assumed exercise or conversion 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 are calculated as follows (in thousands, except per unit information):


	Three Months Ended					Nine Months Ended
	September 30,					September 30,
	2007		2006			2007			2006

Net income available — basic	$	19,677	$	22,283		$	41,677		$	48,583
Less net income attributable to subordinated unitholders		—		(4,305	)		(553	)		(9,395	)

Net income — basic		19,677		17,978			41,124			39,188
Net income attributable to subordinated unitholders		—		4,305			553			9,395

Net income available — diluted(1)	$	19,677	$	22,283		$	41,677		$	48,583

Basic weighted average units		42,330		29,393			41,154			29,357
Dilutive weighted average units(1)		44,233		36,863			43,606			36,767
Basic net income per unit	$	0.46	$	0.61		$	1.00		$	1.33

Diluted net income per unit(1)	$	0.44	$	0.60		$	0.96		$	1.32


(1)		Potentially dilutive (i) restricted and phantom units, (ii) employee unit options and (iii) Class C units totaled 166,110, 611,086 and 1,125,571, respectively, during the three months ended September 30, 2007. Potentially dilutive restricted units and employee unit options totaled 101,149 and 330,153, respectively, during the three months ended September 30, 2006. Potentially dilutive (i) restricted and phantom units, (ii) employee unit options and (iii) Class C units totaled 117,892, 568,781 and 630,814, respectively, during the nine months ended September 30, 2007. Potentially dilutive restricted units and employee unit options totaled 103,934 and 268,135, respectively, during the nine months ended September 30, 2006.


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, 2007 and 2006, we reimbursed Copano Operations $866,000

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

and $835,000, 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, 2007 and 2006, we reimbursed Copano Operations $2,354,000 and $2,475,000, 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, 2007, our payable to Copano Operations was $76,000 and is included in accounts payable on our consolidated balance sheets.

Our management estimates that these expenses on a stand-alone basis (that is, the cost that would have been incurred by us to conduct current operations if we had obtained these services from an unaffiliated entity) would not be significantly different from the amounts recorded in our consolidated financial statements for each of the nine months ended September 30, 2007 and 2006.

Natural Gas Transactions and Other

The following table summarizes transactions between us and affiliated entities of Mr. Eckel, Webb Duval and Southern Dome (in thousands):


					Nine Months
	Three Months Ended September 30,				Ended September 30,
	2007		2006		2007		2006

Affiliates of Mr. Eckel:
Natural gas sales(1)	$	—	$	35	$	25	$	83
Gathering and compression services(2)		7		8		24		26
Natural gas purchases(3)		580		420		1,706		1,477
Webb/Duval:
Natural gas sales(1)		—		—		—		604
Natural gas purchases(3)		390		1,329		505		1,278
Transportation costs(4)		94		91		264		281
Southern Dome:
Natural gas liquid sales(5)		109		—		147		—
Condensate sales(6)		86		—		107		—


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

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

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

Additionally, affiliated companies of Mr. Eckel reimbursed us $3,000 and $43,000 for the three and nine months ended September 30, 2006, respectively, in gas lift costs which are reflected as a reduction of operations and maintenance expense on our consolidated statements of operations. As of September 30, 2007, amounts payable by us to affiliated companies of Mr. Eckel, other than Copano Operations, totaled $152,000 which is included in accounts payable on our consolidated balance sheets.

As operator of Webb Duval, we charged Webb Duval administrative fees of $53,000 and $48,000 for the three months ended September 30, 2007 and 2006, respectively, and $157,000 and $144,000 for the nine months ended

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

September 30, 2007 and 2006, respectively. Well connection fees paid to Webb Duval totaled $67,000 for the nine months ended September 30, 2006. As of September 30, 2007, our payable to Webb Duval totaled $187,000 which is included in accounts payable on our consolidated balance sheets.

We receive a management fee of $250,000 per year from Southern Dome, which along with any reimbursable costs, is the total compensation paid to us by Southern Dome. For the three months ended September 30, 2007, Southern Dome paid us $63,000 in management fees and $107,000 in other reimbursable costs. For the three months ended September 30, 2006, Southern Dome paid us $63,000 in management fees and $38,000 in other reimbursable costs. For the nine months ended September 30, 2007, Southern Dome paid us $188,000 in management fees and $245,000 in other reimbursable costs. For the nine months ended September 30, 2006, Southern Dome paid us $188,000 in management fees and $288,000 in other reimbursable costs. As of September 30, 2007, our receivable from Southern Dome totaled $592,000 and is included in accounts receivable on our consolidated balance sheets.

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

Note 9 — Commitments and Contingencies

Commitments

For the three months ended September 30, 2007 and 2006, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $908,000 and $877,000, respectively. For the nine months ended September 30, 2007 and 2006, rental expense for office space, leased vehicles and leased compressors and related field equipment used in our operations totaled $2,909,000 and $2,467,000, respectively.

We have both fixed and variable quantity contractual commitments arising in the ordinary course of our natural gas marketing activities. At September 30, 2007, we had fixed contractual commitments to purchase 1,038,500 million British thermal units (“MMBtu”) of natural gas in October 2007. As of September 30, 2007, we had fixed contractual commitments to sell 2,650,500 MMBtu of natural gas in October 2007. All of these contracts are based on index-related market pricing. Using index-related market prices as of September 30, 2007, total commitments to purchase natural gas related to such agreements equaled $6,377,000 and the total commitment to sell natural gas under such agreements equaled $16,198,000. 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 2007, natural gas volumes purchased under such contracts equaled 9,743,645 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 2007, natural gas volumes sold under such contracts equaled 4,895,835 MMBtu.

Guarantees

FIN 45, “Guarantor’s Accounting and Disclosure Requirements for Guarantees, Including Indirect Guarantees of Indebtedness of Others,” sets forth disclosure requirements for guarantees by a parent company on behalf of its subsidiaries. We may, from time to time, issue parent guarantees of commitments resulting from the ongoing activities of subsidiary entities. Additionally, a subsidiary entity may from time to time issue a guarantee of commitments resulting from the ongoing activities of another subsidiary entity. The guarantees generally arise in connection with a subsidiary commodity purchase obligation or subsidiary lease commitments. The nature of such guarantees is to guarantee the performance of the subsidiary entities in meeting their respective underlying obligations. Except for operating lease commitments, all such underlying obligations are recorded on the books of the subsidiary entities and are included in our consolidated financial statements as obligations of the combined entities. Accordingly, such obligations are not recorded again on the books of the parent. The parent would only be called upon to perform under the guarantee in the event of a payment default by the applicable subsidiary entity. In

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

satisfying such obligations, the parent would first look to the assets of the defaulting subsidiary entity. As of September 30, 2007, the amount of parental guaranteed obligations totaled approximately $1,700,000, all of which were related to our commodity purchases.

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

Although we may, from time to time, be involved in litigation and claims arising out of our operations in the normal course of business, we are not currently a party to any legal proceedings that are material to us. In addition, we are not aware of any material legal or governmental proceedings against us, or contemplated to be brought against us, under the various environmental protection statutes to which we are subject, that would have a significant adverse effect on our financial position or results of operations.

As a result of our Cantera Acquisition in October 2007, we became a party to a number of legal proceedings alleging (i) false reporting of natural gas prices by CMS Field Services, Inc. (“CMSFS”) (now Cantera Natural Gas, LLC) and numerous other parties and (ii) other related claims. The claims made in these proceedings are based on events that occurred prior to the acquisition of CMSFS by Cantera Resources, Inc. in June 2003 (the “CMS Acquisition”). Pursuant to the acquisition agreement executed in connection with the CMS Acquisition, CMS Gas Transmission Company (“CMS”) has assumed responsibility for the defense of these claims, and we are fully indemnified by CMS against any losses that we may suffer as a result of these claims.


Note 10 —	Supplemental Disclosures to the Statements of Cash Flows


	Nine Months
	Ended
	September 30,
	2007		2006
	(In thousands)

Cash payments for interest, net of $676,000 and $465,000 capitalized in 2007 and 2006, respectively	$	21,478	$	24,535
Cash payments for federal and state income taxes	$	—	$	—

We incurred an increase in liabilities for acquisitions and construction in progress that had not been paid as of September 30, 2007 and 2006 of $778,000 and $3,373,000, respectively. Such amounts are not included in the change in accounts payable and accrued liabilities or with acquisitions, additions to property, plant and equipment and intangible assets on the consolidated statements of cash flows.


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 affected by prevailing commodity prices primarily as a result of two components of our business: (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, as amended, which allows our management to purchase crude oil and NGLs puts and swaps and certain natural gas put or call options in order to reduce our exposure to a substantial adverse change in the prices of those commodities. Financial instruments that we acquire pursuant to our risk

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

management policy are generally designated as cash flow hedges under SFAS No. 133 and are recorded on our consolidated balance sheets at fair value. Changes in the fair value over time are generally recorded to other comprehensive income, or OCI. Gains or losses are recorded to our consolidated statements of operations as forecasted transactions are realized and for ineffectiveness of the hedging relationship, if any.

In the second quarter of 2007, we purchased additional put options and entered into additional swap agreements for ethane, propane, isobutane, normal butane and natural gasoline and also purchased put options for West Texas Intermediate crude oil, which are settled monthly beginning in July 2007 and ending December 2011. These derivatives are intended to hedge the risk of extreme adverse price fluctuations with respect to our production of the commodities hedged. During the nine months ended September 30, 2007, we recorded unrealized mark-to-market losses of $2,593,000 and unrealized losses of $69,000 related to ineffectiveness on these instruments.

Interest Rate Risk Hedging Program

Our interest rate exposure results from variable rate borrowings under our debt agreements. We manage a portion of our interest rate exposure by utilizing interest rate swaps, which allow us to convert a portion of variable rate debt into fixed rate debt.

In January 2007, we amended and restated our Credit Facility, including extending its maturity date and, as a result, the terms of our outstanding interest rate swaps no longer exactly match the term of the Credit Facility. Consequently, we no longer use the “shortcut” method under SFAS No. 133 in accounting for our interest rate swaps. In March 2007, we borrowed $20 million under the Credit Facility, resulting in a principal amount equal to the notional amount of the interest of the interest rate swaps so that the total notional amount of both $25 million interest rate swaps now qualify for hedge accounting.

In September 2007, we entered into a new interest rate swap agreement with a notional amount of $40 million under which we exchanged the payment of variable rate interest on a portion of the principal outstanding under the Credit Facility for fixed rate interest. Under this agreement, we pay the counterparty the fixed interest rate of approximately 4.77% monthly and receive back from the counterparty a variable interest rate based on three-month LIBOR rates. The interest rate swap covers the period from October 2007 through October 2011 and the settlement amounts will be recognized as either an increase or decrease in interest expense.

For the nine months ended September 30, 2007, we recognized mark-to-market losses and minimal ineffectiveness on the interest rate swaps totaling $124,000. As of September 30, 2007, the fair value of these financial instruments was a liability of $48,000.


Note 12 —	Segment Information

We manage our business and analyze and report our results of operations on a segment basis. As of September 30, 2007, our operations are divided into the following four business segments for both internal and external reporting and analysis: (i) Mid-Continent Operations, (ii) Texas Gulf Coast Pipelines, (iii) Texas Gulf Coast Processing and (iv) Corporate, which engages in risk management and other corporate activities. Currently, we analyze and report the results of operations from the Cimmarron Acquisition in our Mid-Continent Operations segment; however, this determination is preliminary and may change at a later date as we continue to integrate the Cimmarron Acquisition into our current operations. Our chief operating decision maker is our Chairman and Chief Executive Officer. We evaluate segment performance based on segment gross margin before depreciation and amortization. As of September 30, 2007, all of our revenue is derived from, and all of our assets and operations are located in, Oklahoma and Texas. Transactions between reportable segments are conducted on an arm’s length basis.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Summarized financial information concerning our reportable segments is shown in the following table (in thousands):


	Mid-			Texas Gulf			Texas Gulf
	Continent			Coast			Coast
	Operations			Pipelines			Processing		Corporate			Eliminations			Total

*Three Months Ended September 30, 2007:*
Sales to external customers	$	163,814		$	55,245		$	80,014	$	(5,997	)(a)	$	—		$	293,076
Intersegment sales		—			38,949			1,495		—			(40,444	)		—
Interest expense and other financing costs		—			—			—		6,943			—			6,943
Depreciation and amortization		7,369			1,908			643		210			—			10,130
Equity in earnings from unconsolidated affiliates		(248	)		(153	)		—		—			—			(401	)
Net income (loss)		15,849			4,283			15,388		(15,853	)		—			19,667
*Three Months Ended September 30, 2006:*
Sales to external customers	$	112,746		$	56,708		$	62,191	$	(334	)(a)	$	—		$	231,311
Intersegment sales		—			39,889			6,261		—			(46,150	)		—
Interest expense and other financing costs		—			—			—		9,525			—			9,525
Depreciation and amortization		5,850			1,594			632		106			—			8,182
Equity in earnings from unconsolidated affiliates		(56	)		(493	)		—		—			—			(549	)
Net income (loss)		16,857			6,256			13,031		(13,861	)		—			22,283
*Nine Months Ended September 30, 2007:*
Sales to external customers	$	417,925		$	174,186		$	208,532	$	(14,857	)(a)	$	—		$	785,786
Intersegment sales		—			121,218			5,017		—			(126,235	)		—
Interest expense and other financing costs		—			—			—		18,314			—			18,314
Depreciation and amortization		19,944			5,736			2,146		600			—			28,426
Equity in earnings from unconsolidated affiliates		(775	)		(1,244	)		—		—			—			(2,019	)
Net income (loss)		40,930			11,035			32,361		(42,649	)		—			41,677
Segment assets		741,866			161,154			113,880		6,881			(23,843	)		999,938
*Nine Months Ended September 30, 2006:*
Sales to external customers	$	310,896		$	178,637		$	165,040	$	325	(a)	$	—		$	654,898
Intersegment sales		—			129,137			28,095		—			(157,232	)		—
Interest expense and other financing costs		—			1			—		25,311			—			25,312
Depreciation and amortization		17,114			4,364			1,830		349			—			23,657
Equity in loss (earnings) from unconsolidated affiliates		119			(763	)		—		—			—			(644	)
Net income (loss)		38,961			14,048			28,593		(33,019	)		—			48,583


(a)		Represents the results of our risk management activities. See Note 11.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)


Note 13 —	Subsequent Events

Closing of Cantera Acquisition

On October 19, 2007, Copano, through its wholly owned subsidiary, Copano Energy/Rocky Mountains, L.L.C. (“Copano Rocky Mountains”), completed the acquisition of all of the membership interests of Cantera pursuant to a Purchase Agreement, dated August 31, 2007, among Copano, Copano Rocky Mountains and Cantera Resources Holdings LLC (the“Cantera Acquisition”).

The purchase price for Cantera consisted of $612.6 million in cash (including $50.1 million of estimated net working capital and other closing adjustments) and 3,245,817 Copano Class D units issued to the seller. Copano funded the cash portion of the purchase price through a private placement of $335 million in Copano equity securities pursuant to a Class E and Common Unit Purchase Agreement, dated August 31, 2007, among Copano and a group of accredited investors (the “Unit Purchase Agreement”), and borrowings under the Credit Facility discussed below.

Cantera’s assets consist primarily of 51.0% and 37.04% managing member interests, respectively, in Bighorn Gas Gathering, LLC (“Bighorn”) and Fort Union Gas Gathering, LLC (“Fort Union”). Bighorn and Fort Union operate natural gas pipeline systems in Wyoming’s Powder River Basin. The Bighorn system delivers natural gas into the Fort Union system.

Copano Class D Units

On October 19, 2007, Copano issued 3,245,817 Class D Units to the seller of Cantera in a private placement exempt from registration under Section 4(2) of the Securities Act of 1933 (the “Securities Act”). The Class D Units represent a new class of Copano units and are convertible into Copano common units on a one-for-one basis upon the earlier of (a) payment of Copano’s common unit distribution with respect to the fourth quarter of 2009, or (b) payment by Copano of $6.00 in cumulative distributions per unit (beginning with Copano’s distribution with respect to the fourth quarter of 2007) to its common unitholders.

Until they convert into common units, the Class D Units will not be entitled to receive cash distributions. The Class D Units will otherwise have the same terms and conditions as the Copano common units, including with respect to voting rights. No vote of Copano’s common unitholders will be required to convert the Class D Units to Copano common units.

Copano Class E Units and Common Units

Pursuant to the Unit Purchase Agreement, Copano issued and sold 5,598,836 Class E Units and 4,533,324 common units to accredited investors in a private placement exempt from registration under Section 4(2) of the Securities Act, for aggregate net proceeds of $335 million used to fund a portion of the cash consideration paid in connection with the Cantera Acquisition. The Class E Units represent a new class of Copano units that have no voting rights other than as required by law, are subordinate to Copano’s common units on dissolution and liquidation and have no distribution rights until Copano’s distribution with respect to the fourth quarter of 2008, when the Class E Units will become entitled to a special quarterly distribution equal to 110% of the quarterly common unit distribution. The Class E Units will convert into common units upon Copano’s payment of its distribution to common unitholders with respect to the third quarter of 2008, if the conversion terms of the Class E Units are approved by the requisite vote of Copano’s unitholders. Copano has agreed to hold a special meeting of its unitholders to consider this proposal as soon as feasible following October 19, 2007 but in no event later than 180 days thereafter.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Registration Rights

Pursuant to the Cantera Purchase Agreement, Copano and the Cantera seller entered into a registration rights agreement, dated October 19, 2007, under which Copano is obligated to file a shelf registration statement relating to resales of Copano common units issued upon conversion of the Class D Units within 60 days after the Class D Units convert to common units. The agreement also provides for unlimited piggyback registration rights after the conversion.

Pursuant to the Unit Purchase Agreement, Copano and the Class E Unit and common unit purchasers also entered into a registration rights agreement on October 19, 2007, under which Copano is obligated to file a shelf registration statement relating to resales of Copano common units (including common units that will be issued upon conversion of the Class E Units) within 60 days after October 19, 2007. The agreement also provides for unlimited piggyback registration rights.

Amended Credit Facility

On October 19, 2007, in connection with the Cantera Acquisition, we amended our Credit Facility and borrowed $300 million to fund the remaining portion of the cash consideration paid in connection with the Cantera Acquisition. This amendment to the Credit Facility, among other things:


	•	increased the aggregate borrowing capacity under the Credit Facility from $200 million to $550 million,

	•	extended the maturity date of the Credit Facility to October 18, 2012,

	•	reduced the commitment fee rates applicable at certain Consolidated Leverage Ratios (as defined in the Credit Facility) as set forth below:


Consolidated Leverage Ratio	Commitment Fee

³4.00:1 but <4.50:1		0.30	%
³3.50:1 but <4.00:1		0.25	%


	•	revised the interest rate provisions to provide for applicable rates ranging from 1.25% to 2.50% for rates determined using LIBOR, and from 0.25% to 1.50% for rates determined using the Base Rate (as defined in the Credit Facility). The applicable rates are dependent on Consolidated Leverage Ratios ranging from 3.00:1 to 5.00:1;

	•	revised covenants under the Credit Facility to accommodate Copano’s obligations as managing member of each of Bighorn and Fort Union, and to accommodate previously existing obligations of each entity;

	•	provided for swing line borrowings in addition to committed borrowings, and provides for LIBOR-based determination of interest on swing line borrowings;

	•	revised the minimum consolidated interest coverage ratio to 2.0:1; and

	•	increased the sublimit for the issuance of standby letters of credit to $50 million.

Copano and its wholly owned subsidiaries (including wholly owned subsidiaries newly formed or acquired after January 12, 2007) have pledged substantially all of their assets (except for certain equity interests held by Cantera and Cimmarron) to secure Copano’s obligations under the amended Credit Facility. Our less-than-wholly owned subsidiaries did not pledge their assets.

Interest Rate Swaps

In October 2007, we entered into two additional interest rate swap agreements with an aggregate notional amount of $70 million under which we exchanged the payment of variable rate interest on a portion of the principal outstanding under the Credit Facility for fixed rate interest. Under these agreements, we pay the counterparty the fixed interest rate of approximately 4.7% monthly and receive back from the counterparty a variable interest rate based on three-month LIBOR rates. The interest rate swap covers the period from October 2007 through October 2012 and the settlement amounts will be recognized as either an increase or decrease in interest expense.


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:


Bbls/d:		Barrels per day
Btu:		British thermal units
MMBtu:		One million British thermal units
MMBtu/d:		One million British thermal units per day
Mcf/d:		One thousand cubic feet per day
MMcf/d:		One million cubic feet per day
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
Throughput:		The volume of product 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 and natural gas processing facilities in Oklahoma and Texas, and, as a result of the Cantera Acquisition in October 2007, in Wyoming and Louisiana.

We manage our business and analyze and report our results of operations on a segment basis. As of September 30, 2007, our operations included four business segments, Mid-Continent Operations, Texas Gulf Coast Pipelines, Texas Gulf Coast Processing and Corporate. Following the Cantera Acquisition, which expanded Copano’s geographic footprint into the Powder River Basin of the Rocky Mountains as discussed in Note 13 to the unaudited consolidated financial statements, we expect to manage our acquired operations in Wyoming as the “Rocky Mountains Operations” business segment.


	•	Mid-Continent Operations is a provider of natural gas midstream services in Oklahoma and in north Texas, including natural gas gathering and related compression and dehydration services, natural gas processing and crude oil gathering. Our Mid-Continent Operations includes the results from the Cimmarron Acquisition for the period from May 1, 2007 through September 30, 2007. For the three months ended September 30, 2007 and 2006, this segment generated approximately 56% and 50%, respectively, of our total segment gross margin. For the nine months ended September 30, 2007 and 2006, this segment generated approximately 57% and 51%, respectively, of our total segment gross margin.

	•	Texas Gulf Coast Pipelines owns networks of natural gas gathering and intrastate pipelines in the Texas Gulf Coast region and is engaged in the gathering and intrastate transmission of natural gas. Within this segment, we also provide certain related services including compression, dehydration and marketing of natural gas. For the three months ended September 30, 2007 and 2006, this segment generated approximately 20% and 20%, respectively, of our total segment gross margin. For the nine months ended September 30, 2007 and 2006, this segment generated approximately 22% and 21%, respectively, of our total segment gross margin.

	•	Texas Gulf Coast Processing is engaged in natural gas processing, conditioning and treating and NGL fractionation and transportation through our Houston Central Processing Plant, Sheridan NGL Pipeline and, beginning in late 2007, our Brenham NGL Pipeline. Our natural gas processing plant is the second largest in the Texas Gulf Coast region and the third largest in Texas in terms of throughput capacity. Our plant is located approximately 100 miles southwest of Houston, Texas. For the three months ended September 30, 2007 and 2006, this segment generated approximately 35% and 30%, respectively, of our total segment


		gross margin. For the nine months ended September 30, 2007 and 2006, this segment generated approximately 31% and 28%, respectively, of our total segment gross margin.


	•	Corporate engages in risk management and other corporate activities. For the three months ended September 30, 2007 and 2006, this segment generated approximately (11)% and 0%, respectively, of our total segment gross margin. For the nine months ended September 30, 2007 and 2006, this segment generated approximately (10)% and 0%, respectively, of our total segment gross margin.

Total segment gross margin is a non-GAAP financial measure. For a reconciliation of total segment gross margin to its most directly comparable GAAP measure, please read “— Non-GAAP Financial Measures.”

Our total segment gross margins are determined primarily by four interrelated variables: (1) the volume of natural gas gathered or transported through our pipelines, (2) the volume and NGL content of natural gas processed, conditioned or treated at our processing plants or, on our behalf, at third-party processing plants, (3) the level and relationship of natural gas and NGL prices and (4) our current contract portfolio. 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 prices and market demand for natural gas and NGLs, which fluctuate with changes in market and economic conditions and other factors.

Our Mid-Continent Operations’ unit margins are, on the whole, positively correlated with NGL prices and natural gas prices. The unit margins we realize from a significant portion of the natural gas gathered or transported by our Texas Gulf Coast Pipelines segment decrease during periods of low natural gas prices because our unit margins on such natural gas volumes are based on a percentage of the index price. The profitability of our Texas Gulf Coast Processing segment is dependent upon the relationship between natural gas and NGL prices. When natural gas prices are low relative to NGL prices, it is more profitable for our Texas Gulf Coast Processing segment to process natural gas than to condition it. Conversely, when natural gas prices are high relative to NGL prices, processing is less profitable or unprofitable. During such periods, our Houston Central Processing Plant has the flexibility to condition natural gas rather than fully process it. Conditioning natural gas, however, is less profitable than processing during periods when the value of recovered NGLs exceeds the value of natural gas required for plant fuel and to replace the reduced Btus that result from processing the natural gas.

How We Evaluate Our Operations

We believe that investors benefit from having access to the same financial measures that our management uses in evaluating our performance. Our management uses a variety of financial and operational measurements to analyze our performance. These measurements include the following: (1) throughput volumes; (2) segment gross margin; (3) operations and maintenance expenses; (4) general and administrative expenses; (5) EBITDA; and (6) distributable cash flow.

Throughput Volumes. Throughput volumes associated with our business are an important part of our operational analysis. We continually evaluate volumes on our pipelines to ensure that we have adequate throughput to meet our financial objectives. It is important that we continually add new volumes to our gathering systems to offset or exceed the normal decline of existing volumes that are attached to those systems. Our performance at our processing plants is significantly influenced by both the volume of natural gas coming into the plant and the NGL content of the natural gas. 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 associated with our pipeline operations, these costs are frequently passed on to our producers.

Segment Gross Margin. We define total segment gross margin as our segment revenue minus cost of sales. Cost of sales includes the following costs and expenses: cost of natural gas and NGLs purchased by us from third parties, cost of natural gas and NGLs purchased by us from affiliates, costs we pay third parties to transport our volumes and costs we pay our affiliates to transport our volumes. We view total segment gross margin as an

important performance measure of the core profitability of our operations. The total segment gross margin data reflect the financial impact on our company of our contract portfolio. With respect to our Mid-Continent Operations segment, our management analyzes segment gross margin per unit of volumes gathered or transported, per unit of natural gas processed and per unit of NGLs recovered. With respect to our Texas Gulf Coast Pipelines segment, our management analyzes segment gross margin per unit of volumes gathered or transported. With respect to our Texas Gulf Coast Processing segment, our management also analyzes segment gross margin per unit of natural gas processed or conditioned and the segment gross margin per unit of NGLs recovered. Our total segment gross margin is reviewed monthly for consistency and trend analysis.

To isolate and consistently track changes in commodity price relationships and their impact on our Texas Gulf Coast Processing segment’s results, we calculate a hypothetical “standardized” processing margin. This processing margin is based on a fixed set of assumptions, with respect to liquids 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 financial results are not derived from this standardized processing margin and the standardized margin is not derived from our financial results. However, we believe this calculation is representative of the current operating commodity price environment of our Texas Gulf Coast Processing operations and we use this calculation to track commodity price relationships. 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. Our standardized processing margins averaged $0.54 per gallon during the third quarter of 2007 compared to $0.41 per gallon during the third quarter of 2006. Our standardized processing margins averaged $0.36 per gallon during the nine months ended September 30, 2007 compared to $0.28 per gallon during the nine months ended September 30, 2006. The average standardized processing margin for the period from 1989 through September 30, 2007 is $0.11 per gallon.

Operations and Maintenance Expenses. Operations and maintenance expenses are costs associated with the operations of a specific asset. Direct labor, insurance, ad valorem taxes, repair and maintenance, utilities and contract services comprise the most significant portion of operations and maintenance expenses. 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 are incurred through Copano Operations which is controlled by Mr. Eckel. 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.

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. 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.

Pursuant to our limited liability company agreement, our Pre-IPO Investors have agreed to reimburse us for our general and administrative expenses in excess of stated levels (subject to certain limitations discussed below) for a period of three years beginning on January 1, 2005. Specifically, to the extent our general and administrative expenses exceed the following levels, the portion of the general and administrative expenses ultimately funded by us (subject to certain adjustments and exclusions) will be limited, or capped, as indicated:


Year	General and Administrative Expense Limitations

1	$	1.50 million per quarter
2	$	1.65 million per quarter
3	$	1.80 million per quarter

During this three-year period, the quarterly limitation on general and administrative expenses will be increased by 10% of the amount by which EBITDA (as defined below) for any quarter exceeds $5.4 million. Additionally, the cap may be extended beyond its initial three-year term at the same or a higher level by the affirmative vote of at least

95% of 11,114,756 common units held by our Pre-IPO Investors or certain of their assignees, voting together as a single class. We believe that an extension of the cap is unlikely; however, such determination will be made in the sole discretion of our Pre-IPO Investors. This cap on general and administrative expenses excludes non-cash expenses as well as expenses we may incur in connection with potential acquisitions and capital improvements.

Pursuant to our limited liability company agreement, the reimbursement obligations of our Pre-IPO Investors are limited solely to the amount of the distributions attributable to the 11,114,756 common and subordinated units owned by the Pre-IPO Investors immediately prior to our IPO (the “Pre-IPO Units”). As a result of the conversion of our subordinated units to common units on a one-for-one basis effective February 14, 2007, these quarterly obligations will not exceed the amount of distributions we pay on 11,114,756 common units for the quarter for which the obligations are incurred. In order to facilitate the payment of any reimbursement obligation, our limited liability company agreement provides that we may deposit any distributions that are required to cover the obligation and are otherwise payable to our Pre-IPO Investors, directly in the Pre-IPO Investors’ escrow accounts. Also, to the extent that any of our Pre-IPO Investors sell Pre-IPO Units, the buyer must assume the related reimbursement obligations or the selling Pre-IPO Investor must deposit certain funds in its escrow account to secure the payment of any future reimbursement obligation with respect to the units transferred. During the nine months ended September 30, 2007, Pre-IPO Investors made capital contributions to us in the aggregate amounts of $7.2 million as reimbursement of excess general and administrative expenses for the fourth quarter of 2006 and the first and second quarters of 2007. Based on the level of our general and administrative expenses for the third quarter of 2007, our Pre-IPO Investors will be obligated to make capital contributions to us in the aggregate amounts of $2.8 million as reimbursement of excess general and administrative expenses for this period.

EBITDA. We define EBITDA as net income plus interest expense, provision for income taxes and depreciation and amortization expense. EBITDA is used as a supplemental financial measure by our management and by external users of our financial statements, such as investors, commercial banks, research analysts and others, 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 measurement that, with certain negotiated adjustments, is reported to our lenders and is used to compute our financial covenants under our Credit Facility. EBITDA should not be considered an alternative to net income, operating income, cash flows from operating activities or any other measure of financial performance presented in accordance with GAAP.

Distributable Cash Flow. We define distributable cash flow as net income plus: (i) depreciation and amortization expense; (ii) cash distributions received from investments in unconsolidated affiliates and equity losses from such unconsolidated affiliates; (iii) reimbursements by our Pre-IPO Investors of certain general and administrative expenses in excess of the “G&A Cap” defined in our limited liability company agreement; (iv) provision for deferred income taxes; (v) the subtraction of maintenance capital expenditures; (vi) the subtraction of equity in earnings from unconsolidated affiliates; and (vii) the addition of losses or subtraction of gains relating to other miscellaneous non-cash amounts affecting net income for the period. 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. Distributable cash flow is a significant performance metric used by our 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. Using this metric, our management can quickly compute the coverage ratio of estimated cash flows to planned cash distributions. Distributable cash flow is also an important non-GAAP financial measure for

our unitholders since it serves as an indicator of our success in providing a cash return on investment. Specifically, this financial measure indicates to investors whether or not we are generating cash flow at a level that can sustain or support an increase in our quarterly distribution rates. Distributable cash flow is also a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and limited liability companies because the value of a unit of such an entity is generally determined by the unit’s yield (which in turn is based on the amount of cash distributions the entity can pay to a unitholder).

How We Manage Our Operations

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

Our Economic Models. We utilize our economic models to determine (i) whether we should elect payment under certain Mid-Continent Operations’ “switch” contracts using a percentage-of-index basis or a percentage-of-proceeds basis, (ii) whether we should reduce the ethane extracted from certain natural gas processed by our processing plants and (iii) whether we should process or condition natural gas at our Houston Central Processing Plant.

Flow and Transaction Monitoring Systems. We utilize automated systems that track commercial and operational activity on each of our pipelines and monitor the flow of natural gas on our pipelines. For our Mid-Continent Operations, we electronically monitor pipeline volumes and operating conditions at certain key points along our pipeline systems. In our Texas Gulf Coast Pipelines operations, we utilize 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 utilize an automated Supervisory Control and Data Acquisition (SCADA) system, which assists our management in monitoring and operating our Texas Gulf Coast Pipelines segment. The SCADA system allows us to monitor our assets at remote locations and respond to changes in pipeline operating conditions from our Houston office.

Producer Activity Evaluation and Reporting. We monitor the producer drilling and completion activity in our areas of operation to identify anticipated changes in production and potential new well attachment opportunities. The continued attachment 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. 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.

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 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 a pre-determined pricing formula. This provision ensures 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

Our growth strategy contemplates 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 intend to pursue acquisitions and capital expenditure 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, including other areas of Texas and Oklahoma and in New Mexico and the Rocky Mountains region, to the extent they present growth opportunities similar to those we are pursuing in

our existing areas of operations. To successfully execute our growth strategy, we will require access to capital on competitive terms. We believe that our long-term cost of equity capital will be favorable because unlike many of our competitors that are master limited partnerships, or MLPs, neither our management nor any other party holds incentive distribution rights that entitle them to increasing percentages of cash distributions as higher per unit levels of cash distributions are received. We intend to finance future acquisitions primarily through funds generated from our operations, borrowings under credit facilities and the issuance of additional debt or equity as appropriate given market conditions. For a more detailed discussion of our capital resources, please read “— Liquidity and Capital Resources.”

Acquisition Analysis. In analyzing a particular acquisition, we consider the operational, financial and strategic benefits of the transaction. Our analysis includes location of the assets, condition of the assets, strategic fit of the assets in relation to our business strategy, expertise required to manage the assets, capital required to integrate and maintain the assets and the competitive environment of the area where the assets are located. From a financial perspective, we analyze the rate of return the assets will generate under various case scenarios, comparative market parameters and the additive earnings and cash flow capabilities of the assets.

Capital Expenditure Analysis. We make capital expenditures either to maintain our assets or the supply of natural gas volumes to our assets or for expansion projects to increase our total segment gross margin. 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. Expansion capital expenditures represent 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. Our decisions whether to spend capital on expansion projects are generally based on anticipated earnings, cash flow and rate of return 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 statements related to plans for growth of the 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 forecast 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 assets 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;

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

	•	our ability to retain our key customers;


	•	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 without limitation in conjunction with the forward-looking statements that are referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in our Annual Report on Form 10-K for the year ended December 31, 2006 as updated by our Quarterly Report on Form 10-Q for the period ended March 31, 2007 and in Item 1A “Risk Factors” and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this report. 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, other than as required by law, 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.

Our Results of Operations


							Nine Months Ended
	Three Months Ended September 30,						September 30,
	2007			2006			2007			2006
	($ in thousands)

Total segment gross margin(1)	$	55,885		$	55,972		$	140,645		$	140,654
Operations and maintenance expenses		10,525			8,519			28,700			23,527
Depreciation and amortization		10,130			8,182			28,426			23,657
General and administrative expenses		8,615			8,108			23,831			19,919
Taxes other than income		1,010			622			2,566			1,610
Equity in (earnings) loss from unconsolidated affiliates		(401	)		(549	)		(2,019	)		(644	)

Operating income		26,006			31,090			59,141			72,585
Interest and other financing costs, net		(6,237	)		(8,807	)		(16,282	)		(24,002	)
Provision for income taxes		(102	)		—			(1,182	)		—

Net income	$	19,667		$	22,283		$	41,677		$	48,583

Segment gross margin:
Mid-Continent Operations	$	31,230		$	27,869		$	80,518		$	72,036
Texas Gulf Coast Pipelines(2)		11,215			11,503			30,699			29,387
Texas Gulf Coast Processing		19,437			16,934			44,285			38,906
Corporate(3)		(5,997	)		(334	)		(14,857	)		325

Total segment gross margin(1)	$	55,885		$	55,972		$	140,645		$	140,654

Segment gross margin per unit:
Mid-Continent Operations:(4)
Pipeline throughput ($/MMBtu)(4)	$	1.49		$	1.64		$	1.42		$	1.51
Plant Inlet throughput ($/MMBtu)(4)	$	2.04		$	2.30		$	1.95		$	2.15
NGLs produced ($/Bbl)(4)	$	21.14		$	23.82		$	20.41		$	22.99
Texas Gulf Coast Pipelines ($/MMBtu)(2)	$	0.44		$	0.48		$	0.41		$	0.44
Texas Gulf Coast Processing:
Inlet throughput ($/MMBtu)(5)	$	0.41		$	0.35		$	0.29		$	0.28
NGLs produced ($/Bbl)(5)	$	12.88		$	12.54		$	9.91		$	9.86
Volumes:
Mid-Continent Operations(4)
Pipeline throughput (MMBtu/d)(4)		227,099			184,247			207,572			174,772
Plant Inlet throughput (MMBtu/d)(4)		166,175			131,501			151,131			122,628
NGLs produced (Bbls/d)(4)		16,058			12,717			14,452			11,475
Texas Gulf Coast Pipelines — throughput (MMBtu/d)(2)		277,083			262,986			277,477			246,212
Texas Gulf Coast Processing:
Inlet throughput (MMBtu/d)		520,341			531,069			551,260			513,567
NGLs produced (Bbls/d)		16,402			14,673			16,364			14,446
Capital Expenditures:
Maintenance capital expenditures	$	2,735		$	3,394		$	7,198		$	7,320
Expansion capital expenditures		15,806			19,232			163,976			35,630

Total capital expenditures	$	18,541		$	22,626		$	171,174		$	42,950

Operations and maintenance expenses:
Mid-Continent Operations	$	6,287		$	4,466		$	15,801		$	12,382
Texas Gulf Coast Pipelines		2,086			1,634			6,503			5,163
Texas Gulf Coast Processing		2,152			2,419			6,396			5,982

Total operations and maintenance expenses	$	10,525		$	8,519		$	28,700		$	23,527


(1)		Total segment gross margin is a non-GAAP financial measure. For a reconciliation of total segment gross margin to its most directly comparable GAAP measure, please read “— Non-GAAP Financial Measures.”

(2)		Excludes results and volumes associated with our interest in Webb Duval. Gross volumes transported by Webb Duval were 86,881 MMBtu/d and 118,765 MMBtu/d, net of intercompany volumes, for the three months ended


		September 30, 2007 and 2006, respectively. Gross volumes transported by Webb Duval were 99,212 MMBtu/d and 116,429 MMBtu/d, net of intercompany volumes, for the nine months ended September 30, 2007 and 2006, respectively.

(3)		The Corporate segment gross margin includes results attributable to Copano’s commodity risk management activities.

(4)		Segment gross margin per unit amounts for the Mid-Continent Operations are calculated as the segment gross margin divided by the pipeline throughput, inlet throughput or NGLs produced, as appropriate. Plant inlet throughput and NGLs produced represent total volumes processed and produced by the Mid-Continent Operations segment at all plants, including plants owned by the Mid-Continent Operations segment and plants owned by third parties. For the three months ended September 30, 2007, plant inlet throughput averaged 97,013 MMBtu/d and NGLs produced averaged 10,110 barrels per day for plants owned by the Mid-Continent Operations segment. For the three months ended September 30, 2006, plant inlet throughput averaged 86,848 MMBtu/d and NGLs produced averaged 8,672 barrels per day for plants owned by the Mid-Continent Operations segment. For the nine months ended September 30, 2007, plant inlet throughput averaged 90,476 MMBtu/d and NGLs produced averaged 9,210 barrels per day for plants owned by the Mid-Continent Operations segment. For the nine months ended September 30, 2006, plant inlet throughput averaged 80,140 MMBtu/d and NGLs produced averaged 7,746 barrels per day for plants owned by the Mid-Continent Operations segment.

(5)		Represents the total processing segment gross margin divided by the total inlet throughput or NGLs produced, as appropriate.

Three Months Ended September 30, 2007 Compared with Three Months Ended September 30, 2006

Mid-Continent Operations Segment Gross Margin. Mid-Continent Operations segment gross margin was $31.2 million for the three months ended September 30, 2007, which included $2.9 million related to Cimmarron (acquired May 1, 2007) compared to $27.9 million for the three months ended September 30, 2006, an increase of $3.3 million, or 12%. The increase in segment gross margin resulted primarily from a 26% increase in NGLs produced, a 26% increase in plant inlet throughput, a 23% increase in pipeline throughput offset by a reduced unit margins as a result of lower natural gas prices. The Cimmarron Acquisition accounted for 53% of the increase in NGLs produced, 61% of the increase in plant inlet throughput and 54% of the increase pipeline throughput for this segment. NGLs produced at the Paden Processing Plant increased 21% during the third quarter of 2007 as compared to the same period in 2006. Cimmarron’s throughput on its crude oil system averaged 3,574 barrels per day for three months ended September 30, 2007. During the third quarter of 2007, the CenterPoint East natural gas index price averaged $5.50 per MMBtu compared to $5.96 per MMBtu during the third quarter of 2006, a decrease of $0.46, or 8%.

Texas Gulf Coast Pipelines Segment Gross Margin. Texas Gulf Coast Pipelines segment gross margin was $11.2 million for the three months ended September 30, 2007 compared to $11.5 million for the three months ended September 30, 2006, a decrease of $0.3 million, or 3%. The decrease was primarily attributable to lower unit margins during the third quarter of 2007 partially offset by a 5% increase in pipeline throughput volumes during the three months ended September 30, 2007 compared to the three months ended September 30, 2006. During the third quarter of 2007, the Houston Ship Channel, or HSC, natural gas index price averaged $5.89 per MMBtu compared to $6.14 per MMBtu during the third quarter of 2006, a decrease of $0.25, or 4%.

Texas Gulf Coast Processing Segment Gross Margin. Texas Gulf Coast Processing segment gross margin was $19.4 million for the three months ended September 30, 2007 compared to $16.9 million for the three months ended September 30, 2006, an increase of $2.5 million, or 15%. For the three months ended September 30, 2007, we experienced an increase of $3.4 million in our processing segment gross margin primarily as a result of increased NGL margins and output at our Houston Central Processing Plant offset by an increase of $0.9 million in upgrade payments to natural gas suppliers, including our Texas Gulf Coast Pipelines segment, during the third quarter of 2007 as compared to the third quarter of 2006. Conditioning fee revenue was effectively flat quarter over quarter. For a discussion of the commodity price environment affecting our Texas Gulf Coast Processing segment, please read “— How We Evaluate Our Operations — Segment Gross Margin.”

Corporate Segment Gross Margin. The corporate segment includes our commodity risk management activities. Gross margin for this segment was a loss of $6.0 million for the three months ended September 30, 2007 compared to a loss of $0.3 million for the three months ended September 30, 2006. The corporate segment gross margin loss for the three months ended September 30, 2007 is comprised of (i) $5.7 million of non-cash amortization expense related to purchased commodity derivatives and (ii) $0.8 million of unrealized losses related to mark-to-market changes and ineffective portions of the hedges offset by $0.5 million of cash settlements on expired commodity derivatives. The corporate segment gross margin loss for the three months ended September 30, 2006 consisted of $2.4 million of cash settlements on expired commodity derivatives offset by $2.7 million of non-cash amortization expense related to purchased commodity derivatives.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $10.5 million for the three months ended September 30, 2007 compared to $8.5 million for the three months ended September 30, 2006. The increase of $2.0 million, or 24%, is primarily attributable to (i) $1.3 million of expenses incurred by Cimmarron, which was acquired on May 1, 2007, (ii) increased labor, compression, insurance, materials and supplies and repair expenses in our Mid-Continent Operations segment of $0.5 million, (iii) increased labor, measurement and repair and maintenance expenses of $0.4 million in our Texas Gulf Coast Pipelines segment offset by (iv) decreased repair and maintenance expenses of $0.2 million in our Texas Gulf Coast Processing segment.

Depreciation and Amortization. Depreciation and amortization totaled $10.1 million for the three months ended September 30, 2007 compared with $8.2 million for the three months ended September 30, 2006, an increase of $1.9 million, or 23%. This increase relates primarily to additional depreciation and amortization associated with acquisitions and capital expenditures made after September 30, 2006, including the Cimmarron Acquisition on May 1, 2007.

General and Administrative Expenses. General and administrative expenses totaled $8.6 million for the three months ended September 30, 2007 compared with $8.1 million for the three months ended September 30, 2006, an increase of $0.5 million, or 6%. The increase primarily relates to (i) expenses related to additional personnel, consultants and compensation adjustments of $1.1 million, (ii) expenses incurred by our Mid-Continent Operations segment of $0.9 million including expenses related to Cimmarron, acquired May 1, 2007, of $0.4 million and (iii) non-cash compensation expense related to the amortization of the fair value of restricted units, phantom units and unit options issued to employees and directors of $0.1 million offset by a decrease of $1.6 million related to expenses associated with acquisition initiatives that were not consummated.

Interest Expense. Interest and other financing costs totaled $6.9 million for the three months ended September 30, 2007 compared with $9.5 million for the three months ended September 30, 2006, a decrease of $2.6 million, or 27%. Interest expense related to our Credit Facility totaled $2.0 million (net of $0.2 million of capitalized interest and settlements under our interest rate swaps) and $2.8 million (net of $0.2 million of capitalized interest and settlements under our interest rate swaps) for the three months ended September 30, 2007 and 2006, respectively. Interest on our Senior Notes totaled $4.6 million for each of the three months ended September 30, 2007 and 2006. Amortization of debt issue costs totaled $0.3 million and $2.1 million for the three months ended September 30, 2007 and 2006, respectively. Amortization of debt issue costs for the three months ended September 30, 2006 included a one-time charge of $1.7 million related to the reduction of the commitment under the Credit Facility from $350 million to $200 million. Average borrowings under our credit arrangements were $354.7 million and $100 million with average interest rates of 7.9% and 7.3% for the third quarter of 2007 and 2006, respectively. For additional information about our credit arrangements, please read “— Liquidity and Capital Resources — Our Indebtedness.”

Nine Months Ended September 30, 2007 Compared with Nine Months Ended September 30, 2006

Mid-Continent Operations Segment Gross Margin. Mid-Continent Operations segment gross margin was $80.5 million for the nine months ended September 30, 2007, which included $4.8 million related to Cimmarron (acquired May 1, 2007) compared to $72.0 million for the nine months ended September 30, 2006, an increase of $8.5 million, or 12%. The increase in segment gross margin resulted primarily from a 26% increase in NGLs produced, a 23% increase in plant inlet throughput and a 19% increase in pipeline throughput offset by reduced unit margins as a result of lower natural gas prices. The Cimmarron Acquisition accounted for 32% of the increase in

NGLs produced, 41% of the increase in plant inlet throughput and 38% of the increase pipeline throughput for this segment. NGLs produced at the Paden Processing Plant increased 25% during the first nine months of 2007 as compared to the same period in 2006. Cimmarron’s throughput on its crude oil system averaged 3,582 barrels per day for the period from May 1, 2007 through September 30, 2007. During the nine months ended September 30, 2007, the CenterPoint East natural gas index price averaged $6.11 per MMBtu compared to $6.33 per MMBtu during the nine months ended September 30, 2006, a decrease of $0.22, or 3%.

Texas Gulf Coast Pipelines Segment Gross Margin. Texas Gulf Coast Pipelines segment gross margin was $30.7 million for the nine months ended September 30, 2007 compared to $29.4 million for the nine months ended September 30, 2006, an increase of $1.3 million, or 4%. The increase was primarily attributable to increased throughput offset by lower natural gas prices during the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006, which resulted in a decrease in margins associated with our index price-related gas purchase and transportation arrangements. During the nine months ended September 30, 2007, the HSC natural gas index price averaged $6.56 per MMBtu compared to $6.71 per MMBtu during the nine months ended September 30, 2006, a decrease of $0.15, or 2%.

Texas Gulf Coast Processing Segment Gross Margin. Texas Gulf Coast Processing segment gross margin was $44.3 million for the nine months ended September 30, 2007 compared to $38.9 million for the nine months ended September 30, 2006, an increase of $5.4 million, or 14%. For the nine months ended September 30, 2007, we experienced improvements of $6.5 million in our processing segment gross margin primarily as a result of increased NGL margins and output at our Houston Central Processing Plant. This improvement in our processing segment gross margin was offset by (i) an increase of $0.8 million in upgrade payments to natural gas suppliers, including our Texas Gulf Coast Pipelines segment, during the nine months ended September 30, 2007 as compared to the same period in 2006 and (ii) decreased conditioning fee revenue of $0.3 million. For a discussion of the commodity price environment affecting our Texas Gulf Coast Processing segment, please read “— How We Evaluate Our Operations — Segment Gross Margin.”

Corporate Segment Gross Margin. The corporate segment includes our commodity risk management activities. Gross margin for this segment was a loss of $14.9 million for the nine months ended September 30, 2007 compared to a gain of $0.3 million for the nine months ended September 30, 2006. The corporate segment gross margin loss for the nine months ended September 30, 2007 is comprised of $16.0 million of non-cash amortization expense related to purchased commodity derivatives and $2.7 million of unrealized losses related to mark-to-market changes and ineffective portions of hedges offset by $3.8 million of cash settlements on expired commodity derivatives. The corporate segment gross margin gain for the nine months ended September 30, 2006 consisted of $8.2 million of cash settlements on expired commodity derivatives offset by $7.6 million of non-cash amortization expense related to purchased commodity derivatives and $0.3 million of unrealized losses related to the ineffective portion of hedges.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $28.7 million for the nine months ended September 30, 2007 compared to $23.5 million for the nine months ended September 30, 2006. The increase of $5.2 million, or 22%, is primarily attributed to (i) increased labor, compression, insurance materials and supplies and repair expenses in our Mid-Continent Operations segment of $1.4 million, (ii) $2.0 million of expenses incurred by Cimmarron which was acquired on May 1, 2007, (iii) increased labor, chemicals, utilities, lease rentals and and repair and maintenance expenses of $1.3 million in our Texas Gulf Coast Pipelines segment and $0.5 million in our Texas Gulf Coast Processing segment.

Depreciation and Amortization. Depreciation and amortization totaled $28.4 million for the nine months ended September 30, 2007 compared with $23.7 million for the nine months ended September 30, 2006, an increase of $4.7 million, or 20%. This increase relates primarily to additional depreciation and amortization associated with acquisitions and capital expenditures made after September 30, 2006, including the Cimmarron Acquisition on May 1, 2007.

General and Administrative Expenses. General and administrative expenses totaled $23.8 million for the nine months ended September 30, 2007 compared with $19.9 million for the nine months ended September 30, 2006, an increase of $3.9 million, or 20%. The increase primarily relates to (i) expenses primarily related to additional personnel, consultants and office space and compensation adjustments of $2.2 million, (ii) expenses

incurred by our Mid-Continent Operations segment of $1.2 million including expenses related to Cimmarron, acquired May 1, 2007, of $0.6 million, (iii) legal and accounting fees of $0.7 million, (iv) non-cash compensation expense related to the amortization of the fair value of restricted units, phantom units and unit options issued to employees and directors of $0.5 million and (iv) costs of preparing and processing tax K-1s to unitholders of $0.2 million offset by a decrease of $0.9 million related to expenses associated with acquisition initiatives that were not consummated.

Interest Expense. Interest and other financing costs totaled $18.3 million for the nine months ended September 30, 2007 compared with $25.3 million for the nine months ended September 30, 2006, a decrease of $7.0 million, or 28%. Interest expense related to our Credit Facility totaled $3.7 million (net of $0.8 million of capitalized interest and settlements under our interest rate swaps) and $8.4 million (net of $0.5 million of capitalized interest and settlements under our interest rate swaps) for the nine months ended September 30, 2007 and 2006, respectively. Interest on our Senior Notes totaled $13.7 million and $11.9 million for the nine months ended September 30, 2007 and 2006, respectively. Interest on our unsecured term loan totaled $1.5 million for the nine months ended September 30, 2006. Amortization of debt issue costs totaled $0.9 million and $3.5 million for the nine months ended September 30, 2007 and 2006, respectively. Amortization of debt issue costs for the three months ended September 30, 2006 included a one-time charge of $1.7 million related to the reduction of the commitment under the Credit Facility from $350 million to $200 million. Average borrowings under our credit arrangements were $308.7 million and $224.0 million with average interest rates of 8% and 6.8% for the nine months ended September 30, 2007 and 2006, respectively. For additional information about our credit arrangements, please read “— Liquidity and Capital Resources — Our Indebtedness.”

Liquidity and Capital Resources

Cash generated from operations, borrowings under our Credit Facility, as amended, (see discussion in Note 13 to the unaudited consolidated financial statements) and funds from equity and debt offerings are our primary sources of liquidity. We believe that funds from these sources should be sufficient to meet both our short-term working capital requirements and our long-term capital expenditure requirements. Our ability to pay distributions to our unitholders, to fund planned capital expenditures and to make acquisitions will depend upon our future operating performance and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing economic conditions in our industry and financial, business and other factors, some of which are beyond our control.

Off-Balance Sheet Arrangements. We had no off-balance sheet arrangements as of September 30, 2007.

Capital Requirements. 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 such as those to acquire additional assets to grow our business, to expand and upgrade gathering systems, transmission capacity, processing plants and to construct or acquire new pipelines or processing plants.

Given our objective of growth through acquisitions, we anticipate that we will continue to invest significant amounts of capital to grow and acquire assets. We actively consider a variety of assets for potential acquisitions. For a discussion of the primary factors we consider in deciding whether to pursue a particular acquisition, please read “— Our Growth Strategy — Acquisition Analysis.”

During the nine months ended September 30, 2007, our capital expenditures totaled $171.2 million consisting of $7.2 million of maintenance capital and $164.0 million of expansion capital including the Cimmarron Acquisition. Additional expansion capital expenditures included the acquisition and construction of small pipeline systems, purchases of compressors and constructing well interconnects to attach volumes in new areas. We funded

our capital expenditures with funds from operations, borrowings under the Credit Facility and the issuance of additional equity. We expect to fund future capital expenditures with funds generated from our operations, borrowings under our Credit Facility and the issuance of additional equity or debt as appropriate given market conditions. Based on our current scope of operations, we anticipate incurring approximately $10.0 million to $12.0 million of maintenance capital expenditures over the next 12 months.

Operating Cash Flows.


	Nine Months Ended
	September 30,
	2007			2006
	(In thousands)

Net income	$	41,677		$	48,583
Depreciation and amortization		29,347			27,181
Equity in earnings from unconsolidated affiliates		(2,019	)		(644	)
Distributions from unconsolidated affiliates		2,888			—
Equity-based compensation and other		2,980			1,409
Cash (used in) provided by working capital		(6,535	)		20,098

Net cash provided by operating activities	$	68,338		$	96,627

The overall decrease of $28.3 million in operating cash flow for the nine months ended September 30, 2007 compared to the nine months ended September 30, 2006 was primarily the result of (i) a decrease in net income of $6.9 million and (ii) decreases in working capital components (exclusive of cash and cash equivalents) of $26.6 million, offset by (iii) an increase in distributions from Webb Duval and Southern Dome, our unconsolidated affiliates, of $2.9 million, (iv) an increase in non-cash items of $2.3 million. The decrease in the changes in working capital components (exclusive of cash and cash equivalents) was primarily the result of increases in accounts receivable and prepaid items of $34.1 million and in risk management activities of $26.0 million offset by increases in accounts payable of $33.5 million.

We believe that we will continue to have adequate liquidity to fund future recurring operating and investing activities. Our primary cash requirements consist of normal operating expenses, capital expenditures to sustain existing operations and revenue generating expenditures, interest payments on our Credit Facility and Senior 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 Credit Facility and the issuance of additional equity and debt securities, as appropriate. Our ability to complete future debt and equity offerings and the timing of any such offerings will depend on various factors, including prevailing market conditions, interest rates, our financial condition and our credit rating at the time.

Investing Cash Flows. Net cash used in investing activities was $115.9 million for the nine months ended September 30, 2007 compared to $51.1 million for the nine months ended September 30, 2006. Investing activities for 2007 included (i) $55.5 million of capital expenditures related to the Cimmarron Acquisition, (ii) $59.9 million of capital expenditures related to bolt-on pipeline acquisitions, the expansion and modification of our Paden Processing Plant and progress payments for the purchase of compression and (iii) 0.9 million of costs primarily associated with the Cantera Acquisition offset by (iv) $0.4 million of distributions from Southern Dome in excess of equity earnings and other. Investing activities for 2006 included (i) $40.0 million of capital expenditures for several small bolt-on pipeline acquisitions, costs related to the construction of an 11-mile pipeline to our Provident City System, progress payments for the purchase of compression, the installation of an additional amine treater and a modification of an existing amine treater at the Houston Central Processing Plant, the addition and installation of a refrigeration unit and condensate stabilizer at the Paden Processing Plant in Oklahoma and the construction of an 8-mile pipeline between two compressor stations in our Mid-Continent Operations area and (ii) a $11.1 million

investment in Southern Dome for the construction of a processing plant and residue pipelines that began operations in late April 2006.

Financing Cash Flows. Net cash provided by financing activities totaled $56.0 million during the nine months ended September 30, 2007 and included (i) borrowing under our Credit Facility of $104.0 million, (ii) capital contributions of $7.2 million from our Pre-IPO Investors and (iii) proceeds from the exercise of unit options of $0.8 million, offset by (a) repayments under our debt arrangements of $1.5 million, (b) distributions to our unitholders of $53.4 million, (c) deferred financing costs of $0.6 million and (d) equity offering costs of $0.5 million. Net cash used in financing activities totaled $36.2 million during the nine months ended September 30, 2006 and included (i) net proceeds from our private placement of common units of $24.4 million, (ii) capital contributions of $4.0 million from our Pre-IPO Investors and (iii) proceeds from the exercise of unit options of $0.2 million, offset by (a) net repayments under our debt arrangements of $24.5 million, (b) distributions to our unitholders of $33.3 million and (c) deferred financing costs of $7.0 million.

Cash Distributions and Reserves: Within 45 days after the end of each quarter, we intend to pay quarterly cash distributions in arrears (in February, May, August and November of each year), to the extent we have sufficient available cash from operating surplus as defined in our limited liability company agreement.

Our Board of Directors has broad discretion to establish cash reserves that it determines are necessary or appropriate to properly conduct our business. These can include cash reserves for future capital and maintenance expenditures, reserves to stabilize distributions of cash to the unitholders, reserves to reduce debt or, as necessary, reserves to comply with the terms of any of our agreements or obligations.

On January 18, 2007, our Board of Directors declared a cash distribution for the three months ended December 31, 2006 of $0.40 per unit, or $1.60 per unit annualized, for all outstanding common and subordinated units. The distribution totaling $17.0 million was paid on February 14, 2007 to holders of record at the close of business on February 1, 2007.

On April 18, 2007, our Board of Directors declared a cash distribution for the three months ended March 31, 2007 of $0.42 per unit, or $1.68 per unit annualized, for all outstanding common units. The distribution totaling $17.9 million was paid on May 15, 2007 to holders of record at the close of business on May 1, 2007.

On July 18, 2007, our Board of Directors declared a cash distribution for the three months ended June 30, 2007 of $0.44 per unit, or $1.76 per unit annualized, for all outstanding common units. The distribution totaling $18.7 million was paid on August 14, 2007 to holders of record at the close of business on August 1, 2007.

On October 17, 2007, our Board of Directors declared a cash distribution for the three months ended September 30, 2007 of $0.47 per unit, or $1.88 per unit annualized, for all outstanding common units eligible for distributions. The distribution totaling $20.3 million will be paid on November 14, 2007 to holders of record of eligible outstanding common units at the close of business on November 1, 2007.

The amounts required to pay the current distribution of $0.47 per unit, or $1.88 per unit annualized, to our common unitholders is $22.4 million per quarter, or $89.6 million annualized, based on the total number of common units outstanding as of November 1, 2007. These amounts include distributions related to restricted 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 respective restricted units and phantom units. As of November 1, 2007, we had 349,956 outstanding restricted and phantom units. These amounts do not include future distributions on common units underlying our 1,184,557 outstanding Class C units which automatically convert to common units in one-third installments on May 1, 2008, November 1, 2008 and May 1, 2009 or future distributions on the common units underlying our Class D or Class E units issued in connection with the Cantera Acquisition discussed in Note 13 to the unaudited consolidated financial statements.

Our Indebtedness

As of September 30, 2007, our aggregate outstanding indebtedness totaled $359.0 million. Subsequent to our acquisition of Cantera on October 19, 2007, discussed in Note 13 to the unaudited consolidated financial statements, our aggregate outstanding indebtedness totaled $659.0 million.

Credit Ratings. Moody’s Investors Service has assigned a Corporate Family Rating to us of B1 with a positive outlook, a B2 rating for our Senior Notes and a Speculative Grade Liquidity rating of SGL-3. Standard & Poor’s Ratings Services has assigned a Corporate Credit Rating of BB- with a positive outlook and a B+ rating for our Senior Notes.

Senior Secured Revolving Credit Facility. The Credit Facility, a senior secured revolving credit facility with Bank of America, N.A., as Administrative Agent, and a group of financial institutions, as lenders, was established in August 2005 and amended in January 2007 and October 2007 as discussed in Note 5 and Note 13 to the unaudited consolidated financial statements.

Based upon our total debt to EBITDA ratio calculated as of September 30, 2007 (utilizing trailing four quarters’ EBITDA as defined under the Credit Facility), we have approximately $146.0 million of unused capacity under the amended Credit Facility after borrowings used for the Cantera Acquisition. Our management believes that we are in compliance with the covenants under the Credit Facility as of September 30, 2007.

The effective average interest rate on borrowings under the Credit Facility for the nine months ended September 30, 2007 was 6.9% and the quarterly commitment fee on the unused portion of the Credit Facility was 0.2% as of September 30, 2007. Interest and other financing costs related to the Credit Facility totaled $4.8 million for the nine months ended September 30, 2007. 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, 2007, the unamortized portion of debt issue costs totaled $2.4 million.

Senior Notes. In February 2006, we issued the Senior Notes due 2016. Interest and other financing costs related to the Senior Notes totaled $14.2 million for the nine months ended September 30, 2007. Costs incurred in connection with the issuance of the Senior Notes are being amortized over the term of the Senior Notes and, as of September 30, 2007, the unamortized portion of debt issue costs totaled $5.9 million.

The Senior Notes are jointly and severally guaranteed by all of our current wholly-owned subsidiaries (other than CEFC, the co-issuer of the Senior Notes) and by certain of our future subsidiaries. The subsidiary guarantees rank equally in right of payment with all of the existing and future senior indebtedness of our guarantor subsidiaries, including their guarantees of our other senior indebtedness. The subsidiary guarantees are effectively subordinated to all existing and future secured indebtedness of our guarantor subsidiaries to the extent of the value of the assets securing that indebtedness and to all existing and future indebtedness and other liabilities, including trade payables, of any non-guarantor subsidiaries (other than indebtedness and other liabilities owed to our guarantor subsidiaries). The subsidiary guarantees rank senior in right of payment to any future subordinated indebtedness of our guarantor subsidiaries.

Recent Accounting Pronouncements

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

Critical Accounting Policies

For a discussion of our critical accounting policies, which are related to revenue recognition, depreciation, amortization and impairment of long-lived assets and financial instruments previously classified as equity and are now classified as liabilities and equity method of accounting, and which remain unchanged, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Significant Accounting Policies and Estimates” in our Annual Report on Form 10-K for the year ended December 31, 2006.

Non-GAAP Financial Measures

The following table presents a reconciliation of the non-GAAP financial measures of (1) total segment gross margin (which consists of the sum of individual segment gross margins) to the GAAP financial measure of operating income and (2) EBITDA to the GAAP financial measures of net income and cash flows from operating activities for each of the periods indicated (in thousands).


	Three Months						Nine Months
	Ended September 30,						Ended September 30,
	2007			2006			2007			2006

Reconciliation of total segment gross margin to operating income:
Operating income	$	26,006		$	31,090		$	59,141		$	72,585
Add: Operations and maintenance expenses		10,525			8,519			28,700			23,527
Depreciation and amortization		10,130			8,182			28,426			23,657
General and administrative expenses		8,615			8,108			23,831			19,919
Taxes other than income		1,010			622			2,566			1,610
Equity in earnings from unconsolidated affiliates		(401	)		(549	)		(2,019	)		(644	)

Total segment gross margin	$	55,885		$	55,972		$	140,645		$	140,654

Reconciliation of EBITDA to net income:
Net income	$	19,667		$	22,283		$	41,677		$	48,583
Add: Depreciation and amortization		10,130			8,182			28,426			23,657
Interest and other financing costs		6,943			9,525			18,314			25,312
Provision for income taxes		102			—			1,182			—

EBITDA	$	36,842		$	39,990		$	89,599		$	97,552

Reconciliation of EBITDA to cash flows from operating activities:
Cash flow provided by operating activities	$	27,447		$	36,690		$	68,338		$	96,627
Add: Cash paid for interest and other financing costs		6,636			7,389			17,393			21,788
Equity in earnings from unconsolidated affiliates		401			549			2,019			644
Distributions from unconsolidated affiliates		(777	)		—			(2,888	)		—
Risk management activities		143			(4,054	)		19,137			(6,914	)
Increase in working capital and other		2,992			(584	)		(14,400	)		(14,593	)

EBITDA	$	36,842		$	39,990		$	89,599		$	97,552


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 puts, swaps and other derivatives to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of future earnings and cash flows resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures,

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

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 and a variety of additional factors that are beyond our control. Our profitability is affected by prevailing commodity prices primarily as a result of two components of our business: (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. The following discussion describes our commodity price risks as of September 30, 2007.

The processing contracts in our Mid-Continent Operations segment are predominantly percentage-of-proceeds arrangements. Under these arrangements, we generally receive and process natural gas on behalf of 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 Texas Gulf Coast Pipelines segment purchases natural gas for transportation and resale and also transports and provides 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. Although fees for natural gas that we transport on our pipeline systems for the account of others are primarily fixed fee, our contracts also include a percentage-of-index component in a number of cases.

The impacts of commodity prices on our Texas Gulf Coast Processing segment are more complex, involving the interplay between our contractual arrangements and the ability of our Houston Central Processing Plant to either process or condition gas depending on a price relationship known as the processing spread or processing margin. Under those arrangements, we receive natural gas from producers and third-party transporters, process or condition the natural gas and sell the resulting NGLs to third parties at market prices. Under a significant number of these arrangements, we also charge producers and third-party transporters a conditioning fee either at all times or only under certain conditions. These fees provide us additional revenue and compensate us for the services required to redeliver natural gas that meets downstream pipeline quality specifications. The extraction of NGLs reduces the Btus of the natural gas processed at our Houston Central Processing Plant, which reduction is known as plant thermal reduction, or PTR. When NGL prices are high relative to natural gas prices, the processing margin is said to be positive, and we operate our Houston Central Processing Plant in a manner intended to extract NGLs to the fullest extent possible. During such periods, we use a portion of the natural gas that we purchase from producers for the purpose of meeting our PTR requirements. Because of our contractual arrangements, operating our Houston Central Processing Plant in maximum recovery mode creates a long position in NGLs and a short position in natural gas. When processing margins are negative, we operate our Houston Central Processing Plant in conditioning mode to extract the least amount of NGLs needed to meet downstream pipeline hydrocarbon dew point specifications. When we operate in a conditioning mode, the PTR requirements of our Houston Central Processing Plant are significantly lower. The ability to condition rather than to fully process natural gas provides an operational hedge that allows us to reduce our commodity price exposure. Accordingly, operating our Houston Central Processing Plant in conditioning mode reduces the long position in NGLs of our Texas Gulf Coast segments to nominal levels and eliminates our short position in natural gas for these segments on a combined basis.

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 $1.3 million to our total segment gross margin for the nine months ended September 30, 2007. We also calculated that a $0.10 per MMBtu increase in the price of natural gas would have resulted in approximately a $1.2 million decrease to our total segment gross margin and vice versa, for the nine months ended September 30, 2007. These relationships are not necessarily linear. Due to the prices received for natural gas and NGLs during the nine months ended September 30, 2007, the sensitivity analysis does not fully reflect the benefit of our hedging program. If actual prices were to fall below the strike prices of our hedges, sensitivity to the change in commodity

prices would be reduced. Additionally, if processing margins are negative, we can operate our Houston Central Processing Plant in a conditioning mode so that additional increases in natural gas prices would have a positive impact to our total segment gross margin.

Commodity Price Hedging Activities. We seek to mitigate the price risk of natural gas and NGLs through the use of commodity derivative instruments. These activities are governed by our risk management policy, which, as amended in June 2007, 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;

	•	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) and/or sell fixed for floating swaps on natural gas at Henry Hub, HSC or other highly liquid points relevant to our operations or to the operations of an entity to be acquired by us;

	•	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 an entity to be acquired by us, has direct price exposure, priced at Mt. Belvieu or Conway; and

	•	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 to the operations of an entity to be acquired by us.

Our policy also limits the maturity and notional amounts of our derivatives transactions and requires that:


	•	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;

	•	Through December 31, 2008, notional volume must not exceed the projected requirements or output, as applicable, for the hedged period with respect to (i) the purchase of crude oil or NGL put options, (ii) the purchase of natural gas put or call options, (iii) the purchase of fractionation spread or processing margin spread put options or (iv) the entry into any crude oil, natural gas or NGL spread options permitted by the policy.

	•	After December 31, 2008, notional volume must not exceed 80% of the projected requirements or output, as applicable, for the hedged period with respect to (i) the purchase of crude oil or NGLs put options, (ii) the purchase of natural gas put or call options, (iii) the purchase of fractionation spread or processing margin spread put options or (iv) the entry into any crude oil, natural gas or NGL spread options; and

	•	The aggregate volumetric exposure associated with swaps, collars and written calls relating to any product must not exceed 50% of the aggregate hedged position with respect to such product.

Our policy of limiting swaps as a percentage of our overall hedge positions is intended to avoid risk associated with potential fluctuations in output volumes that may result from conditioning elections or other operational circumstances.

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. Under this documentation, the payment obligations in connection with our swap transactions are secured by a first priority lien in the collateral securing our senior secured indebtedness that ranks equal in right of payment with liens granted in favor of our senior secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit, or other additional collateral to secure these hedges at any time even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.

We will seek, whenever possible, to enter into hedge transactions that meet or exceed the requirements for effective hedges as outlined in SFAS No. 133.

Mid-Continent Operations Segment. Natural gas for our Mid-Continent Operations segment is hedged using the CenterPoint East index, the principal index used to price the underlying commodity. With the exception of natural gasoline and condensate, NGLs are contractually priced using the Conway index but since there is an extremely limited forward market for Conway, we use Mt. Belvieu hedge instruments instead. While this creates the potential for basis risk, statistical analysis reveals that the two indices have been historically highly correlated.

Texas Gulf Coast Pipelines and Processing Segments. 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 Processing Plant. The call spread options are based on the HSC 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 Gulf Coast Pipelines and Processing segments because our natural gas position is neutral to short due to our contractual arrangements and the ability of the Houston Central Processing Plant to switch between full recovery and conditioning mode. Because of our ability to reject ethane, we have not hedged our ethane production from our Texas Gulf Coast Processing segment.

The following table summarizes our commodity hedge portfolio as of September 30, 2007 (all hedges are settled monthly):

Purchased CenterPoint East Natural Gas Puts


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

2007	$	8.75		9,750	$	2,284,000
2008	$	7.75		5,000	$	2,192,000
2009	$	6.95		5,000	$	1,394,000

Purchased HSC Index Natural Gas Call Spreads


	Call Strike
	(Per MMBtu)				Call Volumes
	Bought		Sold		(MMBtu/d)		Fair Value

2007	$	8.00	$	10.00		11,400	$	122,000
2008	$	8.15	$	10.00		9,400	$	1,495,000
2009	$	7.75	$	10.00		8,000	$	1,941,000
2010	$	7.35	$	10.00		7,100	$	1,995,000
2011	$	6.95	$	10.00		7,100	$	2,180,000

Purchased Purity Ethane Puts and Entered into Swaps


	Put						Swap
	Strike		Volumes				Price		Volumes
	(Per Gallon)		(Bbls/d)		Fair Value		(Per Gallon)		(Bbls/d)		Fair Value

2007	$	0.6365		599	$	—	$	0.6525		599	$	(514,000	)
2007	$	0.6960		2,000	$	2,000	$	0.7300		2,000	$	(1,121,000	)
2008	$	0.5700		607	$	5,000	$	0.5650		607	$	(2,304,000	)
2008	$	0.6250		2,900	$	99,000	$	0.6525		1,300	$	(3,252,000	)
2009	$	0.5900		2,200	$	155,000	$	0.6025		1,100	$	(3,010,000	)
2010	$	0.5550		1,600	$	95,000	$	0.5700		500	$	(1,395,000	)
2011	$	0.5300		1,700	$	99,000	$	0.5450		500	$	(1,407,000	)

Purchased TET Propane Puts and Entered into Swaps


	Put						Swap
	Strike		Volumes				Price		Volumes
	(Per Gallon)		(Bbls/d)		Fair Value		(Per Gallon)		(Bbls/d)		Fair Value

2007	$	0.8930		2,575	$	—	$	0.9375		726	$	(961,000	)
2007	$	0.9000		1,100	$	—		—		—		—
2007	$	1.0950		500	$	8,000		—		—		—
2008	$	0.8360		2,594	$	83,000	$	0.8700		745	$	(3,775,000	)
2008	$	0.8975		1,100	$	84,000		—		—		—
2008	$	1.0500		1,000	$	373,000		—		—		—
2009	$	0.8725		2,200	$	471,000		—		—		—
2009	$	0.9650		1,000	$	474,000	$	1.0275		1,000	$	(2,135,000	)
2010	$	0.8500		1,100	$	288,000		—		—		—
2010	$	0.9460		700	$	387,000	$	0.9925		700	$	(1,537,000	)
2011	$	0.8265		1,100	$	324,000		—		—		—
2011	$	0.9340		700	$	445,000	$	0.9750		700	$	(1,488,000	)

Purchased Non-TET Isobutane Puts and Entered into Swaps


	Put						Swap
	Strike		Volumes				Price		Volumes
	(Per Gallon)		(Bbls/d)		Fair Value		(Per Gallon)		(Bbls/d)		Fair Value

2007	$	1.0675		620	$	—	$	1.1250		90	$	(148,000	)
2007	$	1.0750		200	$	—		—		—		—
2008	$	0.9900		622	$	9,000	$	1.0450		92	$	(596,000	)
2008	$	1.0900		250	$	13,000		—		—		—
2009	$	1.0600		450	$	75,000		—		—		—
2009	$	1.1600		100	$	38,000	$	1.2425		100	$	(283,000	)
2010	$	1.0350		300	$	60,000		—		—		—
2010	$	1.1145		100	$	38,000	$	1.2025		100	$	(287,000	)
2011	$	1.0205		300	$	75,000		—		—		—
2011	$	1.1100		100	$	47,000	$	1.1800		100	$	(281,000	)

Purchased Non-TET Normal Butane Puts and Entered into Swaps


	Put						Swap
	Strike		Volumes				Price		Volumes
	(Per Gallon)		(Bbls/d)		Fair Value		(Per Gallon)		(Bbls/d)		Fair Value

2007	$	1.0650		803	$	—	$	1.1200		264	$	(380,000	)
2007	$	1.0675		150	$	—		—		—		—
2007	$	1.2700		400	$	2,000		—		—		—
2008	$	0.9875		810	$	5,000	$	1.0400		271	$	(1,486,000	)
2008	$	1.0800		300	$	10,000		—		—		—
2008	$	1.2150		400	$	78,000		—		—		—
2009	$	1.0525		700	$	65,000		—		—		—
2009	$	1.1400		400	$	98,000	$	1.2275		400	$	(825,000	)
2010	$	1.0300		300	$	29,000		—		—		—
2010	$	1.1000		200	$	42,000	$	1.1850		200	$	(444,000	)
2011	$	1.0205		300	$	36,000		—		—		—
2011	$	1.0850		200	$	46,000	$	1.1700		200	$	(424,000	)

Purchased Non-TET Natural Gasoline Puts and Entered into Swaps

Put

Swap

Strike

Volumes

Price

Volumes

(Per Gallon)

(Bbls/d)

Fair Value

(Per Gallon)

(Bbls/d)