UNITED STATES SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 10-Q

þ	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2011
OR
o	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number: 001-32329

Copano Energy, L.L.C.

(Exact Name of Registrant as Specified in Its Charter)

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

2727 Allen Parkway, Suite 1200

Houston, Texas 77019

(Address of Principal Executive Offices)

(713) 621-9547

(Registrant’s Telephone Number, Including Area Code)

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

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

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

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

(Do not check if a smaller reporting company)

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

There were 66,229,589 common units of Copano Energy, L.L.C. outstanding at August 1, 2011. Copano Energy, L.L.C.’s common units trade on The NASDAQ Stock Market LLC under the symbol “CPNO.”

TABLE OF CONTENTS

			Page
PART I — FINANCIAL INFORMATION
	Item 1.	Financial Statements		3
		Unaudited Consolidated Balance Sheets as of June 30, 2011 and December 31, 2010		3
		Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2011 and 2010		4
		Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2011 and 2010		5
		Unaudited Consolidated Statement of Members’ Capital and Comprehensive Income (Loss) for the Six Months Ended June 30, 2011 and 2010		6
		Notes to Unaudited Consolidated Financial Statements		7
	Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		34
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		56
	Item 4.	Controls and Procedures		59
PART II — OTHER INFORMATION
	Item 1.	Legal Proceedings		60
	Item 1A.	Risk Factors		60
	Item 6.	Exhibits		61
EX-10.2
EX-31.1
EX-31.2
EX-32.1
EX-32.2
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

2

Item 1.   Financial Statements.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2011			2010
	(In thousands, except unit information)
ASSETS
Current assets:
Cash and cash equivalents	$	61,556		$	59,930
Accounts receivable, net		112,641			96,662
Risk management assets		4,616			7,836
Prepayments and other current assets		3,249			5,179
Total current assets		182,062			169,607
Property, plant and equipment, net		1,007,879			912,157
Intangible assets, net		186,872			188,585
Investments in unconsolidated affiliates		658,424			604,304
Escrow cash		1,850			1,856
Risk management assets		12,912			11,943
Other assets, net		28,908			18,541
Total assets	$	2,078,907		$	1,906,993
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable	$	146,178		$	117,706
Accrued interest		8,037			10,621
Accrued tax liability		586			913
Risk management liabilities		9,784			9,357
Other current liabilities		22,139			14,495
Total current liabilities		186,724			153,092
Long term debt (includes $0 and $546 bond premium as of June 30, 2011 and December 31, 2010, respectively)		804,525			592,736
Deferred tax provision		2,051			1,883
Risk management and other noncurrent liabilities		2,986			4,525
Commitments and contingencies (Note 9)
Members’ capital:
Series A convertible preferred units, no par value, 11,121,071 units and 10,585,197 units issued and outstanding as of June 30, 2011 and December 31, 2010, respectively		285,168			285,172
Common units, no par value, 66,225,657 units and 65,915,173 units issued and outstanding as of June 30, 2011 and December 31, 2010, respectively		1,164,083			1,161,652
Paid in capital		57,312			51,743
Accumulated deficit		(396,253	)		(313,454	)
Accumulated other comprehensive loss		(27,689	)		(30,356	)
		1,082,621			1,154,757
Total liabilities and members’ capital	$	2,078,907		$	1,906,993

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

3

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF OPERATIONS

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	(In thousands, except per unit information)
Revenue:
Natural gas sales	$	123,928		$	84,819		$	227,723		$	205,035
Natural gas liquids sales		180,758			114,802			329,759			234,120
Transportation, compression and processing fees		27,898			16,516			52,369			29,630
Condensate and other		13,472			13,914			26,130			27,932
Total revenue		346,056			230,051			635,981			496,717
Costs and expenses:
Cost of natural gas and natural gas liquids(1)		274,398			167,613			498,128			377,478
Transportation(1)		6,362			5,603			12,211			11,279
Operations and maintenance		15,763			13,230			30,862			25,333
Depreciation and amortization		17,363			15,583			34,232			30,784
General and administrative		11,901			10,900			24,499			21,442
Taxes other than income		1,397			1,181			2,527			2,343
Equity in (earnings) loss from unconsolidated affiliates		(1,306	)		23,632			(3,008	)		21,837
Total costs and expenses		325,878			237,742			599,451			490,496
Operating income (loss)		20,178			(7,691	)		36,530			6,221
Other income (expense):
Interest and other income		8			37			15			44
Loss on refinancing of unsecured debt		(18,233	)		—			(18,233	)		—
Interest and other financing costs		(11,454	)		(13,351	)		(23,370	)		(28,296	)
Loss before income taxes		(9,501	)		(21,005	)		(5,058	)		(22,031	)
Provision for income taxes		140			(106	)		(771	)		(340	)
Net loss		(9,361	)		(21,111	)		(5,829	)		(22,371	)
Preferred unit distributions		(8,076	)		—			(15,956	)		—
Net loss to common units	$	(17,437	)	$	(21,111	)	$	(21,785	)	$	(22,371	)
Basic and diluted net loss per common unit	$	(0.26	)	$	(0.32	)	$	(0.33	)	$	(0.36	)
Weighted average number of common units		66,143			65,516			66,065			61,941
Distributions declared per common unit	$	0.575		$	0.575		$	1.150		$	1.150

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

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

4

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Six Months Ended June 30,
	2011			2010
	(In thousands)
Cash Flows From Operating Activities:
Net loss	$	(5,829	)	$	(22,371	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization		34,232			30,784
Amortization of debt issue costs		1,949			1,790
Equity in (earnings) loss from unconsolidated affiliates		(3,008	)		21,837
Distributions from unconsolidated affiliates		12,323			10,993
Loss on refinancing of unsecured debt		18,233			—
Non-cash gain on risk management activities, net		(1,536	)		(1,049	)
Equity-based compensation		5,340			4,688
Deferred tax provision		168			(98	)
Other non-cash items		(10	)		(369	)
Changes in assets and liabilities, net of acquisitions:
Accounts receivable		(15,637	)		12,231
Prepayments and other current assets		2,110			2,605
Risk management activities		5,455			6,002
Accounts payable		21,498			(3,151	)
Other current liabilities		718			1,522
Net cash provided by operating activities		76,006			65,414
Cash Flows From Investing Activities:
Additions to property, plant and equipment		(98,289	)		(59,438	)
Additions to intangible assets		(4,140	)		(930	)
Acquisitions		(16,084	)		—
Investments in unconsolidated affiliates		(65,027	)		(1,538	)
Distributions from unconsolidated affiliates		1,249			1,997
Escrow cash		6			—
Proceeds from sale of assets		141			266
Other		(185	)		523
Net cash used in investing activities		(182,329	)		(59,120	)
Cash Flows From Financing Activities:
Proceeds from long-term debt		605,000			80,000
Repayment of long-term debt		(392,665	)		(170,000	)
Payments of premiums and expenses on redemption of unsecured debt		(14,572	)		—
Deferred financing costs		(15,670	)		—
Distributions to unitholders		(76,571	)		(69,430	)
Proceeds from public offering of common units, net of underwriting discounts and commissions of $7,223		—			164,786
Equity offering costs		(4	)		(531	)
Proceeds from option exercises		2,431			991
Net cash provided by financing activities		107,949			5,816
Net increase in cash and cash equivalents		1,626			12,110
Cash and cash equivalents, beginning of year		59,930			44,692
Cash and cash equivalents, end of period	$	61,556		$	56,802

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

5

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

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

	Series A Preferred					Common				Class D						Accumulated			Accumulated						Total
	Number		Preferred			Number		Common		Number		Class D		Paid-in		Earnings			Other Comprehensive						Comprehensive
	of Units		Units			of Units		Units		of Units		Units		Capital		(Deficit)			(Loss) Income			Total			(Loss) Income
														(In thousands)
Balance, December 31, 2010		10,585	$	285,172			65,915	$	1,161,652		—	$	—	$	51,743	$	(313,454	)	$	(30,356	)	$	1,154,757		$	—
Issuance of preferred units (paid-in-kind)		536		15,567			—		—		—		—		—		—			—			15,567			—
Accrued in-kind units		—		389			—		—		—		—		—		—			—			389
In-kind distributions		—		(15,956	)		—		—		—		—		—		—			—			(15,956	)
Cash distributions to common unitholders		—		—			—		—		—		—		—		(76,970	)		—			(76,970	)		—
Equity offering costs		—		(4	)		—		—		—		—		—		—			—			(4	)		—
Equity-based compensation		—		—			311		2,431		—		—		5,569		—			—			8,000			—
Net loss		—		—			—		—		—		—		—		(5,829	)		—			(5,829	)		(5,829	)
Derivative settlements reclassified to income		—		—			—		—		—		—		—		—			18,324			18,324			18,324
Unrealized loss-change in fair value of derivatives		—		—			—		—		—		—		—		—			(15,657	)		(15,657	)		(15,657	)
Comprehensive loss																									$	(3,162	)
Balance, June 30, 2011		11,121	$	285,168			66,226	$	1,164,083		—	$	—	$	57,312	$	(396,253	)	$	(27,689	)	$	1,082,621

	Series A Preferred				Common					Class D								Accumulated			Accumulated						Total
	Number		Preferred		Number		Common			Number			Class D			Paid-in		Earnings			Other Comprehensive						Comprehensive
	of Units		Units		of Units		Units			of Units			Units			Capital		(Deficit)			Income (Loss)			Total			Income (Loss)
																(In thousands)
Balance, December 31, 2009		—	$	—		54,670	$	879,504			3,246		$	112,454		$	42,518	$	(158,267	)	$	(16,183	)	$	860,026		$	—
Conversion of Class D Units into common units		—		—		3,246		112,454			(3,246	)		(112,454	)		—		—			—			—			—
Cash distributions to common unitholders		—		—		—		—			—			—			—		(70,037	)		—			(70,037	)		—
Issuance of units		—		—		7,446		172,008			—			—			—		—			—			172,008			—
Equity offering costs		—		—		—		(7,756	)		—			—			—		—			—			(7,756	)		—
Equity-based compensation		—		—		201		991			—			—			4,861		—			—			5,852			—
Net loss		—		—		—		—			—			—			—		(22,371	)		—			(22,371	)		(22,371	)
Derivative settlements reclassified to income		—		—		—		—			—			—			—		—			(332	)		(332	)		(332	)
Unrealized gain-change in fair value of derivatives		—		—		—		—			—			—			—		—			21,337			21,337			21,337
Comprehensive income																											$	(1,366	)
Balance, June 30, 2010		—	$	—		65,563	$	1,157,201			—		$	—		$	47,379	$	(250,675	)	$	4,822		$	958,727

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

6

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Note 1 — Organization and Basis of Presentation

Organization

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

Our natural gas pipelines collect natural gas from wellheads or designated points near producing wells. We treat and process natural gas as needed to remove contaminants and to extract mixed natural gas liquids, or NGLs, and we deliver the resulting residue gas to third-party pipelines, local distribution companies, power generation facilities and industrial consumers. We sell extracted NGLs as a mixture or as fractionated purity products and deliver them through our plant interconnects or NGL pipelines. We process natural gas from our own gathering systems and from third-party pipelines, and in some cases we deliver natural gas and mixed NGLs to third parties who provide us with transportation, processing or fractionation services. We also provide natural gas transportation services in limited circumstances. We refer to our operations (i) conducted through our subsidiaries operating in Texas and Louisiana collectively as our “Texas” segment, (ii) conducted through our subsidiaries operating in Oklahoma collectively as our “Oklahoma” segment and (iii) conducted through our subsidiaries operating in Wyoming collectively as our “Rocky Mountains” segment.

Basis of Presentation and Principles of Consolidation

The accompanying unaudited consolidated financial statements and related notes include our assets, liabilities and results of operations for each of the periods presented. All intercompany accounts and transactions are eliminated in our unaudited consolidated financial statements.

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

Our management believes that the disclosures in these unaudited consolidated financial statements are adequate to make the information presented not misleading. In the preparation of these financial statements, we evaluated subsequent events through the issuance date of the financial statements. These interim financial statements should be read in conjunction with the audited consolidated financial statements and notes thereto contained in our Annual Report on Form 10-K for the year ended December 31, 2010.

Note 2 — Recent Accounting Pronouncements

In June 2011, the Financial Accounting Standards Board issued Accounting Standards Update 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income,” which amends current comprehensive income guidance. This accounting update eliminates the option to present the components of other comprehensive income as part of the statement of members’ capital. Instead, we must report comprehensive income in either a single continuous statement of comprehensive income which contains two sections, net income and other comprehensive income, or in two separate but consecutive statements. This guidance will be effective beginning with our first quarterly filing in 2012. We do not expect the guidance to impact our consolidated financial statements, as the only required change is the format of presentation.

7

Note 2 — Recent Accounting Pronouncements (Continued)

Section 1504 of the Dodd-Frank Wall Street Reform and Consumer Protection Act, adopted by the United States Congress in 2010, directs the SEC to develop rules requiring companies engaged in the commercial development of oil, natural gas or minerals to disclose payments made to the United States government and all foreign governments. In its proposed rule release, the SEC indicated that, while the focus of the rule generally is upstream companies, the disclosure requirement may apply to companies that perform certain natural gas processing activities. Payment disclosures would be required at a project level within the Annual Report on Form 10-K beginning with the year ended December 31, 2012. We cannot predict final disclosure requirements that will be required by the SEC.

We have reviewed other recently issued, but not yet adopted, accounting standards and updates in order to determine their potential effects, if any, on our consolidated results of operations, financial position and cash flows. Most of the recent updates represented technical corrections to the existing accounting literature or applied to other industries and are not expected to a have a material impact on our consolidated cash flows, results of operations or financial position.

Note 3 — Intangible Assets

Our intangible assets consisted of the following:

	June 30,			December 31,
	2011			2010
	(In thousands)
Rights-of-way and easements, at cost	$	129,137		$	125,496
Less accumulated amortization for rights-of-way and easements		(26,007	)		(23,234	)
Contracts		108,416			107,916
Less accumulated amortization for contracts		(28,078	)		(25,153	)
Customer relationships		4,864			4,864
Less accumulated amortization for customer relationships		(1,460	)		(1,304	)
Intangible assets, net	$	186,872		$	188,585

During the three and six months ended June 30, 2011 and 2010, we did not place in service any intangible assets with future renewals or extension costs. As of June 30, 2011 and 2010, the weighted average amortization period for all of our intangible assets was 19 years and 20 years, respectively. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 20 years, 18 years and 11 years, respectively, as of June 30, 2011. The weighted average amortization period for our rights-of-way and easements, contracts and customer relationships was 22 years, 18 years and 12 years, respectively, as of June 30, 2010. Amortization expense was $2,956,000 and $2,782,000 for the three months ended June 30, 2011 and 2010, respectively. Amortization expense was $5,854,000 and $5,562,000 for the six months ended June 30, 2011 and 2010, respectively.

Estimated aggregate amortization expense remaining for 2011 and each of the five succeeding fiscal years is approximately: 2011 — $5,920,000; 2012 — $11,916,000; 2013 — $11,742,000; 2014 — $11,464,000; 2015 — $11,403,000; and 2016 — $11,384,000.

8

Note 4 — Investments in Unconsolidated Affiliates

Our investments in unconsolidated affiliates consisted of the following at June 30, 2011:

		Ownership
Equity Method Investment	Structure	Percentage			Segment
Webb/Duval Gatherers (“Webb Duval”)	Texas general partnership		62.50	%	Texas
Eagle Ford Gathering LLC (“Eagle Ford Gathering”)	Delaware limited liability company		50.00	%	Texas
Liberty Pipeline Group, LLC (“Liberty Pipeline Group”)	Delaware limited liability company		50.00	%	Texas
Southern Dome, LLC (“Southern Dome”)	Delaware limited liability company		69.50	%(1)	Oklahoma
Bighorn Gas Gathering, L.L.C. (“Bighorn”)	Delaware limited liability company		51.00	%	Rocky Mountains
Fort Union Gas Gathering, L.L.C. (“Fort Union”)	Delaware limited liability company		37.04	%	Rocky Mountains

(1) Represents Copano’s right to distributions from Southern Dome

None of these entities’ respective partnership or operating agreements restrict their ability to pay distributions to their respective partners or members after consideration of current and anticipated cash needs, including debt service obligations. However, Fort Union’s credit agreement provides that it can distribute cash to its members only if its ratio of net operating cash flow to debt service is not less than 1.25 to 1.00 and it is not otherwise in default under its credit agreement. If Fort Union fails to comply with this covenant or otherwise defaults under its credit agreement, it would be prohibited from distributing cash. As of June 30, 2011, Fort Union is in compliance with this financial covenant.

Bighorn and Fort Union.  Our investment in Bighorn totaled $337,592,000 as of June 30, 2011. During the six months ended June 30, 2011 and 2010, we made capital contributions to Bighorn of $432,000 and $630,000, respectively. Our investment in Fort Union totaled $214,696,000 as of June 30, 2011 and during the six months ended June 30, 2011 and 2010, we made capital contributions to Fort Union of $0 and $774,000, respectively.

9

Note 4 — Investments in Unconsolidated Affiliates (Continued)

The summarized financial information for our investments in Bighorn and Fort Union, which are accounted for using the equity method, is as follows (in thousands):

	As of and for the Six Months Ended June 30,
	2011						2010
	Bighorn			Fort Union			Bighorn			Fort Union
	(In thousands)
Operating revenue	$	13,903		$	27,104		$	15,973		$	28,009
Operating expenses		(4,589	)		(3,455	)		(5,961	)		(3,926	)
Depreciation and amortization		(2,587	)		(3,996	)		(2,549	)		(3,629	)
Interest income (expense) and other		42			(1,228	)		22			(2,332	)
Net income		6,769			18,425			7,485			18,122
Ownership %		51	%		37.04	%		51	%		37.04	%
		3,452			6,825			3,817			6,712
Priority allocation of earnings and other		254			—			195			—
Copano’s share of management fees charged		98			46			142			44
Amortization of difference between the carried investment and the underlying equity in net assets		(5,629	)		(3,212	)		(31,084	)		(3,212	)
Equity in (loss) earnings from unconsolidated affiliates	$	(1,825	)	$	3,659		$	(26,930	)	$	3,544
Distributions	$	4,956		$	7,408		$	5,497		$	5,371
Current assets	$	5,912		$	9,721		$	6,605		$	14,437
Noncurrent assets		86,667			200,270			90,891			208,624
Current liabilities		(1,084	)		(18,782	)		(1,238	)		(19,852	)
Noncurrent liabilities		(282	)		(66,779	)		(257	)		(81,565	)
Net assets	$	91,213		$	124,430		$	96,001		$	121,644

Other.  The summarized financial information for our investments in other unconsolidated affiliates (Webb Duval, Eagle Ford Gathering, Liberty Pipeline Group and Southern Dome) is presented below in aggregate:

	As of and for the
	Six Months Ended June 30,
	2011			2010
	(In thousands)
Operating revenue	$	14,029		$	17,024
Operating expenses		(11,883	)		(14,173	)
Depreciation and amortization		(756	)		(759	)
Other income, net		3			5
Net income	$	1,393		$	2,097
Current assets	$	10,728		$	4,129
Noncurrent assets		215,259			21,198
Current liabilities		(25,111	)		(6,041	)
Noncurrent liabilities		(898	)		(60	)
Net assets	$	199,978		$	19,226

Our share of the equity earnings from our other unconsolidated affiliates was $1,173,000 and $1,549,000 for the six months ended June 30, 2011 and 2010, respectively.

10

Note 4 — Investments in Unconsolidated Affiliates (Continued)

We received total distributions from our other unconsolidated affiliates of $1,208,000 and $2,122,000 for the six months ended June 30, 2011 and 2010, respectively.

We made cash contributions to our other unconsolidated affiliates of $62,157,000 and $0 for the six months ended June 30, 2011 and 2010, respectively. Contributions for the six months ended June 30, 2011 were primarily made to Eagle Ford Gathering for the construction of gathering pipelines and to Liberty Pipeline Group for the construction of its NGL pipeline.

Note 5 — Long-Term Debt

	June 30,		December 31,
	2011		2010
	(In thousands)
Revolving credit facility	$	195,000	$	10,000
Senior Notes:
8.125% senior unsecured notes due 2016		—		332,665
Unamortized bond premium-senior notes due 2016		—		546
7.75% senior unsecured notes due 2018		249,525		249,525
7.125% senior unsecured notes due 2021		360,000		—
Total Senior Notes		609,525		582,736
Total long-term debt	$	804,525	$	592,736

Revolving Credit Facility

On June 10, 2011, we entered into a second amended and restated credit agreement (the “Amended Credit Agreement”) with Bank of America, N.A., as Administrative Agent, which increased our $550 million senior secured revolving credit facility to $700 million. The significant changes in the Amended Credit Agreement include:

•  The maturity date is extended from October 18, 2012 to June 10, 2016.

•  Interest is determined, at our election, by reference to (a) the British Bankers Association LIBOR rate, or LIBOR, plus an applicable rate between 2.0% and 3.25% per annum or (b) the highest of (1) the federal funds rate plus 0.50%, (2) the prime rate and (3) LIBOR plus 1.0%, plus, in each case, an applicable rate between 1.0% and 2.25% per annum. The applicable rates vary depending on our consolidated leverage ratio (as defined in the Amended Credit Agreement).

•  The quarterly commitment fee on the unused amount of the revolving credit facility is determined by reference to an applicable rate between 0.375% and 0.5% per annum. The applicable rate varies depending on our consolidated leverage ratio (as defined in the Amended Credit Agreement).

•  A sublimit of up to $100 million is available for letters of credit and a sublimit of up to $75 million is available for swing line loans.

As of June 30, 2011, we had no letters of credit outstanding.

The weighted average rate on borrowings under the revolving credit facility for the six months ended June 30, 2011 and 2010 was 2.4% and 1.8%, respectively, and the quarterly commitment fee on the unused portion of the revolving credit facility for those periods was 0.375% and 0.25%, respectively. Interest and other financing costs related to the revolving credit facility totaled $2,767,000 and $3,535,000 for the six months ended June 30, 2011 and 2010, respectively.

We incurred $7,813,000 in financing fees related to the Amended Credit Agreement. Because the borrowing capacity of the Amended Credit Agreement is greater than the borrowing capacity of the previous arrangement, our costs incurred in connection with the establishment of the Amended Credit Agreement are being amortized over its

11

Note 5 — Long-Term Debt (Continued)

term in accordance with Accounting Standards Codification (“ASC”) 470-50-40-21, “Debt — Modifications and Extinguishments-Line-of-Credit Arrangements.” As of June 30, 2011, the unamortized portion of debt issue costs totaled $11,207,000.

The Amended Credit Agreement contains covenants (some of which require that we make certain subjective representations and warranties), including financial covenants that require us and our subsidiary guarantors, on a consolidated basis, to maintain specified ratios. We are in compliance with the financial covenants under the Amended Credit Agreement as of June 30, 2011.

Future borrowings under our revolving credit facility are available for acquisitions, capital expenditures, working capital and general corporate purposes, and the facility may be drawn on and repaid without restrictions so long as we are in compliance with its terms, including maximum leverage ratios (applicable to our secured debt and total debt) and a minimum interest coverage ratio.

Senior Notes

Senior Notes Offering and Tender Offer.  On April 5, 2011, we closed a public offering of $360,000,000 in aggregate principal amount of 7.125% senior unsecured notes due 2021 (the “2021 Notes”). We used the net proceeds to fund a tender offer for all of our outstanding 8.125% senior unsecured notes due 2016 (the “2016 Notes”) and a subsequent redemption of our 2016 Notes not tendered under the tender offer, and to provide additional working capital and for general corporate purposes. We recognized a loss on the tender and redemption of the 2016 Notes totaling $18,233,000, including $4,185,000 in remaining unamortized debt issue costs related to the 2016 Notes. Interest and other financing costs relating to the 2016 Notes totaled $7,664,000 and $13,902,000 for the six months ended June 30, 2011 and 2010, respectively.

Interest and other financing costs relating to the 2021 Notes totaled $6,326,000 for the six months ended June 30, 2011. Interest on the 2021 Notes is payable each April 1 and October 1. Costs of issuing the 2021 Notes are being amortized over the term of the 2021 Notes and, as of June 30, 2011, the unamortized portion of debt issue costs totaled $7,745,000.

7.75% Senior Notes Due 2018.  At June 30, 2011, the aggregate principal amount of 7.75% senior unsecured notes due 2018 (the “2018 Notes” and, together with the 2021 Notes, the “Senior Notes”) outstanding was $249,525,000.

Interest and other financing costs relating to the 2018 Notes totaled $9,941,000 for each of the six months ended June 30, 2011 and 2010, respectively. Interest on the 2018 Notes is payable each June 1 and December 1. Costs of issuing the 2018 Notes are being amortized over the term of the 2018 Notes and, as of June 30, 2011, the unamortized portion of debt issue costs totaled $3,763,000.

General.  The indentures governing our Senior Notes restrict our ability to pay cash distributions. Before we can pay a distribution to our unitholders, we must demonstrate that our ratio of EBITDA to fixed charges (as defined in the Senior Notes indentures) is at least 1.75 to 1.0.

We are in compliance with the financial covenants under the Senior Notes indentures as of June 30, 2011.

Guarantor Financial Statements

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

12

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Long-Term Debt (Continued)

	June 30, 2011																	December 31, 2010
										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	$	10,863		$	—		$	50,693		$	—	$	—		$	61,556		$	9,650		$	—		$	50,280		$	—	$	—		$	59,930
Accounts receivable, net		3			—			112,638			—		—			112,641			14			—			96,648			—		—			96,662
Intercompany receivable		88,198			(1	)		(88,197	)		—		—			—			35,178			(1	)		(35,177	)		—		—			—
Risk management assets		—			—			4,616			—		—			4,616			—			—			7,836			—		—			7,836
Prepayments and other current assets		1,213			—			2,036			—		—			3,249			3,378			—			1,801			—		—			5,179
Total current assets		100,277			(1	)		81,786			—		—			182,062			48,220			(1	)		121,388			—		—			169,607
Property, plant and equipment, net		37			—			1,007,842			—		—			1,007,879			56			—			912,101			—		—			912,157
Intangible assets, net		—			—			186,872			—		—			186,872			—			—			188,585			—		—			188,585
Investments in unconsolidated affiliates		—			—			658,424			658,424		(658,424	)		658,424			—			—			604,304			604,304		(604,304	)		604,304
Investments in consolidated subsidiaries		1,779,666			—			—			—		(1,779,666	)		—			1,703,940			—			—			—		(1,703,940	)		—
Escrow cash		—			—			1,850			—		—			1,850			—			—			1,856			—		—			1,856
Risk management assets		—			—			12,912			—		—			12,912			—			—			11,943			—		—			11,943
Other assets, net		22,716			—			6,192			—		—			28,908			13,128			—			5,413			—		—			18,541
Total assets	$	1,902,696		$	(1	)	$	1,955,878		$	658,424	$	(2,438,090	)	$	2,078,907		$	1,765,344		$	(1	)	$	1,845,590		$	604,304	$	(2,308,244	)	$	1,906,993
LIABILITIES AND MEMBERS’/PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	72		$	—		$	146,106		$	—	$	—		$	146,178		$	17		$	—		$	117,689		$	—	$	—		$	117,706
Accrued interest		8,037			—			—			—		—			8,037			10,621			—			—			—		—			10,621
Accrued tax liability		586			—			—			—		—			586			913			—			—			—		—			913
Risk management liabilities		—			—			9,784			—		—			9,784			—			—			9,357			—		—			9,357
Other current liabilities		4,746			—			17,393			—		—			22,139			4,266			—			10,229			—		—			14,495
Total current liabilities		13,441			—			173,283			—		—			186,724			15,817			—			137,275			—		—			153,092
Long-term debt		804,525			—			—			—		—			804,525			592,736			—			—			—		—			592,736
Deferred tax provision		1,989			—			62			—		—			2,051			1,848			—			35			—		—			1,883
Risk management and other noncurrent liabilities		120			—			2,866			—		—			2,986			186			—			4,339			—		—			4,525
Members’/Partners’ capital:
Series A convertible preferred units		285,168			—			—			—		—			285,168			285,172			—			—			—		—			285,172
Common units		1,164,083			—			—			—		—			1,164,083			1,161,652			—			—			—		—			1,161,652
Paid in capital		57,312			1			1,186,160			653,168		(1,839,329	)		57,312			51,743			1			1,162,543			602,055		(1,764,599	)		51,743
Accumulated deficit		(396,253	)		(2	)		621,196			5,256		(626,450	)		(396,253	)		(313,454	)		(2	)		571,754			2,249		(574,001	)		(313,454	)
Accumulated other comprehensive loss		(27,689	)		—			(27,689	)		—		27,689			(27,689	)		(30,356	)		—			(30,356	)		—		30,356			(30,356	)
		1,082,621			(1	)		1,779,667			658,424		(2,438,090	)		1,082,621			1,154,757			(1	)		1,703,941			604,304		(2,308,244	)		1,154,757
Total liabilities and members’/partners’ capital	$	1,902,696		$	(1	)	$	1,955,878		$	658,424	$	(2,438,090	)	$	2,078,907		$	1,765,344		$	(1	)	$	1,845,590		$	604,304	$	(2,308,244	)	$	1,906,993

13

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (Continued)

	Three Months Ended June 30, 2011																	Three Months Ended June 30, 2010
									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	$	—		$	—	$	123,928		$	—		$	—		$	123,928		$	—		$	—	$	84,819		$	—		$	—		$	84,819
Natural gas liquids sales		—			—		180,758			—			—			180,758			—			—		114,802			—			—			114,802
Transportation, compression and processing fees		—			—		27,898			—			—			27,898			—			—		16,516			—			—			16,516
Condensate and other		—			—		13,472			—			—			13,472			—			—		13,914			—			—			13,914
Total revenue		—			—		346,056			—			—			346,056			—			—		230,051			—			—			230,051
Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		274,398			—			—			274,398			—			—		167,613			—			—			167,613
Transportation		—			—		6,362			—			—			6,362			—			—		5,603			—			—			5,603
Operations and maintenance		—			—		15,763			—			—			15,763			—			—		13,230			—			—			13,230
Depreciation and amortization		10			—		17,353			—			—			17,363			10			—		15,573			—			—			15,583
General and administrative		5,893			—		6,008			—			—			11,901			5,831			—		5,069			—			—			10,900
Taxes other than income		—			—		1,397			—			—			1,397			—			—		1,181			—			—			1,181
Equity in (earnings) loss from unconsolidated affiliates		—			—		(1,306	)		(1,306	)		1,306			(1,306	)		—			—		23,632			23,632			(23,632	)		23,632
Total costs and expenses		5,903			—		319,975			(1,306	)		1,306			325,878			5,841			—		231,901			23,632			(23,632	)		237,742
Operating (loss) income		(5,903	)		—		26,081			1,306			(1,306	)		20,178			(5,841	)		—		(1,850	)		(23,632	)		23,632			(7,691	)
Other income (expense):
Interest and other income		—			—		8			—			—			8			—			—		37			—			—			37
Loss of refinancing of unsecured debt		(18,233	)		—					—			—			(18,233	)		—					—			—			—			—
Interest and other financing costs		(10,989	)		—		(465	)		—			—			(11,454	)		(12,717	)		—		(634	)		—			—			(13,351	)
(Loss) income before income taxes and equity in earnings from consolidated subsidiaries		(35,125	)		—		25,624			1,306			(1,306	)		(9,501	)		(18,558	)		—		(2,447	)		(23,632	)		23,632			(21,005	)
Provision for income taxes		150			—		(10	)		—			—			140			(106	)		—		—			—			—			(106	)
(Loss) income before equity in earnings from consolidated subsidiaries		(34,975	)		—		25,614			1,306			(1,306	)		(9,361	)		(18,664	)		—		(2,447	)		(23,632	)		23,632			(21,111	)
Equity in earnings (loss) from consolidated subsidiaries		25,614			—		—			—			(25,614	)		—			(2,447	)		—		—			—			2,447			—
Net (loss) income		(9,361	)		—		25,614			1,306			(26,920	)		(9,361	)		(21,111	)		—		(2,447	)		(23,632	)		26,079			(21,111	)
Preferred unit distributions		(8,076	)		—		—			—			—			(8,076	)		—			—		—			—			—			—
Net (loss) income to common units	$	(17,437	)	$	—	$	25,614		$	1,306		$	(26,920	)	$	(17,437	)	$	(21,111	)	$	—	$	(2,447	)	$	(23,632	)	$	26,079		$	(21,111	)

14

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (Continued)

	Six Months Ended June 30, 2011																	Six Months Ended June 30, 2010
									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	$	—		$	—	$	227,723		$	—		$	—		$	227,723		$	—		$	—	$	205,035		$	—		$	—		$	205,035
Natural gas liquids sales		—			—		329,759			—			—			329,759			—			—		234,120			—			—			234,120
Transportation, compression and processing fees		—			—		52,369			—			—			52,369			—			—		29,630			—			—			29,630
Condensate and other		—			—		26,130			—			—			26,130			—			—		27,932			—			—			27,932
Total revenue		—			—		635,981			—			—			635,981			—			—		496,717			—			—			496,717
Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		498,128			—			—			498,128			—			—		377,478			—			—			377,478
Transportation		—			—		12,211			—			—			12,211			—			—		11,279			—			—			11,279
Operations and maintenance		—			—		30,862			—			—			30,862			—			—		25,333			—			—			25,333
Depreciation and amortization		20			—		34,212			—			—			34,232			20			—		30,764			—			—			30,784
General and administrative		13,416			—		11,083			—			—			24,499			11,026			—		10,416			—			—			21,442
Taxes other than income		—			—		2,527			—			—			2,527			—			—		2,343			—			—			2,343
Equity in (earnings) loss from unconsolidated affiliates		—			—		(3,008	)		(3,008	)		3,008			(3,008	)		—			—		21,837			21,837			(21,837	)		21,837
Total costs and expenses		13,436			—		586,015			(3,008	)		3,008			599,451			11,046			—		479,450			21,837			(21,837	)		490,496
Operating (loss) income		(13,436	)		—		49,966			3,008			(3,008	)		36,530			(11,046	)		—		17,267			(21,837	)		21,837			6,221
Other income (expense):
Interest and other income		—			—		15			—			—			15			—			—		44			—			—			44
Loss on refinancing of unsecured debt		(18,233	)		—		—			—			—			(18,233	)		—			—		—			—			—			—
Interest and other financing costs		(22,627	)		—		(743	)		—			—			(23,370	)		(26,064	)		—		(2,232	)		—			—			(28,296	)
(Loss) income before income taxes and equity in earnings
from consolidated subsidiaries		(54,296	)		—		49,238			3,008			(3,008	)		(5,058	)		(37,110	)		—		15,079			(21,837	)		21,837			(22,031	)
Provision for income taxes		(740	)		—		(31	)		—			—			(771	)		(340	)		—		—			—			—			(340	)
(Loss) income before equity in earnings from consolidated subsidiaries		(55,036	)		—		49,207			3,008			(3,008	)		(5,829	)		(37,450	)		—		15,079			(21,837	)		21,837			(22,371	)
Equity in earnings (loss) from consolidated subsidiaries		49,207			—		—			—			(49,207	)		—			15,079			—		—			—			(15,079	)		—
Net (loss) income		(5,829	)		—		49,207			3,008			(52,215	)		(5,829	)		(22,371	)		—		15,079			(21,837	)		6,758			(22,371	)
Preferred unit distributions		(15,956	)		—		—			—			—			(15,956	)		—			—		—			—			—			—
Net (loss) income to common units	$	(21,785	)	$	—	$	49,207		$	3,008		$	(52,215	)	$	(21,785	)	$	(22,371	)	$	—	$	15,079		$	(21,837	)	$	6,758		$	(22,371	)

15

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (Continued)

	Six Months Ended June 30, 2011																	Six Months Ended June 30, 2010
									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	$	(83,120	)	$	—	$	159,126		$	12,323		$	(12,323	)	$	76,006		$	(31,290	)	$	—		$	96,704		$	10,993		$	(10,993	)	$	65,414
Cash Flows From Investing Activities:
Additions to property, plant and equipment and intangibles		—			—		(102,429	)		—			—			(102,429	)		—			—			(60,368	)		—			—			(60,368	)
Acquisitions		—			—		(16,084	)		—			—			(16,084	)		—			—			—			—			—			—
Investments in unconsolidated affiliates		—			—		(65,027	)		(65,027	)		65,027			(65,027	)		—			—			(1,538	)		(1,538	)		1,538			(1,538	)
Distributions from unconsolidated affiliates		—			—		1,249			1,249			(1,249	)		1,249			—			—			1,997			1,997			(1,997	)		1,997
Investments in consolidated affiliates		(80,319	)		—		—			—			80,319			—			(52,465	)		—			—			—			52,465			—
Distributions from consolidated affiliates		56,703			—		—			—			(56,703	)		—			95,355			—			—			—			(95,355	)		—
Proceeds from sale of assets		—			—		141			—			—			141			—			—			266			—			—			266
Other		—			—		(179	)		—			—			(179	)		—			—			523			—			—			523
Net cash (used in) provided by investing activities		(23,616	)		—		(182,329	)		(63,778	)		87,394			(182,329	)		42,890			—			(59,120	)		459			(43,349	)		(59,120	)
Cash Flows From Financing Activities:
Proceeds from long-term debt		605,000			—		—			—			—			605,000			80,000			—			—			—			—			80,000
Repayment of long-term debt		(392,665	)		—		—			—			—			(392,665	)		(170,000	)		—			—			—			—			(170,000	)
Deferred financing costs		(15,670	)		—		—			—			—			(15,670	)		—			—			—			—			—			—
Payments of premiums and expenses on redemption of unsecured debt		(14,572	)		—		—			—			—			(14,572	)		—			—			—			—			—			—
Distributions to unitholders		(76,571	)		—		—			—			—			(76,571	)		(69,430	)		—			—			—			—			(69,430	)
Proceeds from public offering of common units		—			—		—			—			—			—			164,786			—			—			—			—			164,786
Equity offering costs		(4	)		—		—			—			—			(4	)		(531	)		—			—			—			—			(531	)
Contributions from parent		—			—		80,319			65,027			(145,346	)		—			—			—			52,465			—			(52,465	)		—
Distributions to parent		—			—		(56,703	)		—			56,703			—			—			—			(95,355	)		—			95,355			—
Other		2,431			—		—			—			—			2,431			991			—			—			1,538			(1,538	)		991
Net cash provided by (used in) financing activities		107,949			—		23,616			65,027			(88,643	)		107,949			5,816			—			(42,890	)		1,538			41,352			5,816
Net increase (decrease) in cash and cash equivalents		1,213			—		413			13,572			(13,572	)		1,626			17,416			—			(5,306	)		12,990			(12,990	)		12,110
Cash and cash equivalents, beginning of year		9,650			—		50,280			85,851			(85,851	)		59,930			3,861			(1	)		40,832			59,896			(59,896	)		44,692
Cash and cash equivalents, end of period	$	10,863		$	—	$	50,693		$	99,423		$	(99,423	)	$	61,556		$	21,277		$	(1	)	$	35,526		$	72,886		$	(72,886	)	$	56,802

16

Note 6 — Members’ Capital and Distributions

Series A Convertible Preferred Units

On July 21, 2010, we issued 10,327,022 Series A convertible preferred units (“Series A preferred units”) in a private placement to TPG Copenhagen, L.P. (“TPG”), an affiliate of TPG Capital, L.P., for gross proceeds of $300 million. The Series A preferred units are entitled to quarterly distributions in kind (paid in the form of additional Series A preferred units) for the first three years after the issue date.

	Series A
	Preferred Units Issued
Quarter Ending	As In-Kind Distributions			Issue Date	Amount
September 30, 2010		258,175		November 11, 2010	$	7,500,000
December 31, 2010		264,629		February 11, 2011		7,688,000
March 31, 2011		271,245		May 12, 2011		7,880,000
June 30, 2011		278,026(1	)	August 2011(1)		8,077,000

(1) Units will be issued on or about August 11, 2011

For additional information about our Series A preferred units, please read Note 6, “Members’ Capital and Distributions,” in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2010.

Common Units

The following table summarizes our quarterly cash distributions during 2011:

	Distribution
Quarter Ending	Per Unit		Date Declared	Record Date	Payment Date	Amount
December 31, 2010	$	0.575	January 12, 2011	February 1, 2011	February 11, 2011	$	38,456,000
March 31, 2011	$	0.575	April 13, 2011	April 29, 2011	May 12, 2011	$	38,538,000
June 30, 2011	$	0.575	July 13, 2011	August 1, 2011	August 11, 2011	$	38,687,000

Accounting for Equity-Based Compensation

We use ASC 718, “Stock Compensation,” to account for equity-based compensation expense related to awards issued under our long-term incentive plan (“LTIP”). As of June 30, 2011, the number of units available for grant under our LTIP totaled 2,254,000 of which up to 1,696,000 units were eligible to be issued as restricted common units, phantom units or unit awards.

Equity Awards.  We recognized non-cash compensation expense of $5,266,000 and $3,553,000 related to the amortization of equity-based compensation under our LTIP during the six months ended June 30, 2011 and 2010, respectively. See Item 8 in our Annual Report on Form 10-K, for the year ended December 31, 2010 for details on our equity-based compensation.

Unit Awards.  During the six months ended June 30, 2011, we issued 11,732 unit awards (common units that are not subject to vesting or forfeiture) to settle our Employee Incentive Compensation Program (“EICP”) and 2010 Management Incentive Compensation Plan (“MICP”) bonuses.

Since ASC 480, “Accounting for Certain Financial Instruments With Characteristics of Both Liabilities and Equity,” requires classification of unconditional obligations that the issuer must or may settle by issuing a variable number of units as a liability, we classify equity awards issued to settle EICP and MICP bonuses as liability awards. As of June 30, 2011, we have accrued $654,000 for the second quarter 2011 EICP bonuses. Additionally, as of June 30, 2011, we have accrued $1,256,000 of the 2011 MICP incentive bonuses and estimate unrecognized compensation costs related to these outstanding liability awards to be $1,675,000, which is expected to be recognized as expense on a straight-line basis through February 2012, when we settle 2011 MICP bonuses.

17

Note 7 — Net Income (Loss) Per Unit

Net income (loss) per unit is calculated in accordance with ASC 260, “Earnings Per Share,” which specifies 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.

Basic net income (loss) per unit excludes dilution and is computed by dividing net income (loss) attributable to each respective class of units by the weighted average number of units outstanding for each respective class during the period. Dilutive net income (loss) per unit reflects potential dilution that could occur if convertible securities were converted into common units or contracts to issue common units were exercised except when the assumed conversion or exercise would have an anti-dilutive effect on net income (loss) per unit. Dilutive net income (loss) per unit is computed by dividing net income (loss) attributable to each respective class of units by the weighted average number of units outstanding for each respective class of units during the period increased by the number of additional units that would have been outstanding if the dilutive potential units had been issued.

Because we had a net loss to common units for the three and six months ended June 30, 2011 and 2010, the weighted average units outstanding are the same for basic and diluted net loss per common unit. The following potentially dilutive common equity was excluded from the dilutive net loss per common unit calculation because including these equity securities would have been anti-dilutive:

					Six Months
	Three Months Ended				Ended
	June 30,				June 30,
	2011		2010		2011		2010
			(In thousands)
Employee options		820		1,214		820		1,214
Unit appreciation rights		365		345		365		345
Restricted units		59		104		59		104
Phantom units		988		920		988		920
Contingent incentive plan unit awards		39		37		56		49
Series A preferred units		10,996		—		11,121		—

18

Note 8 — Related Party Transactions

Natural Gas and Related Transactions

The following table summarizes transactions between us and affiliated entities:

	Three Months Ended June 30,					Six Months Ended June 30,
	2011			2010		2011			2010
	(In thousands)
Affiliates of Mr. Lawing:(1)
Natural gas sales(2)	$	—		$	1	$	(1	)	$	2
Gathering and compression services(3)		1			2		3			5
Natural gas purchases(4)		22			108		82			389
Reimbursable costs(5)		57			75		114			150
Webb Duval:
Natural gas sales(2)		39			12		39			12
Natural gas purchases(4)		(308	)		59		(369	)		112
Transportation costs(3)		119			61		170			131
Management fees(6)		56			56		112			112
Reimbursable costs(6)		224			72		337			139
Payable to us as of June 30, 2011(7)							275
Payable by us as of June 30, 2011(8)							45
Eagle Ford Gathering:
Management fees(6)		41			—		82			—
Reimbursable costs(6)		3,482			—		13,595			—
Capital project fees(6)		260			—		548
Payable to us as of June 30, 2011(7)							22
Payable by us as of June 30, 2011(8)							57
Liberty Pipeline Group:
Reimbursable costs(6)		12,011			—		15,505			—
Payable to us as of June 30, 2011(7)							30
Southern Dome:
Management fees(6)		62			63		125			125
Reimbursable costs(6)		105			61		201			157
Payable to us as of June 30, 2011(7)							52
Bighorn:
Compressor rental fees(9)		398			417		815			833
Gathering costs(3)		—			—		—			16
Natural gas purchases(4)		—			—		—			3
Management fees(6)		97			139		193			278
Reimbursable costs(6)		579			563		1,162			1,225
Payable to us as of June 30, 2011(7)							245
Fort Union:
Gathering costs(3)		1,379			1,267		2,659			2,638
Treating costs(4)		—			—		6			52
Management fees(6)		61			60		123			120
Reimbursable costs(6)		59			50		776			129
Payable to us as of June 30, 2011(7)							16
Other:
Natural gas sales(2)		—			65		—			125
Payable to us as of June 30, 2011(7)							6

19

Note 8 — Related Party Transactions (Continued)

(1)	These entities were controlled by John R. Eckel, Jr., our former Chairman and Chief Executive Officer, until his death in November 2009, and since that time have been controlled by Douglas L. Lawing, our Executive Vice President, General Counsel and Secretary, in his role as executor of Mr. Eckel’s estate.
(2)	Revenues included in natural gas sales on our consolidated statements of operations.
(3)	Revenues included in transportation, compression and processing fees on our consolidated statements of operations.
(4)	Included in costs of natural gas and natural gas liquids on our consolidated statements of operations.
(5)	Reimbursable costs received from Copano/Operations, Inc. (“Copano Operations”), controlled by Mr. Lawing, for its use of shared personnel, facilities and equipment. This was the only compensation we received from Copano Operations.
(6)	Management fees, reimbursable costs and capital project fees received from our unconsolidated affiliates are included in general and administrative expenses on our consolidated statements of operations.
(7)	Included in accounts receivable on the consolidated balance sheets.
(8)	Included in accounts payable on the consolidated balance sheets.
(9)	Revenues included in condensate and other on our consolidated statements of operations.

Other

Certain of our operating subsidiaries incurred costs payable to an affiliate of TPG for compression services totaling $21,000 and $55,000 for the three and six months ended June 30, 2011, respectively. Pursuant to a director designation agreement between us and TPG, our Board of Directors nominated Michael G. MacDougall, a partner with TPG, for election to the Board at our 2011 annual meeting. On May 18, 2011, our unitholders elected Mr. MacDougall to serve on our Board until our 2012 annual meeting.

Certain of our operating subsidiaries incurred costs payable to operating subsidiaries of Exterran Holdings, Inc. (“Exterran Holdings”) for the purchase and installation of compressors, compression services and compressor repairs totaling $1,380,000 and $3,132,000, respectively, for the three months ended June 30, 2011 and 2010 and $2,031,000 and $4,120,000, respectively, for the six months ended June 30, 2011 and 2010. Ernie L. Danner, a member of our Board of Directors, serves on the Board of Directors of Exterran Holdings and as its President and Chief Executive Officer.

During the second quarter of 2011, we purchased a maintenance vessel, to service our assets in the Copano Bay area, from Copano Operations for $102,000.

Our management believes that the terms of our related party agreements and transactions are no less favorable to us than those we could have obtained from unaffiliated third parties.

Note 9 — Commitments and Contingencies

Commitments

For the three months ended June 30, 2011 and 2010, rental expense for leased office space, vehicles, compressors and related field equipment used in our operations totaled $1,133,000 and $855,000, respectively. For the six months ended June 30, 2011 and 2010, rental expense for leased office space, vehicles, compressors and related field equipment used in our operations totaled $2,057,000 and $1,733,000, respectively.

We are party to firm transportation agreements with Wyoming Interstate Gas Company (“WIC”), under which we are obligated to pay for transportation capacity whether or not we use such capacity. Under these agreements, we are obligated to pay approximately $4,938,000 for the remainder of 2011, $9,867,000 in 2012, $8,978,000 in 2013, $5,509,000 in 2014, $4,093,000 in 2015 and $15,111,000 over the remainder of the contract term. The agreements expire on December 31, 2019. All of our obligations under these agreements are offset by capacity release agreements under which third party replacement shippers pay WIC for the right to use our capacity. Notwithstanding our capacity release, we remain obligated to pay WIC for such capacity in the event and to the extent that a

20

Note 9 — Commitments and Contingencies (Continued)

replacement shipper to whom such capacity has been released fails to pay. These capacity release agreements cover 100% of our total WIC capacity and continue through December 31, 2019. We have placed in escrow $1.9 million, classified as escrow cash on the consolidated balance sheets, as credit support for our obligations under the WIC agreements.

Additionally, we have two firm gathering agreements with Fort Union, under which we are obligated to pay for gathering capacity on the Fort Union system whether or not we use such capacity. Under these agreements, we are obligated to pay approximately $3,220,000 for the remainder of 2011, $7,154,000 for 2012, $7,665,000 for 2013, $7,665,000 for 2014, $7,665,000 for 2015 and $14,700,000 over the remainder of the contract term. These commitments expire on November 30, 2017.

We have fixed-quantity contractual commitments to Targa North Texas LP (“Targa”) in settlement of a dispute regarding what portion, if any, of natural gas we were purchasing from producers had been contractually dedicated by us for resale to Targa. As of June 30, 2011, we had fixed contractual commitments to provide Targa a total of 2.373 billion cubic feet of natural gas for each of 2011, 2012 and 2013. Under the terms of the agreement, we are obligated to pay annual fees ($1.10 per thousand cubic feet (“Mcf”), $1.15 per Mcf and $1.25 per Mcf for 2011, 2012 and 2013, respectively) to the extent our natural gas deliveries to Targa fall below the committed quantity. In February 2011, we paid $2,134,000 to Targa in settlement of our 2010 obligation. As of June 30, 2011, we have accrued $907,000 of our 2011 obligation.

We have committed to deliver minimum quantities of mixed NGLs under a fractionation and product sales agreement with Formosa Hydrocarbons Company, Inc. (“Formosa”). Under this agreement, we have no payment obligations for the remainder of 2011 or for 2012, and we will be obligated to pay $8,085,000 for 2013, $10,731,000 for 2014, $10,731,000 for 2015 and $77,822,000 over the remainder of the contract term, to the extent our mixed NGL deliveries fall below the committed quantity. This commitment expires on March 31, 2023.

Regulatory Compliance

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

Litigation

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

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

21

Note 10 — Supplemental Disclosures to the Statements of Cash Flows

	Six Months Ended June 30,
	2011		2010
	(In thousands)
Cash payments for interest, net of $4,072,000 and $1,315,000 capitalized in 2011 and 2010, respectively	$	23,727	$	26,554
Cash payments for federal and state income taxes	$	925	$	655
In-kind distributions to Series A convertible preferred unitholders	$	15,956	$	—

We incurred a change in liabilities for investing activities that had not been paid as of June 30, 2011 and 2010 of $10,763,000 and $14,645,000, respectively. Such amounts are not included in the change in accounts payable and accrued liabilities or with acquisitions, additions to property, plant and equipment and intangible assets on the consolidated statements of cash flows. As of June 30, 2011 and 2010, we accrued $18,762,000 and $19,894,000, respectively, for capital expenditures that had not been paid; therefore, these amounts are not included in investing activities for each respective period presented.

Note 11 — Financial Instruments

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

Commodity Risk Hedging Program

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

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

Financial instruments that we acquire pursuant to our risk management policy are generally designated as cash flow hedges under ASC 815, “Derivatives and Hedging,” and are recorded on our consolidated balance sheets at fair

22

Note 11 — Financial Instruments (Continued)

value. For derivatives designated as cash flow hedges, we recognize the effective portion of changes in fair value as other comprehensive income (“OCI”) and reclassify them to revenue within the consolidated statements of operations as settlements of the underlying transactions impact earnings. For derivatives not designated as cash flow hedges, we recognize changes in fair value as a gain or loss in our consolidated statements of operations. These financial instruments serve the same risk management purpose whether designated as a cash flow hedge or not.

We assess, both at the inception of each hedge and on an ongoing basis, whether our derivative instruments are effective in hedging the variability of forecasted cash flows associated with the underlying hedged items. If the correlation between a derivative instrument and the underlying hedged item is lost or it becomes probable that the original forecasted transaction will not occur, we discontinue hedge accounting based on a determination that the instrument is ineffective as a hedge. Subsequent changes in the derivative instrument’s fair value are immediately recognized as a gain or loss (increase or decrease in revenue) in our consolidated statements of operations.

As of June 30, 2011, we estimated that $22,298,000 of OCI will be reclassified as a decrease to earnings in the next 12 months as a result of monthly settlements of instruments hedging crude oil, NGLs and natural gas. In addition, for the three and six months ended June 30, 2011, we reclassified $548,000 of losses from accumulated OCI to earnings as a result of determining the forecasted transaction was probable of not occurring.

At June 30, 2011, the notional volumes of our commodity positions were:

Commodity	Instrument	Unit	2011		2012		2013
Natural gas	Calls	MMBtu/d		10,000		—		—
Natural gas	Call Spreads	MMBtu/d		7,100		—		—
Natural gas	Swaps	MMBtu/d		10,000		—		—
NGLs	Puts	Bbl/d		7,950		4,500		1,300
NGLs	Swaps	Bbl/d		1,500		—		—
Crude oil	Puts	Bbl/d		2,700		1,500		750
At December 31, 2010, the notional volumes of our commodity positions were:
Commodity	Instrument	Unit	2011		2012		2013
Natural gas	Calls	MMBtu/d		10,000		—		—
Natural gas	Call Spreads	MMBtu/d		7,100		—		—
Natural gas	Swaps	MMBtu/d		10,000		—		—
NGLs	Puts	Bbl/d		7,950		3,500		—
NGLs	Swaps	Bbl/d		1,500		—		—
Crude oil	Puts	Bbl/d		2,700		1,500		400

Interest Rate Risk Hedging Program

Our interest rate exposure results from variable rate borrowings under our revolving credit facility. We manage a portion of our interest rate exposure using interest rate swaps, which allow us to convert a portion of our variable rate debt into fixed rate debt. As of June 30, 2011, we hold a notional amount of $95.0 million in interest rate swaps, which have a weighted average fixed rate of 4.30% and mature in October 2012. As of June 30, 2011, our interest rate swaps were not designated as cash flow hedges.

For the three months ended June 30, 2011 and 2010, interest and other financing costs on the consolidated statements of operations include unrealized mark-to-market gains/(losses) of $501,000 and $888,000, respectively, on undesignated interest rate swaps. For the six months ended June 30, 2011 and 2010, interest and other financing costs on the consolidated statements of operations include unrealized mark-to-market gains/(losses) of $1,174,000 and, $810,000, respectively, on undesignated interest rate swaps.

As of June 30, 2011, we estimate that $227,000 of OCI will be reclassified as a decrease to earnings in the next 12 months as the underlying interest rate swaps expire.

23

Note 11 — Financial Instruments (Continued)

ASC 820 “Fair Value Measurement” and ASC 815 “Derivative and Hedging”

We recognize the fair value of our assets and liabilities that require periodic re-measurement as necessary based upon the requirements of ASC 820. This standard defines fair value, expands disclosure requirements with respect to fair value and specifies a hierarchy of valuation techniques based on whether the inputs to those valuation techniques are observable or unobservable. “Inputs” are the assumptions that a market participant would use in valuing the asset or liability. Observable inputs reflect market data obtained from independent sources, while unobservable inputs reflect our market assumptions. The three levels of the fair value hierarchy established by ASC 820 are as follows:

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

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

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

At each balance sheet date, we perform an analysis of all instruments subject to ASC 820 and include in Level 3 all of those for which fair value is based on significant unobservable inputs.

The following tables set forth by level within the fair value hierarchy our financial assets and liabilities that were accounted for at fair value on a recurring basis as of June 30, 2011 and December 31, 2010. As required by ASC 820, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value

24

Note 11 — Financial Instruments (Continued)

measurement requires judgment and may affect the valuation of fair value of assets and liabilities and their placement with the fair value hierarchy levels.

	Fair Value Measurements on
	Hedging Instruments(a)
	June 30, 2011
	Level 1		Level 2			Level 3		Total
	(In thousands)
Assets:
Natural Gas:
Short-term — Designated(b)	$	—	$	—		$	4	$	4
Short-term — Not designated(b)		—		151			—		151
Long-term — Designated(c)		—		—			—		—
Long-term — Not designated(c)		—		—			—		—
Natural Gas Liquids:
Short-term — Designated(b)		—		—			3,416		3,416
Short-term — Not designated(b)		—		—			10		10
Long-term — Designated(c)		—		—			8,667		8,667
Long-term — Not designated(c)		—		—			—		—
Crude Oil:
Short-term — Designated(b)		—		—			1,034		1,034
Short-term — Not designated(b)		—		—			1		1
Long-term — Designated(c)		—		—			4,245		4,245
Long-term — Not designated(c)		—		—			—		—
Total	$	—	$	151		$	17,377	$	17,528
Liabilities:
Natural Gas:
Short-term — Not designated(d)	$	—	$	260		$	—	$	260
Natural Gas Liquids:
Short-term — Designated(d)		—		—			5,050		5,050
Long-term — Designated(e)		—		—			—		—
Interest Rate:
Short-term — Not designated(d)		—		4,474			—		4,474
Long-term — Not designated(e)		—		1,041			—		1,041
Total	$	—	$	5,775		$	5,050	$	10,825
Total designated assets	$	—	$	—		$	12,316	$	12,316
Total not designated (liabilities)/assets	$	—	$	(5,624	)	$	11	$	(5,613	)

(a)	Instruments re-measured on a recurring basis.
(b)	Included on the consolidated balance sheets as a current asset under the heading of “Risk management assets.”
(c)	Included on the consolidated balance sheets as a noncurrent asset under the heading of “Risk management assets.”
(d)	Included on the consolidated balance sheets as a current liability under the heading of “Risk management liabilities.”

25

Note 11 — Financial Instruments (Continued)

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

	Fair Value Measurements on
	Hedging Instruments(a)
	December 31, 2010
	Level 1		Level 2			Level 3		Total
	(In thousands)
Assets:
Natural Gas:
Short-term — Designated(b)	$	—	$	—		$	87	$	87
Natural Gas Liquids:
Short-term — Designated(b)		—		—			6,812		6,812
Short-term — Not designated(b)		—		—			14		14
Long-term — Designated(c)		—		—			6,391		6,391
Crude Oil:
Short-term — Designated(b)		—		—			904		904
Short-term — Not designated(b)		—		—			19		19
Long-term — Designated(c)		—		—			5,552		5,552
Total	$	—	$	—		$	19,779	$	19,779
Liabilities:
Natural Gas:
Short-term — Not designated(d)	$	—	$	82		$	—	$	82
Natural Gas Liquids:
Short-term — Designated(d)		—		—			4,867		4,867
Interest Rate:
Short-term — Not designated(d)		—		4,408			—		4,408
Long-term — Not designated(e)		—		2,469			—		2,469
Total	$	—	$	6,959		$	4,867	$	11,826
Total designated assets	$	—	$	—		$	14,879	$	14,879
Total not designated (liabilities)/assets	$	—	$	(6,959	)	$	33	$	(6,926	)

(a)	Instruments re-measured on a recurring basis.
(b)	Included on the consolidated balance sheets as a current asset under the heading of “Risk management assets.”
(c)	Included on the consolidated balance sheets as a noncurrent asset under the heading of “Risk management assets.”
(d)	Included on the consolidated balance sheets as a current liability under the heading of “Risk management liabilities.”
(e)	Included on the consolidated balance sheets as a noncurrent liability under the heading of “Risk management and other noncurrent liabilities.”

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

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

26

Note 11 — Financial Instruments (Continued)

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

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

	Three Months Ended June 30, 2011
				Natural Gas
	Natural Gas			Liquids			Crude Oil			Total
	(In thousands)
Assets balance, beginning of period	$	31		$	5,053		$	4,904		$	9,988
Total gains or losses:
Non-cash amortization of option premium		(1,470	)		(3,905	)		(1,982	)		(7,357	)
Other amounts included in earnings		—			(3,155	)		303			(2,852	)
Included in accumulated other comprehensive loss		1,443			6,352			2,055			9,850
Settlements		—			2,698			—			2,698
Asset balance, end of period	$	4		$	7,043		$	5,280		$	12,327
Change in unrealized income included in earnings related to instruments still held as of the end of the period	$	—		$	(174	)	$	(92	)	$	(266	)

	Six Months Ended June 30, 2011
				Natural Gas
	Natural Gas			Liquids			Crude Oil			Total
	(In thousands)
Assets balance, beginning of period	$	87		$	8,350		$	6,475		$	14,912
Total gains or losses:
Non-cash amortization of option premium		(2,924	)		(7,761	)		(3,942	)		(14,627	)
Other amounts included in earnings		—			(5,098	)		790			(4,308	)
Included in accumulated other comprehensive loss		2,841			(510	)		157			2,488
Purchases		—			7,364			1,800			9,164
Settlements		—			4,698			—			4,698
Asset balance, end of period	$	4		$	7,043		$	5,280		$	12,327
Change in unrealized (income) loss included in earnings related to instruments still held as of the end of the period	$	—		$	(314	)	$	59		$	(255	)

27

Note 11 — Financial Instruments (Continued)

	Three Months Ended June 30, 2010
				Natural Gas
	Natural Gas			Liquids			Crude Oil			Total
	(In thousands)
Assets balance, beginning of period	$	722		$	25,498		$	16,805		$	43,025
Total gains or losses:
Non-cash amortization of option premium		(1,472	)		(4,106	)		(2,492	)		(8,070	)
Other amounts included in earnings		—			4,567			5,500			10,067
Included in accumulated other comprehensive loss		1,403			14,673			3,388			19,464
Purchases		—			—			3,425			3,425
Settlements		—			(4,395	)		(5,097	)		(9,492	)
Asset balance, end of year	$	653		$	36,237		$	21,529		$	58,419
Change in unrealized loss (income) included in earnings related to instruments still held as of the end of the period	$	—		$	27		$	(185	)	$	(158	)

	Six Months Ended June 30,
	2010
				Natural Gas
	Natural Gas			Liquids			Crude Oil			Total
	(In thousands)
Assets balance, beginning of period	$	2,752		$	15,641		$	24,213		$	42,606
Total gains or losses:
Non-cash amortization of option premium		(2,929	)		(8,163	)		(4,957	)		(16,049	)
Other amounts included in earnings		—			6,633			10,220			16,853
Included in accumulated other comprehensive loss		830			21,256			(1,334	)		20,752
Purchases		—			7,381			3,425			10,806
Settlements		—			(6,511	)		(10,038	)		(16,549	)
Asset balance, end of period	$	653		$	36,237		$	21,529		$	58,419
Change in unrealized (income) loss included in earnings related to instruments still held as of the end of the period	$	—		$	(29	)	$	154		$	125

Realized gains and losses for all Level 3 recurring items recorded in earnings are included in revenue on the consolidated statements of operations. Unrealized gains and losses for Level 3 recurring items that are not designated as cash flow hedges, or are ineffective as cash flow hedges, are also included in revenue on the consolidated statements of operations. The effective portion of unrealized gains and losses relating to cash flow hedges are included in accumulated other comprehensive loss on the consolidated balance sheets and consolidated statements of members’ capital and comprehensive loss.

Transfers in and/or out of Level 2 or Level 3 represent existing assets or liabilities where inputs to the valuation became less observable or assets and liabilities that were previously classified as a lower level for which the lowest significant input became observable during the period. There were no transfers in or out of Level 2 or Level 3 during the periods presented.

We have not entered into any derivative transactions containing credit risk related contingent features as of June 30, 2011.

28

Note 11 — Financial Instruments (Continued)

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

The Effect of Derivative Instruments on the Statements of Operations

							Amount of Gain
							(Loss) Recognized
							in Income
							on Derivative
	Amount of Gain			Amount of Gain			(Ineffective Portion
	(Loss) Recognized			(Loss) Reclassified			and Amount
Derivatives in	in OCI on			from Accumulated			Excluded from
ASC 815 Cash Flow	Derivatives			OCI into Income			Effectiveness			Statements of
Hedging Relationships	(Effective Portion)			(Effective Portion)			Testing)			Operations Location
(In thousands)
Three Months Ended June 30, 2011
Natural gas	$	(26	)	$	(1,470	)	$	—		Natural gas sales
Natural gas liquids		(463	)		(6,816	)		(177	)	Natural gas liquids sales
Crude oil		482			(1,573	)		(93	)	Condensate and other
Interest rate swaps		—			(83	)		—		Interest and other financing costs
Total	$	(7	)	$	(9,942	)	$	(270	)
Six Months Ended June 30, 2011
Natural gas	$	(83	)	$	(2,924	)	$	—		Natural gas sales
Natural gas liquids		(12,599	)		(12,088	)		(317	)	Natural gas liquids sales
Crude oil		(2,975	)		(3,132	)		40		Condensate and other
Interest rate swaps		(0	)		(180	)		—		Interest and other financing costs
Total	$	(15,657	)	$	(18,324	)	$	(277	)
Three Months Ended June 30, 2010
Natural gas	$	(70	)	$	(1,472	)	$	—		Natural gas sales
Natural gas liquids		14,926			253			27		Natural gas liquids sales
Crude oil		5,252			1,864			82		Condensate and other
Interest rate swaps		—			(121	)		—		Interest and other financing costs
Total	$	20,108		$	524		$	109
Six Months Ended June 30, 2010
Natural gas	$	(2,083	)	$	(2,912	)	$	—		Natural gas sales
Natural gas liquids		19,855			(1,401	)		(29	)	Natural gas liquids sales
Crude oil		2,901			4,235			107		Condensate and other
Interest rate swaps		—			(254	)		—		Interest and other financing costs
Total	$	20,673		$	(332	)	$	78

29

Note 11 — Financial Instruments (Continued)

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

The Effect of Derivative Instruments on the Statements of Operations

	Amount of Gain
Derivatives Not Designated as	(Loss) Recognized in			Statement of
Hedging Instruments Under ASC 820	Income on Derivative			Operations Location
	(In thousands)
Three Months Ended June 30, 2011
Natural gas	$	(65	)	Natural gas sales
Natural gas liquids		(281	)	Natural gas liquids sales
Crude oil		396		Condensate and other
Interest rate swaps		(381	)	Interest and other financing costs
Total	$	(331	)
Six Months Ended June 30, 2011
Natural gas	$	(128	)	Natural gas sales
Natural gas liquids		(84	)	Natural gas liquids sales
Crude oil		749		Condensate and other
Interest rate swaps		(563	)	Interest and other financing costs
Total	$	(26	)
Three Months Ended June 30, 2010
Natural gas	$	116		Natural gas sales
Natural gas liquids		146		Natural gas liquids sales
Crude oil		334		Condensate and other
Interest rate swaps		(512	)	Interest and other financing costs
Total	$	84
Six Months Ended June 30, 2010
Natural gas	$	(108	)	Natural gas sales
Natural gas liquids		151		Natural gas liquids sales
Crude oil		83		Condensate and other
Interest rate swaps		(1,978	)	Interest and other financing costs
Total	$	(1,852	)

30

Note 12 — Fair Value of Financial Instruments

Amounts reflected in our consolidated balance sheets as of June 30, 2011 for cash and cash equivalents approximate fair value. The fair value of our revolving credit facility has been estimated based on similar debt transactions that occurred during the six months ended June 30, 2011. Estimates of the fair value of our Senior Notes are based on market information as of June 30, 2011. A summary of the fair value and carrying value of the financial instruments is shown in the table below.

	June 30, 2011				December 31, 2010
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
	(In thousands)
Cash and cash equivalents	$	61,556	$	61,556	$	59,930	$	59,930
Revolving credit facility		195,000		195,000		10,000		9,873
2016 Notes		—		—		332,665		341,813
2018 Notes		249,525		258,258		249,525		254,516
2021 Notes		360,000		354,600		—		—

Note 13 — Segment Information

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

•  Texas, which provides midstream natural gas services in south and north Texas, including gathering and intrastate transportation of natural gas, and related services such as compression, dehydration, treating, processing and marketing. Our Texas segment also provides NGL fractionation and transportation. This segment includes our equity investments in Webb Duval, Eagle Ford Gathering and Liberty Pipeline Group, and a processing plant located in southwest Louisiana.

•  Oklahoma, which provides midstream natural gas services in central and east Oklahoma, including gathering of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our equity investment in Southern Dome.

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

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

We evaluate segment performance based on segment gross margin before depreciation, amortization and impairment. Operating and maintenance expenses and general and administrative expenses incurred at Corporate and other are allocated to Texas, Oklahoma and Rocky Mountains based on expenses directly attributable to each segment or an allocation based on activity, as appropriate. We use the same accounting methods and allocations in the preparation of our segment information as used in our consolidated reporting.

31

Note 13 — Segment Information (Continued)

Summarized financial information concerning our reportable segments is shown in the following tables:

							Rocky						Corporate
	Texas			Oklahoma			Mountains			Total Segments			and Other			Consolidated
							(In thousands)
Three Months Ended June 30, 2011:
Total segment gross margin	$	46,134		$	28,665		$	771		$	75,570		$	(10,274	)	$	65,296
Operations and maintenance expenses		8,908			6,794			61			15,763			—			15,763
Depreciation and amortization		6,861			9,358			766			16,985			378			17,363
General and administrative expenses		2,955			2,389			296			5,640			6,261			11,901
Taxes other than income		685			712			—			1,397			—			1,397
Equity in earnings from unconsolidated affiliates		(23	)		(669	)		(614	)		(1,306	)		—			(1,306	)
Operating income (loss)	$	26,748		$	10,081		$	262		$	37,091		$	(16,913	)	$	20,178
Natural gas sales	$	76,684		$	48,651		$	128		$	125,463		$	(1,535	)	$	123,928
Natural gas liquids sales		108,919			78,898			—			187,817			(7,059	)		180,758
Transportation, compression and processing fees		20,906			2,778			4,214			27,898			—			27,898
Condensate and other		4,629			10,124			398			15,151			(1,679	)		13,472
Sales to external customers	$	211,138		$	140,451		$	4,740		$	356,329		$	(10,273	)	$	346,056
Interest and other financing costs	$	—		$	—		$	—		$	—		$	11,454		$	11,454
Three Months Ended June 30, 2010:
Total segment gross margin	$	31,751		$	21,821		$	1,148		$	54,720		$	2,115		$	56,835
Operations and maintenance expenses		7,497			5,670			63			13,230			—			13,230
Depreciation and amortization		6,452			7,942			765			15,159			424			15,583
General and administrative expenses		2,763			1,690			589			5,042			5,858			10,900
Taxes other than income		600			578			3			1,181			—			1,181
Equity in loss (earnings) from unconsolidated affiliates		27			(686	)		24,291			23,632			—			23,632
Operating income (loss)	$	14,412		$	6,627		$	(24,563	)	$	(3,524	)	$	(4,167	)	$	(7,691	)
Natural gas sales	$	38,622		$	47,222		$	331		$	86,175		$	(1,356	)	$	84,819
Natural gas liquids sales		60,016			54,324			—			114,340			462			114,802
Transportation, compression and		10,688			1,388			4,440			16,516			—			16,516
processing fees
Condensate and other		2,414			8,073			417			10,904			3,010			13,914
Sales to external customers	$	111,740		$	111,007		$	5,188		$	227,935		$	2,116		$	230,051
Interest and other financing costs	$	—		$	—		$	—		$	—		$	13,351		$	13,351

32

Note 13 — Segment Information (Continued)

						Rocky						Corporate
	Texas		Oklahoma			Mountains			Total Segments			and Other			Consolidated
	In thousands
Six Months Ended June 30, 2011:
Total segment gross margin	$	91,145	$	51,747		$	1,813		$	144,705		$	(19,063	)	$	125,642
Operations and maintenance expenses		17,733		13,013			116			30,862			—			30,862
Depreciation and amortization		13,530		18,401			1,531			33,462			770			34,232
General and administrative expenses		5,721		4,567			664			10,952			13,547			24,499
Taxes other than income		1,227		1,282			1			2,510			17			2,527
Equity in loss (earnings) from unconsolidated affiliates		196		(1,371	)		(1,833	)		(3,008	)		—			(3,008	)
Operating income (loss)	$	52,738	$	15,855		$	1,334		$	69,927		$	(33,397	)	$	36,530
Natural gas sales	$	136,785	$	93,736		$	253		$	230,774		$	(3,051	)	$	227,723
Natural gas liquids sales		197,599		145,020			—			342,619			(12,860	)		329,759
Transportation, compression and		38,582		5,200			8,587			52,369			—			52,369
Condensate and other		9,492		18,975			815			29,282			(3,152	)		26,130
Sales to external customers	$	382,458	$	262,931		$	9,655		$	655,044		$	(19,063	)	$	635,981
Interest and other financing costs	$	—	$	—		$	—		$	—		$	23,370		$	23,370
Segment assets	$	734,468	$	670,897		$	629,193		$	2,034,558		$	44,349		$	2,078,907
Six Months Ended June 30, 2010:
Total segment gross margin	$	58,916	$	46,096		$	2,251		$	107,263		$	697		$	107,960
Operations and maintenance expenses		14,066		11,103			164			25,333			—			25,333
Depreciation and amortization		12,037		16,356			1,531			29,924			860			30,784
General and administrative expenses		5,174		3,977			1,125			10,276			11,166			21,442
Taxes other than income		1,263		1,077			3			2,343			—			2,343
Equity in loss (earnings) from unconsolidated affiliates		91		(1,640	)		23,386			21,837			—			21,837
Operating income (loss)	$	26,285	$	15,223		$	(23,958	)	$	17,550		$	(11,329	)	$	6,221
Natural gas sales	$	100,433	$	106,703		$	935		$	208,071		$	(3,036	)	$	205,035
Natural gas liquids sales		120,302		115,348			—			235,650			(1,530	)		234,120
Transportation, compression and		18,025		2,631			8,974			29,630			—			29,630
Condensate and other		4,808		17,028			833			22,669			5,263			27,932
Sales to external customers	$	243,568	$	241,710		$	10,742		$	496,020		$	697		$	496,717
Interest and other financing costs	$	—	$	—		$	—		$	—		$	28,296		$	28,296

33

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 historical consolidated financial statements and notes thereto included in Item 1 of this report, as well as Item 7, “Management’s Discussion and Analysis of Financial Condition and Results of Operations,” and the audited financial statements included in Item 8 of our Annual Report on Form 10-K for the year ended December 31, 2010 (the “2010 10-K”).

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

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

Overview

Through our subsidiaries and equity investments, we own and operate natural gas gathering and intrastate transportation pipeline assets, natural gas processing and fractionation facilities and NGL pipelines. We operate in Texas, Oklahoma, Wyoming and Louisiana. We manage our business and analyze and report our results of operations on a segment basis. Our operations are divided into three operating segments: Texas, Oklahoma and Rocky Mountains.

•  Our Texas segment provides midstream natural gas services in south and north Texas, including gathering and transportation of natural gas, and related services such as compression, dehydration, treating, processing and marketing. Our Texas segment also provides NGL fractionation and transportation. This segment includes our equity investments in Webb Duval, Eagle Ford Gathering and Liberty Pipeline Group and a processing plant located in southwest Louisiana.

•  Our Oklahoma segment provides midstream natural gas services in central and east Oklahoma, including gathering of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our equity investment in Southern Dome.

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

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

Recent Developments

Increased Presence in Eagle Ford Shale.  On June 30, 2011, Eagle Ford Gathering announced that it had executed two new long-term contracts to provide transportation, processing and fractionation services for up to 100,000 MMBtu per day of Eagle Ford Shale natural gas production. In addition, on June 15, 2011, Eagle Ford

34

Gathering announced a long-term agreement with Williams Partners L.P. to process Eagle Ford Shale production at Williams Partners’ Markham processing plant. Eagle Ford Gathering will construct a 7-mile, 20-inch lateral to connect to the Markham plant and install approximately 3,400 horsepower of compression at a cost of approximately $27 million. The agreement will initially provide Eagle Ford Gathering with 100 MMcf/d of processing capacity at the Markham plant, with an option to increase its capacity to up to 200 MMcf/d.

Amended Credit Facility.  On June 10, 2011, we entered into an amendment and restatement of our credit agreement with Bank of America, N.A., as Administrative Agent. The amended and restated credit agreement provides for a $700 million senior secured revolving credit facility that matures June 10, 2016. For a description of the agreement, please read “— Liquidity and Capital Resources — Our Indebtedness.”

Declaration of Common Unit Distribution.  On July 13, 2011, our Board of Directors declared a cash distribution of $0.575 per common unit for the second quarter of 2011. This distribution will be paid on August 11, 2011 to all common unitholders of record at the close of business on August 1, 2011.

Trends and Uncertainties

This section, which describes recent changes in factors affecting our business, should be read in conjunction with “— How We Evaluate Our Operations” and “— How We Manage Our Operations” below and in Item 7 of our 2010 10-K. Many of the factors affecting our business are beyond our control and are difficult to predict.

Commodity Prices and Producer Activity

Our gross margins and total distributable cash flow are affected by natural gas and NGL prices and by drilling activity near our gathering and processing assets. Generally, natural gas and NGL prices affect the cash flow and profitability of our Texas and Oklahoma segments directly and, to the extent that they influence the level of drilling activity, these prices also affect all of our segments indirectly. Additionally, crude oil prices affect us indirectly because they tend to be highly correlated with NGL prices, and because crude oil drilling activity could result in increased production of casinghead natural gas associated with crude oil production. For a discussion of how we use hedging to reduce the effects of commodity price fluctuations on our cash flow and profitability, please read Note 11, “Financial Instruments,” included in our unaudited consolidated financial statements included in Item 1, and Item 3, “Quantitative and Qualitative Disclosures about Market Risk.”

Natural gas, NGL and crude oil prices affect the long-term growth and sustainability of our business because they influence exploration and production activity. Commodity price fluctuations are among the factors that producers consider as they schedule drilling projects. Producers typically increase drilling activity when natural gas, NGL and crude oil prices are sufficient to make drilling and completion activity economic and, depending on the severity and duration of an unfavorable pricing environment, may suspend drilling and completion activity to the degree they have become uneconomic. Changes in drilling and completion activity are reflected in production volumes (and in turn, in our throughput volumes) only gradually because of the time required to drill, complete and attach new wells (or if drilling is declining, because of continuing production from already-completed wells). Delays between the time wells are drilled and actual flow to market can range from a few days in areas with minimal completion and attachment processes to as long as 18 months for extensive dewatering or completion of facilities involving long lead times. In addition, delays between drilling and flow can be dependent on downstream factors such as availability of liquids removal and transportation capabilities.

The level at which drilling and production become economic depends on a combination of factors in addition to natural gas, NGL and crude oil prices. For producers of rich gas who benefit from improved processing economics under their sales contracts, the disincentive of low natural gas prices could be offset if NGL prices are consistently high relative to natural gas prices. Strong crude oil prices could also support increased production of associated casinghead natural gas.

Commodity prices generally are influenced by various factors that affect supply and demand. These factors include regional drilling activity, available pipeline capacity, the severity of winter and summer weather (and other factors that influence consumption), storage levels, competing supplies (such as crude oil or liquefied natural gas imports or exports), and NGL transportation and fractionation capacity. Factors that can cause volatility in crude oil

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prices, such as events in the Middle East, can also affect NGL prices because the two are highly correlated. Many of the factors affecting prices are in turn dependent on overall economic activity.

Other factors that affect a producer’s ability and incentives to drill include the availability of capital and the producer’s drilling, completion and other operating costs, which are influenced by the characteristics of the hydrocarbon reservoir and equipment and services availability, among other things. The expected composition of wellhead production and the availability and proximity of transportation, processing and fractionation infrastructure and market outlets are significant considerations. A factor that we believe has supported strong activity in unconventional shale plays is low geologic risk — in other words, a greater likelihood that wells drilled will be productive — which reduces a producer’s overall drilling costs. Also, some producers can rely on commodity price hedging to support drilling activity when prices are less favorable, and producers may drill when they otherwise would not to the extent that drilling activity is necessary to maintain their leasehold interests or under the terms of their capital commitments.

Second-Quarter 2011 Commodity Prices Overall.  Natural gas prices on the NYMEX remained above $4.20 per MMBtu for each month of the second quarter of 2011 and averaged 5% higher compared to the first quarter of 2011, which included a low of $3.79 per MMBtu in March. Average NGL prices and crude oil prices decreased moderately after beginning the quarter at their highest levels since 2008.

Pricing Trends in Texas.  The following graph and table summarize prices for natural gas and NGLs on the primary indices we use for Texas pricing and for crude oil on NYMEX.

Texas Prices for Crude Oil, Natural Gas and NGLs⁽¹⁾

(1) Average crude oil prices are based on NYMEX. Natural gas prices are first-of-the-month index prices. Average monthly NGL prices are calculated based on Mont Belvieu prices and our weighted-average product mix for the period indicated.

	Quarterly Data for Texas:
	Q1 2010		Q2 2010		Q3 2010		Q4 2010		Q1 2011		Q2 2011
Houston Ship Channel ($/MMBtu)	$	5.36	$	4.04	$	4.33	$	3.78	$	4.06	$	4.29
Mont Belvieu ($/Bbl)	$	47.66	$	43.14	$	40.16	$	48.03	$	51.22	$	58.57
NYMEX crude oil ($/Bbl)	$	78.72	$	78.03	$	76.20	$	85.17	$	94.10	$	102.56
Service throughput (MMBtu/d)		582,958		559,876		590,116		648,941		654,996		665,040
Plant inlet (MMBtu/d)		457,233		469,019		516,949		574,616		560,903		588,533
NGLs produced (Bbls/d)		15,339		18,382		19,685		21,388		23,228		26,913
Segment gross margin (in thousands)	$	27,165	$	31,751	$	31,218	$	38,548	$	45,011	$	46,134

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The first-of-the-month price for natural gas on the Houston Ship Channel index was $4.37 per MMBtu for July 2011 and the spot price was $4.39 per MMBtu on July 29, 2011. The weighted-average daily price for NGLs at Mont Belvieu for July 2011, based on our second quarter 2011 product mix, was $59.62 per Bbl.

Our standardized processing margins averaged $0.902 and $0.557 per gallon for the three months ended June 30, 2011 and 2010, respectively. The average standardized processing margin for the period from January 1, 1989 through June 30, 2011 is $0.183 per gallon. Our “standardized” processing margin is based on a fixed set of assumptions with respect to NGL composition and fuel consumption per recovered gallon. Our results of operations may not necessarily correlate to the changes in our standardized processing margin because of the impact of factors other than commodity prices, such as volumes, changes in NGL composition, recovery rates and variable contract terms. However, we believe this calculation is useful to investors for tracking commodity price relationships that affect our Texas processing operations.

Pricing Trends in Oklahoma.  The following graph and table summarize prices for natural gas and NGLs on the primary indices we use for Oklahoma pricing and crude oil on the NYMEX.

Oklahoma Prices for Crude Oil, Natural Gas and NGLs⁽¹⁾

(1) Average crude oil prices are based on NYMEX. Natural gas prices are first-of-the-month index prices. Average monthly NGL prices are calculated based on Conway prices and our weighted-average product mix for the period indicated.

	Quarterly Data for Oklahoma:
	Q1 2010		Q2 2010		Q3 2010		Q4 2010		Q1 2011		Q2 2011
CenterPoint East ($/MMBtu)	$	5.22	$	3.86	$	4.14	$	3.53	$	3.93	$	4.14
Conway ($/Bbl)	$	44.44	$	36.34	$	36.53	$	43.91	$	46.36	$	50.17
NYMEX crude oil ($/Bbl)	$	78.72	$	78.03	$	76.20	$	85.17	$	94.10	$	102.56
Service throughput (MMBtu/d)		248,784		259,972		270,184		267,353		269,550		283,870
Plant inlet (MMBtu/d)		152,190		156,204		156,676		154,257		147,710		157,424
NGLs produced (Bbls/d)		15,334		16,653		16,541		16,480		16,037		17,331
Segment gross margin (in thousands)	$	24,275	$	21,821	$	23,010	$	24,511	$	23,082	$	28,665

The first-of-the-month price for natural gas on the CenterPoint East index was $4.14 per MMBtu for July 2011 and the spot price was $4.33 per MMBtu on July 29, 2011. The weighted-average daily price for NGLs at Conway for July 2011, based on our second quarter 2011 product mix, was $50.78 per Bbl.

Basis Trends.  Basis risk — the risk that the value of a hedge may not move in tandem with the value of the actual price exposure that is being hedged — affects our hedges of Oklahoma NGL volumes because, due to the limited liquidity in the forward market for Conway-based hedge instruments, we use Mont Belvieu-priced hedge instruments for our Oklahoma NGL volumes. In addition, our long position in natural gas in Oklahoma can serve as

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a hedge against any net short position in natural gas we may have in Texas. To the extent we rely on natural gas from our Oklahoma segment, which is priced primarily on the CenterPoint East index, to offset a short position in natural gas in our Texas segment, which is priced on the Houston Ship Channel index, we are subject to basis risk.

Prices for the second quarter of 2011 reflected an increase of the average basis differential between Mont Belvieu and Conway, which was $6.91 per Bbl, as compared to $4.34 per Bbl for the first quarter of 2011. Prices for purity ethane accounted for 59% of this basis differential. For July 2011, the basis differential averaged $7.38 per Bbl, and at July 29, 2011 the basis differential was $8.79 per Bbl. The average basis differential between Houston Ship Channel and CenterPoint East natural gas index prices was $0.15 per MMBtu for the second quarter of 2011, an increase from $0.13 per MMBtu for the first quarter of 2011, and was $0.23 per MMBtu for July 2011 and $0.06 per MMBtu at July 29, 2011.

The following graph summarizes the basis differential between Mont Belvieu and Conway prices.

Mont Belvieu — Conway Basis⁽¹⁾

(1) Average NGL prices are calculated based on our Oklahoma segment weighted-average product mix for the period indicated.

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Pricing Trends in the Rocky Mountains.  The following graph and table summarize prices for natural gas on the Colorado Interstate Gas (“CIG”), the primary index we use for the Rocky Mountains.

Rocky Mountains Natural Gas Prices⁽¹⁾

(1) Natural gas prices are first-of-the-month index prices.

	Quarterly Data for Rocky Mountains:
	Q1 2010		Q2 2010		Q3 2010		Q4 2010		Q1 2011		Q2 2011
CIG ($/MMBtu)	$	5.14	$	3.61	$	3.50	$	3.42	$	3.83	$	3.98
Pipeline throughput (MMBtu/d)(1)		931,319		900,047		913,730		886,568		581,051		533,329
Segment gross margin (in thousands)(2)	$	1,103	$	1,148	$	1,091	$	1,098	$	1,042	$	771

(1)	Includes 100% of Bighorn and Fort Union, but does not reflect an additional 288,966 MMBtu/d and 327,894 MMBtu/d of additional long-term contractually committed volumes, based on which Fort Union also received payments for the first and second quarters of 2011, respectively.
(2)	Excludes results and volumes associated with our equity interests in Bighorn and Fort Union.

The first-of-the-month price for natural gas on the CIG index was $3.96 per MMBtu for July 2011 and the spot price was $3.90 per MMBtu on July 29, 2011.

Second Quarter 2011 Drilling and Production Activity.

•  Drilling.  Drilling activity in the second quarter increased significantly in the Eagle Ford Shale in Texas, where we continued to work to secure additional long-term supply contracts. Producer activity in the Woodford Shale behind our Mountains systems in Oklahoma and the north Barnett Shale Combo play behind our Saint Jo plant in Texas continued at a rapid pace consistent with the first quarter of 2011. In the Rocky Mountains and in other areas of Texas and Oklahoma, drilling activity has remained low.

•  Volumes.  Our overall service throughput volumes for the second quarter of 2011 were consistent with the first quarter of 2011, primarily reflecting the effect of a 65% increase in Eagle Ford Shale volumes on our DK pipeline and Live Oak system, a 50% increase in north Barnett Shale Combo volumes on our Saint Jo system, and a 5% increase in Woodford Shale volumes on our Mountains systems, offset by a 26% decrease in third-party pipeline volumes we received from Kinder Morgan at our Houston Central complex, a 33% decrease on our Upper Gulf Coast system in Texas due to warmer weather and natural production declines

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elsewhere in Texas. In the Rocky Mountains, volumes have continued to decline due to limited drilling activity in the Powder River Basin. In addition, Fort Union’s physical volumes in the second quarter of 2011 remained flat after declining 40% in the first quarter of 2011 due to completion of TransCanada’s Bison Pipeline, which began service in January 2011. The impact on Fort Union’s revenue was largely offset by payments based on long-term contractual volume commitments.

•  Outlook. So long as NGL and crude prices generally remain strong relative to natural gas prices, we anticipate continued drilling activity in rich gas areas such as the Eagle Ford Shale and the north Barnett Shale Combo plays. We believe that these plays are attractive to producers because they offer rich gas in a favorable NGL price environment, low geologic risk and nearby infrastructure and market access, as well as high initial production rates. In addition, we have seen moderate increases in drilling activity in the Mississippi Lime play in northern Oklahoma and are evaluating the economic viability of the play and opportunities to expand into the play from our existing assets in the area.

Natural gas prices have been relatively stable but have not yet reached levels that provide producers incentives to increase drilling in the Powder River Basin and in areas where producers employ conventional drilling techniques. Drilling and related activity in shale plays have consumed significant capital and other resources, which may effectively raise barriers to entry in other areas. However, other factors such as commodity hedges, improved well completion technology or the need to maintain leasehold interests will also influence drilling and completion activity. We expect that many producers who rely on conventional drilling, produce mainly lean gas, or both, will wait to see sustained increases in natural gas prices before resuming significant drilling activity. We do not expect volume growth in the Rocky Mountains until prices are sufficient to support substantial drilling and completion activity.

Other Industry Trends.  NGL transportation and fractionation facilities continue to experience capacity constraints, which generally results in higher NGL transportation and fractionation costs for parties that do not have contractually fixed costs. Growing rich natural gas volumes from the Eagle Ford Shale are placing additional pressure on existing transportation capacity for NGLs, condensate and crude oil, while transportation costs for heavier NGL products in Texas remain higher due to lack of broad pipeline infrastructure and trucking. As drilling activity in the Eagle Ford Shale increases, required resources such as water used in hydraulic fracturing will likely become more costly and difficult to obtain. Recent severe drought conditions in Texas have further strained water supplies. These effects could limit the benefits producers receive from rich gas production and, in the near term, could affect the level of drilling activity in rich gas plays. In addition, activity in the Eagle Ford Shale could ultimately be impacted by downstream capacity constraints or insufficient demand and storage capacity for residue gas.

Factors Affecting Operating Results and Financial Condition

Our results for the second quarter of 2011 reflect higher gross margins due to drilling activity that has been supported by stronger NGL prices and producers’ focus on shale play development. Higher volumes under fee-based contracts, as well as higher NGL prices under commodity-sensitive contracts, contributed to increased gross margins in both Texas and Oklahoma. Our combined operating segment gross margins for the second quarter of 2011 increased 8% compared to the first quarter of 2011. Drilling in some of our operating areas has remained limited since 2009’s weak commodity pricing environment. We and some of the joint ventures in which we own interests continue to experience flat or declining volumes, particularly from lean gas and conventional drilling areas, due to low natural gas prices and low drilling activity.

Higher NGL and crude oil prices combined with lower strike prices on our commodity derivative instruments reduced our cash flow from commodity hedge settlements. For the first six months of 2011, we paid $4.8 million in net cash settlements from our commodity hedge portfolio, compared to receiving $16.5 million in net cash settlements for the first six months of 2010.

How We Evaluate Our Operations

We believe that investors and other market participants benefit from having access to the various financial and operating measures that our management uses in evaluating our performance. These measures include:

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(i) throughput volumes; (ii) segment gross margin and total segment gross margin; (iii) operations and maintenance expenses; (iv) general and administrative expenses; (v) EBITDA and adjusted EBITDA and (vi) total distributable cash flow.

Segment gross margin, total segment gross margin, EBITDA, adjusted EBITDA and total distributable cash flow are non-generally accepted accounting principles, or non-GAAP, financial measures. We use non-GAAP financial measures to evaluate our core profitability and to assess the financial performance of our assets. A reconciliation of each non-GAAP measure to its most directly comparable GAAP measure is provided below. Non-GAAP financial measures should not be considered as alternatives to GAAP measures such as net income (loss), operating income (loss), income (loss) from continuing operations, cash flows from operating activities or any other GAAP measure of liquidity or financial performance. Our non-GAAP financial measures may not be comparable to similarly titled measures of other companies, which may not calculate their measures in the same manner.

As discussed below, we have revised our calculation of adjusted EBITDA and our presentation of total distributable cash flow from prior periods. For additional discussion about our other financial and operating performance measures, please read “— How We Evaluate Our Operations” under Item 7 of our 2010 10-K.

Adjusted EBITDA.  Commencing with the second quarter of 2011, we revised our calculation of adjusted EBITDA to more closely resemble that of many of our peers in terms of measuring our ability to generate cash. Our adjusted EBITDA (as revised) equals:

•  net income (loss);

•  plus interest and other financing costs, provision for income taxes, depreciation, amortization and impairment expense, non-cash amortization expense associated with our commodity derivative instruments, distributions from unconsolidated affiliates, loss on refinancing of unsecured debt and equity-based compensation expense;

•  minus equity in earnings (loss) from unconsolidated affiliates and unrealized gains (losses) from commodity risk management activities; and

•  plus or minus other miscellaneous non-cash amounts affecting net income (loss) for the period.

In calculating adjusted EBITDA as revised, we no longer add to EBITDA (earnings before interest taxes depreciation and amortization our share of the depreciation, amortization and impairment expense and interest and other financing costs embedded in our equity in earnings (loss) from unconsolidated affiliates; instead we now add to EBITDA (i) our impairment expense, and other non-cash amounts affecting net income (loss) for the period, (ii) non-cash amortization expense associated with our commodity derivative instruments, (iii) loss on refinancing of unsecured debt and (iv) distributions from unconsolidated affiliates.

We believe that our revised calculation of adjusted EBITDA is a more effective tool for our management in evaluating our operating performance for several reasons. Although our historical method for calculating adjusted EBITDA was useful in assessing the performance of our assets (including our unconsolidated affiliates) without regard to financing methods, capital structure or historical cost basis, the prior calculation was not as useful in evaluating the core performance of our assets and their ability to generate cash because adjustments for a number of non-cash expenses and other non-cash and non-operating items were not reflected in the calculation and the impact of cash distributions from our unconsolidated affiliates was likewise not reflected. We believe that the revised calculation of adjusted EBITDA is more consistent with the method and presentation used by many of our peers and will allow management and analysts to better evaluate our performance relative to our peer companies.

Also, we believe that the revised calculation more effectively represents what lenders and debt holders, as well as industry analysts and many of our unitholders, have indicated is useful in assessing our core performance and outlook and comparing us to other companies in our industry. For example, we believe that adjusted EBITDA as revised may provide investors and analysts with a more useful tool for evaluating our leverage because it more closely resembles Consolidated EBITDA (as defined under our revolving credit facility), which is used by our lenders to calculate our financial covenants. Consolidated EBITDA differs from adjusted EBITDA in that it includes further adjustments to (i) reflect the pro forma effects of material acquisitions and dispositions and (ii) in the case of leverage ratio calculations, includes projected EBITDA from significant capital projects under

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construction. Please read — Liquidity and Capital Resources — Our Indebtedness — Amended and Restated Revolving Credit Agreement.”

Total Distributable Cash Flow.  Commencing with the second quarter of 2011, we present total distributable cash flow as net income (loss) plus all adjustments included in the adjusted EBITDA calculation described above and minus: (i) interest expense, (ii) current tax expense and (iii) maintenance capital expenditures. Although we have revised our presentation of total distributable cash flow, the components of the calculation have not changed except that total distributable cash flow now eliminates the impact of any loss on refinancing of unsecured debt because such losses do not reduce operating cash flow.

Reconciliation of Non-GAAP Financial Measures.  The following table presents a reconciliation of the non-GAAP financial measures of (i) total segment gross margin (which consists of the sum of individual segment gross margins and the results of our risk management activities, which are included in corporate and other) to the GAAP

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financial measure of operating income and (ii) EBITDA, adjusted EBITDA and total distributable cash flow to the GAAP financial measure of net income (loss), for each of the periods indicated.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
	($ in thousands)
Reconciliation of total segment gross margin to operating income (loss):
Operating income (loss)	$	20,178		$	(7,691	)	$	36,530		$	6,221
Add: Operations and maintenance expenses		15,763			13,230			30,862			25,333
Depreciation and amortization		17,363			15,583			34,232			30,784
General and administrative expenses		11,901			10,900			24,499			21,442
Taxes other than income		1,397			1,181			2,527			2,343
Equity in (earnings) loss from unconsolidated affiliates		(1,306	)		23,632			(3,008	)		21,837
Total segment gross margin	$	65,296		$	56,835		$	125,642		$	107,960
Reconciliation of EBITDA, adjusted EBITDA and total distributable cash flow to net loss:
Net loss	$	(9,361	)	$	(21,111	)	$	(5,829	)	$	(22,371	)
Add: Depreciation and amortization		17,363			15,583			34,232			30,784
Interest and other financing costs		11,454			13,351			23,370			28,296
Provision for income taxes		(140	)		106			771			340
EBITDA		19,316			7,929			52,544			37,049
Add: Amortization of commodity derivative options		7,357			8,070			14,627			16,048
Distributions from unconsolidated affiliates		7,099			6,254			13,572			12,991
Loss on refinancing of unsecured debt		18,233			—			18,233			—
Equity-based compensation		4,109			2,686			7,091			5,401
Equity in (earnings) loss from unconsolidated affiliates		(1,306	)		23,632			(3,008	)		21,837
Unrealized loss (gain) from commodity risk management activities		180			(694	)		(363	)		(240	)
Other non-cash operating items		(572	)		701			(848	)		2,228
Adjusted EBITDA		54,416			48,578			101,848			95,314
Less: Interest expense		(10,988	)		(13,344	)		(22,594	)		(27,315	)
Current income tax expense and other		(293	)		(119	)		(624	)		(599	)
Maintenance capital expenditures		(5,555	)		(1,649	)		(7,601	)		(3,080	)
Total distributable cash flow	$	37,580		$	33,466		$	71,029		$	64,320

How We Manage Our Operations

Our management team uses a variety of tools to manage our business. These tools include: (i) our economic models and standardized processing margin, (ii) flow and transaction monitoring systems, (iii) producer activity evaluation and reporting and (iv) imbalance monitoring and control. For a further discussion, please read “— How We Manage Our Operations” under Item 7 of our 2010 10-K.

Our Contracts

We seek to execute contracts with producers and shippers that provide us with stable cash flows even in adverse natural gas and NGL pricing environments. Our existing contract mix reflects pricing terms (including fee-based,

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percentage-of-proceeds, percentage-of-index and keep-whole) with varying levels of commodity price sensitivity. Our focus in executing new contracts is on increasing our fee-based revenues, which we believe will contribute to the stability of our cash flow.

In addition to compensating us for gathering, transportation, processing or fractionation services, many of our contracts also allow us to charge fees for treating, compression, dehydration, nitrogen rejection or other services. Additionally, to the extent our contract entitles us to keep extracted NGLs, we may share a fixed or variable portion of our processing margin with the producer or third-party transporter in the form of “processing upgrade” payments during periods in which processing margins exceed an agreed-upon amount.

Generally, non-fee-based pricing terms carry varying levels of commodity sensitivity, while fee-based pricing is only indirectly affected by commodity prices. Substantially all of our Rocky Mountains contracts are fee-based arrangements. Our contracts in Texas and Oklahoma often reflect a combination of pricing terms. An example of combined pricing terms would be a percentage-of-proceeds contract that also allows us to charge a treating fee for removing contaminants from natural gas.

The table below summarizes our gross margin attributable to each of the most common pricing terms in our contract portfolio, as a percentage of our quarterly total segment gross margin and our share of the gross margin from each of our unconsolidated affiliates.

Contract Pricing	Q1 2010			Q2 2010			Q3 2010			Q4 2010			Q1 2011			Q2 2011
Fee-based		27	%		33	%		37	%		38	%		41	%		41	%
Percentage-of-proceeds(1)		39	%		31	%		30	%		32	%		32	%		33	%
Keep-whole and other(2)		36	%		33	%		29	%		34	%		39	%		40	%
Net hedging(3)		(2	)%		3	%		4	%		(4	)%		(12	)%		(14	)%

(1)	Gross margin attributable to percentage-of-proceeds contract terms increases as commodity prices increase.
(2)	Gross margin attributable to keep-whole pricing terms increases if NGL prices increase relative to natural gas prices, and decreases if NGL prices decline relative to natural gas prices.
(3)	Net impact of our commodity derivative instruments to total segment gross margin.

For a further discussion, please read “— Our Contracts” in Item 7 of our 2010 10-K.

Forward-Looking Statements

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

•  the volatility of prices and market demand for natural gas, crude oil and NGLs, and for products derived from these commodities;

•  our ability to continue to connect new sources of natural gas supply and the NGL content of new supplies;

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

•  our ability to attract and retain key customers and contract with new customers;

•  our ability to access or construct new gas processing, NGL fractionation and transportation capacity;

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

•  our ability to meet in-service dates and cost expectations for construction projects;

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

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

•  the effectiveness of our hedging program;

•  general economic conditions;

•  force majeure situations such as the loss of a market or facility downtime;

•  the effects of government regulations and policies; and

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

Cautionary statements identifying important factors that could cause actual results to differ materially from our expectations are set forth in this report, including in conjunction with the forward-looking statements referred to above. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth under Item 1A, “Risk Factors” in our 2010 10-K. 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. Forward-looking statements speak only as of the date made, and we undertake no obligation to publicly update or revise any forward-looking statements, other than as required by law, whether as a result of new information, future events or otherwise.

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Our Results of Operations

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2011			2010			2011			2010
				($ In thousands)
Total segment gross margin(1)	$	65,296		$	56,835		$	125,642		$	107,960
Operations and maintenance expenses		15,763			13,230			30,862			25,333
Depreciation and amortization		17,363			15,583			34,232			30,784
General and administrative expenses		11,901			10,900			24,499			21,442
Taxes other than income		1,397			1,181			2,527			2,343
Equity in (earnings) from unconsolidated affiliates(2)(3)(4)		(1,306	)		23,632			(3,008	)		21,837
Operating income (loss)		20,178			(7,691	)		36,530			6,221
Loss on retirement of unsecured debt		(18,233	)		—			(18,233	)		—
Interest and other financing costs, net		(11,446	)		(13,314	)		(23,355	)		(28,252	)
Provision for income taxes		140			(106	)		(771	)		(340	)
Net loss		(9,361	)		(21,111	)		(5,829	)		(22,371	)
Preferred unit distributions		(8,076	)		—			(15,956	)		—
Net loss to common units	$	(17,437	)	$	(21,111	)	$	(21,785	)	$	(22,371	)
Total segment gross margin:
Texas	$	46,134		$	31,751		$	91,145		$	58,916
Oklahoma		28,665			21,821			51,747			46,096
Rocky Mountains(5)		771			1,148			1,813			2,251
Segment gross margin		75,570			54,720			144,705			107,263
Corporate and other(6)		(10,274	)		2,115			(19,063	)		697
Total segment gross margin(1)	$	65,296		$	56,835		$	125,642		$	107,960
Segment gross margin per unit:
Texas:
Service throughput ($/MMBtu)	$	0.76		$	0.62		$	0.76		$	0.57
Oklahoma:
Service throughput ($/MMBtu)	$	1.11		$	0.92		$	1.03		$	1.00
Volumes:
Texas:(7)
Service throughput (MMBtu/d)(8)		665,040			559,876			660,741			571,358
Pipeline throughput (MMBtu/d)		444,186			327,839			422,429			322,423
Plant inlet volumes (MMBtu/d)		588,533			469,019			574,794			463,158
NGLs produced (Bbls/d)		26,913			18,382			25,080			16,869
Oklahoma:(9)
Service throughput (MMBtu/d)(8)		283,870			259,972			280,293			254,386
Plant inlet volumes (MMBtu/d)		157,424			156,204			156,856			154,208
NGLs produced (Bbls/d)		17,331			16,653			17,067			15,994
Capital Expenditures:
Maintenance capital expenditures	$	5,555		$	1,649		$	7,601		$	3,080
Expansion capital expenditures		69,382			51,536			120,901			71,942
Total capital expenditures	$	74,937		$	53,185		$	128,502		$	75,022
Operations and maintenance expenses:
Texas	$	8,908		$	7,497		$	17,733		$	14,066
Oklahoma		6,794			5,670			13,013			11,103
Rocky Mountains		61			63			116			164
Total operations and maintenance expenses	$	15,763		$	13,230		$	30,862		$	25,333

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(1)	Total segment gross margin is a non-GAAP financial measure. Please read “— How We Evaluate Our Operations” for a reconciliation of total segment gross margin to its most directly comparable GAAP measure of operating income.
(2)	Includes results and volumes associated with our interests in Bighorn and Fort Union. Combined volumes gathered by Bighorn and Fort Union were 533,329 MMBtu/d and 900,047 MMBtu/d for the three months ended June 30, 2011 and 2010, respectively. Combined volumes gathered by Bighorn and Fort Union were 557,059 MMBtu/d and 915,596 MMBtu/d for the six months ended June 30, 2011 and 2010, respectively. The volume decline is primarily due to certain Fort Union shippers diverting gas volumes to TransCanada’s Bison Pipeline upon its start up in January 2011. However, Fort Union also received payments based on an additional 327,894 MMBtu/d and 308,566 MMBtu/d in long-term contractually committed volumes for the three and six months ended June 30, 2011.
(3)	Includes results and volumes associated with our interest in Southern Dome. For the three months ended June 30, 2011, plant inlet volumes for Southern Dome averaged 11,730 MMBtu/d and NGLs produced averaged 432 Bbls/d. For the three months ended June 30, 2010, plant inlet volumes for Southern Dome averaged 12,689 MMBtu/d and NGLs produced averaged 456 Bbls/d. For the six months ended June 30, 2011, plant inlet volumes for Southern Dome averaged 11,457 MMBtu/d and NGLs produced averaged 413 Bbls/d. For the six months ended June 30, 2010, plant inlet volumes for Southern Dome averaged 13,406 MMBtu/d and NGLs produced averaged 477 Bbls/d.
(4)	Includes results and volumes associated with our interest in Webb Duval. Gross volumes transported by Webb Duval, net of intercompany volumes, were 48,045 MMBtu/d and 54,747 MMBtu/d for the three months ended June 30, 2011 and 2010, respectively. Gross volumes transported by Webb Duval, net of intercompany volumes, were 48,744 MMBtu/d and 57,405 MMBtu/d for the six months ended June 30, 2011 and 2010, respectively.
(5)	Rocky Mountains segment gross margin includes results from producer services, including volumes purchased for resale, volumes gathered under firm capacity gathering agreements with Fort Union, volumes transported using our firm capacity agreements with Wyoming Interstate Gas Company and compressor rental services provided to Bighorn. Excludes results and volumes associated with our interest in Bighorn and Fort Union.
(6)	Corporate and other includes results attributable to our commodity risk management activities.
(7)	Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Texas segment at all plants, including plants owned by the Texas segment and plants owned by third parties. Plant inlet volumes averaged 572,486 MMBtu/d and NGLs produced averaged 25,889 Bbls/d for the three months ended June 30, 2011 for plants owned by the Texas segment. Plant inlet volumes averaged 461,880 MMBtu/d and NGLs produced averaged 17,864 Bbls/d for the three months ended June 30, 2010 for plants owned by the Texas segment. Plant inlet volumes averaged 557,900 MMBtu/d and NGLs produced averaged 24,016 Bbls/d for the six months ended June 30, 2011 for plants owned by the Texas segment. Plant inlet volumes averaged 456,180 MMBtu/d and NGLs produced averaged 16,366 Bbls/d for the six months ended June 30, 2010 for plants owned by the Texas segment.
(8)	“Service throughput” means the volume of natural gas delivered to our wholly owned processing plants by third-party pipelines plus our “pipeline throughput,” which is the volume of natural gas transported or gathered through our pipelines.
(9)	Plant inlet volumes and NGLs produced represent total volumes processed and produced by the Oklahoma segment at all plants, including plants owned by the Oklahoma segment and plants owned by third parties. For the three months ended June 30, 2011, plant inlet volumes averaged 134,315 MMBtu/d and NGLs produced averaged 15,298 Bbls/d for plants owned by the Oklahoma segment. For the three months ended June 30, 2010, plant inlet volumes averaged 119,030 MMBtu/d and NGLs produced averaged 13,289 Bbls/d for plants owned by the Oklahoma segment. For the six months ended June 30, 2011, plant inlet volumes averaged 128,797 MMBtu/d and NGLs produced averaged 14,625 Bbls/d for plants owned by the Oklahoma segment. For the six months ended June 30, 2010, plant inlet volumes averaged 118,320 MMBtu/d and NGLs produced averaged 12,881 Bbls/d for plants owned by the Oklahoma segment.

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Three Months Ended June 30, 2011 Compared To Three Months Ended June 30, 2010

Net loss, which is prior to deducting in-kind distributions on our Series A preferred units issued in July 2010, was $9.4 million for the three months ended June 30, 2011 compared to net loss of $21.1 million for the three months ended June 30, 2010. The reduced loss resulted primarily from (i) higher total segment gross margin related to increased service throughput and NGL production in Texas and Oklahoma and NGL price increases in both segments, (ii) lower interest expense associated with our outstanding debt and (iii) increased equity earnings from our unconsolidated affiliates as a result of a $25.0 million impairment that was recorded in the second quarter of 2010, partially offset by (i) an $18.2 million loss on the tender and redemption of our 8.125% senior unsecured notes due 2016 and (ii) increased operating and general and administrative costs.

Net loss to common units after deducting $8.1 million of in-kind distributions on our Series A preferred units totaled $17.4 million, or $0.26 per unit on a diluted basis, for the three months ended June 30, 2011 compared to net loss to common units of $21.1 million, or $0.32 per unit on a diluted basis, for the three months ended June 30, 2010. Weighted average diluted units outstanding totaled 66.1 million for the three months ended June 30, 2011 as compared to 65.5 million for the same period in 2010.

Texas Segment Gross Margin.  Texas segment gross margin was $46.1 million for the three months ended June 30, 2011 compared to $31.8 million for the three months ended June 30, 2010, an increase of $14.3 million, or 45%, reflecting 36% higher NGL prices, a $3.5 million increase in revenues from our Houston Central complex fractionation facilities (started in May 2010), which reduced our third-party fractionation costs and enabled us to begin earning fees for providing fractionation services, and an increase in revenue associated with fee-based contracts, including $2.2 million in deficiency fees payable on volumes not delivered. Texas segment gross margin per unit of service throughput increased $0.14 per MMBtu to $0.76 per MMBtu for the three months ended June 30, 2011 compared to $0.62 per MMBtu for the three months ended June 30, 2010. The Texas segment gross margin also benefited from increases in gathering, NGL production and processed volumes of 35%, 46% and 25%, respectively, during the three months ended June 30, 2011 as compared to the three months ended June 30, 2010. Natural gas throughput increased primarily from volumes in the Eagle Ford Shale and north Barnett Shale Combo plays, and increased NGL production reflects additional volumes at our Houston Central complex and Saint Jo plant in the north Barnett Shale Combo play.

Oklahoma Segment Gross Margin.  Oklahoma segment gross margin was $28.7 million for the three months ended June 30, 2011 compared to $21.8 million for the three months ended June 30, 2010, an increase of $6.9 million, or 32%. The increase in segment gross margin was primarily due to a period-over-period increase in average natural gas and NGL prices of 7% and 38%, respectively. The segment gross margin also benefited from the April 1, 2011 acquisition of the Harrah plant which added an additional $1.5 million of gross margin in the three months ended June 30, 2011, from increases in service throughput of 9% due to volume growth from the Woodford Shale, NGL production of 4% and total plant inlet volumes of 1%. The Oklahoma segment gross margin per unit of service throughput increased $0.19 per MMBtu, to $1.11 per MMBtu for the three months ended June 30, 2011 compared to $0.92 per MMBtu for the three months ended June 30, 2010.

Rocky Mountains Segment Gross Margin.  Rocky Mountains segment gross margin was $0.8 million for the three months ended June 30, 2011 compared to $1.1 million for the three months ended June 30, 2010, a decrease of $0.3 million, or 27%. This decrease is primarily the result of increased demand fees we paid under our existing firm gathering agreements with Fort Union. As a result of production declines in the area, we were unable to resell part of our firm capacity on Fort Union to third parties.

Corporate and Other.  Corporate and other includes our commodity risk management activities and was a loss of $10.3 million for the three months ended June 30, 2011 compared to a gain of $2.1 million for the three months ended June 30, 2010. The loss for the three months ended June 30, 2011 included $7.4 million of non-cash amortization expense relating to the option component of our commodity derivative instruments, $2.7 million of net cash settlements paid on expired commodity derivative instruments and $0.2 million of unrealized loss on our commodity derivative instruments. The gain for the three months ended June 30, 2010 included $9.5 million of net cash settlements received on expired commodity derivative instruments and $0.7 million of unrealized mark-to-market gains on our commodity derivative instruments partially offset by $8.1 million of non-cash amortization expense relating to the option component of our commodity derivative instruments.

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Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $15.8 million for the three months ended June 30, 2011 compared to $13.2 million for the three months ended June 30, 2010. The 20% increase is attributable primarily to (i) increased payroll, lease rentals, fuel, utilities and supplies expenses in our Oklahoma segment of $1.1 million, including expenses for the operations of the Harrah plant acquired in April 2011 and (ii) increased payroll, utilities, chemicals and repair and maintenance expenses in our Texas segment of $1.4 million, including for expanded operations related to new Eagle Ford Shale assets.

Depreciation and, Amortization.  Depreciation and amortization totaled $17.4 million for the three months ended June 30, 2011 compared with $15.6 million for the three months ended June 30, 2010, an increase of 12%. This increase relates primarily to additional depreciation and amortization resulting from capital expenditures made after June 30, 2010, including expenditures relating to the fractionation facilities at our Houston Central complex, the expansion of our Saint Jo plant, the construction of our DK pipeline and the acquisition of the Harrah plant.

General and Administrative Expenses.  General and administrative expenses totaled $11.9 million for the three months ended June 30, 2011 compared to $10.9 million for the three months ended June 30, 2010. The 9% increase consists primarily of (i) increases in personnel, compensation and benefits costs of $0.8 million, (ii) an increase of $1.0 million in non-cash compensation expense related to amortization of the fair value of restricted units, phantom units, unit options and unit appreciation rights issued under our LTIP, partially offset by (i) a reduction in costs of preparing and processing tax forms (Schedule K-1s) for unitholders of $0.2 million, (ii) a reduction in professional services expense of $0.3 million and (iii) a $0.3 million increase in management fees received from our unconsolidated affiliates, primarily Eagle Ford Gathering.

Interest and Other Financing Costs.  Interest and other financing costs totaled $11.5 million for the three months ended June 30, 2011 compared to $13.4 million for the three months ended June 30, 2010, a decrease of $1.9 million, or 14%. The decrease in interest and other financing costs resulted from (i) a reduction in interest expense on our revolving credit facility and senior notes of $0.5 million and (ii) $1.9 million of additional capitalized interest costs related to the construction of expansion capital projects, partially offset by a (i) $0.4 million decrease in unrealized mark-to-market gains on undesignated interest rate swaps and (ii) a $0.1 million increase in the amortization of debt issue costs. Average borrowings under our credit arrangements for the three months ended June 30, 2011 and 2010 were $773.0 million and $731.4 million, respectively, with average interest rates of 7.4% and 8.1%, respectively. Please read “— Liquidity and Capital Resources — Our Indebtedness.”

Six Months Ended June 30, 2011 Compared To Six Months Ended June 30, 2010

Net loss, which is prior to deducting in-kind distributions on our Series A preferred units issued in July 2010, was $5.8 million for the six months ended June 30, 2011 compared to a net loss of $22.4 million for the six months ended June 30, 2010. The reduced loss resulted primarily from (i) higher total segment gross margin related to increased service throughput in Texas and Oklahoma and NGL price increases in both segments (ii) increased equity earnings from our unconsolidated affiliates as a result of a $25.0 million impairment that was recorded in the second quarter of 2010 and (iii) lower interest expense associated with our outstanding debt, partially offset by an (i) $18.2 million loss on the tender and redemption of our 8.125% senior unsecured notes due 2016 and (ii) increased operating and general and administrative costs.

Net loss to common units after deducting $16.0 million of in-kind distributions on our Series A preferred units totaled $21.8 million, or $0.33 per unit on a diluted basis, for the six months ended June 30, 2011 compared to net loss to common units of $22.4 million, or $0.36 per unit on a diluted basis, for the six months ended June 30, 2010. Weighted average diluted units outstanding totaled 66.1 million for the six months ended June 30, 2011 as compared to 61.9 million for the same period in 2010.

Texas Segment Gross Margin.  Texas segment gross margin was $91.1 million for the six months ended June 30, 2011 compared to $58.9 million for the six months ended June 30, 2010, an increase of $32.2 million, or 55%, reflecting 22% higher NGL prices, an $8.0 million increase in revenues from our Houston Central complex fractionation facilities (started in May 2010), which reduced our third-party fractionation costs and enabled us to begin earning fees for providing fractionation services, and an increase in revenue associated with fee-based contracts, including $5.2 million in deficiency fees payable on volumes not delivered. Texas segment gross margin per unit of service throughput increased $0.19 per MMBtu to $0.76 per MMBtu for the six months ended June 30,

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2011 compared to $0.57 per MMBtu for the six months ended June 30, 2010. The Texas segment gross margin also benefited from increases in gathering, NGL production and processed volumes of 31%, 49% and 24%, respectively, during the six months ended June 30, 2011 compared to the six months ended June 30, 2010. Natural gas throughput increased primarily from volumes in the Eagle Ford Shale and north Barnett Shale Combo plays, and increased NGL production reflects additional volumes at our Houston Central complex and Saint Jo plant in the north Barnett Shale Combo play.

Oklahoma Segment Gross Margin.  Oklahoma segment gross margin was $51.7 million for the six months ended June 30, 2011 compared to $46.1 million for the six months ended June 30, 2010, an increase of $5.6 million, or 12%. The increase in segment gross margin was primarily due to a period-over-period increase in NGL prices of 20% offset by a decrease in average natural gas prices of 11%. The segment gross margin also benefited from the April 1, 2011 acquisition of the Harrah plant which added an additional $1.5 million of gross margin in the six months ended June 30, 2011 and from increases in service throughput of 10% due to volume growth from the Woodford Shale, NGL production of 7% and total plant inlet volumes of 2%. The Oklahoma segment gross margin per unit of service throughput increased $0.03 per MMBtu to $1.03 per MMBtu for the six months ended June 30, 2011 compared to $1.00 per MMBtu for the six months ended June 30, 2010.

Rocky Mountains Segment Gross Margin.  Rocky Mountains segment gross margin was $1.8 million for the six months ended June 30, 2011 compared to $2.3 million for the six months ended June 30, 2010, a decrease of $0.5 million, or 22%. This decrease is primarily the result of increased demand fees we paid under our existing firm gathering agreements with Fort Union. As a result of production declines in the area, we were unable to resell part of our firm capacity on Fort Union to third parties.

Corporate and Other.  Corporate and other includes our commodity risk management activities and was a loss of $19.1 million for the six months ended June 30, 2011 compared to a gain of $0.7 million for the six months ended June 30, 2010. The loss for the six months ended June 30, 2011 included $14.6 million of non-cash amortization expense relating to the option component of our commodity derivative instruments and $4.8 million of net cash settlements paid on expired commodity derivative instruments offset by $0.3 million of unrealized gain on our commodity derivative instruments. The gain for the six months ended June 30, 2010 included $16.5 million of net cash settlements received on expired commodity derivative instruments and $0.2 million of unrealized mark-to-market gains on our commodity derivative instruments partially offset by $16.0 million of non-cash amortization expense relating to the option component of our commodity derivative instruments.

Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $30.9 million for the six months ended June 30, 2011 compared to $25.3 million for the six months ended June 30, 2010. The 22% increase is attributable primarily to (i) increased payroll, lease rentals, fuel, utilities and supplies expenses in our Oklahoma segment of $1.9 million, including expenses for the operations of the Burbank and Harrah plants acquired in April 2010 and April 2011, respectively, and (ii) increased payroll, utilities, chemicals and repair and maintenance expenses in our Texas segment of $3.7 million, including for expanded operations related to new Eagle Ford Shale assets.

Depreciation and, Amortization.  Depreciation and amortization totaled $34.2 million for the six months ended June 30, 2011 compared with $30.8 million for the six months ended June 30, 2010, an increase of 11%. This increase relates primarily to additional depreciation and amortization resulting from capital expenditures made after June 30, 2010, including expenditures relating to the fractionation facility at our Houston Central complex, the expansion of our Saint Jo plant, installation of the Burbank plant, the construction of our DK pipeline and the acquisition of the Harrah plant.

General and Administrative Expenses.  General and administrative expenses totaled $24.5 million for the six months ended June 30, 2011 compared to $21.4 million for the six months ended June 30, 2010. The 14% increase consists primarily of (i) increases in personnel, compensation and benefits costs of $1.6 million, (ii) an increase of $1.2 million in non-cash compensation expense related to amortization of the fair value of restricted units, phantom units, unit options and unit appreciation rights issued under our LTIP, (iii) costs of preparing and processing tax forms (Schedule K-1s) for unitholders of $0.3 million, (iv) expenses for acquisition initiatives that were not consummated totaling $0.6 million and (iv) a $0.3 million loss on the sale of non-core assets in our Texas segment,

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offset by (i) a $0.5 million increase in management fees received from our unconsolidated affiliates, primarily Eagle Ford Gathering and (ii) a reduction in professional services expense of $0.4 million.

Interest and Other Financing Costs.  Interest and other financing costs totaled $23.4 million for the six months ended June 30, 2011 compared to $28.3 million for the six months ended June 30, 2010, a decrease of $4.9 million, or 17%. The decrease in interest and other financing costs resulted from (i) a reduction in interest expense on our revolving credit facility and senior notes of $2.0 million, (ii) $2.7 million of additional capitalized interest costs related to the construction of expansion capital projects and (iii) a $0.4 million increase in unrealized mark-to-market gains on undesignated interest rate swaps, offset by a $0.2 million increase in the amortization of debt issue costs. Average borrowings under our credit arrangements for the six months ended June 30, 2011 and 2010 were $699.1 million and $777.1 million, respectively, with average interest rates of 8.0% and 7.7%, respectively. Please read “— Liquidity and Capital Resources — Our Indebtedness.”

Cash Flows

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

	Six Months Ended
	June 30,
	2011			2010
	(In thousands)
Net cash provided by operating activities	$	76,006		$	65,414
Net cash used in investing activities		(182,329	)		(59,120	)
Net cash provided by financing activities		107,949			5,816

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

Operating Cash Flows.  Net cash provided by operating activities was $76.0 million for the six months ended June 30, 2011 compared to $65.4 million for the six months ended June 30, 2010. The increase in cash provided by operating activities of $10.6 million was attributable to the following changes:

•  a $7.9 million increase in cash flow provided by operating activities for the six months ended June 30, 2011 compared with the same period in 2010;

•  a $1.3 million increase in cash distributions received from our unconsolidated affiliates in six months ended June 30, 2011 compared to the six months ended June 30, 2010; and

•  a $1.9 million decrease in interest payments for the six months ended June 30, 2011 compared to the same period in 2010 as a result of lower average borrowings;

partially offset by:

•  a $0.5 million increase in cash flow used for risk management activities for the six months ended June 30, 2011 as compared to the six months ended June 30, 2010.

Investing Cash Flows.  Net cash used in investing activities was $182.3 million and $59.1 million for the six months ended June 30, 2011 and 2010, respectively. Investing activities for the six months ended June 30, 2011 included (i) $118.5 million of capital expenditures related to our Eagle Ford Shale growth strategy, the acquisition of the Harrah plant in Oklahoma and well connections attaching volumes in new areas (please read “— Liquidity and Capital Resources — Capital Expenditures” for additional details) and (ii) $65.0 million of investments in Eagle Ford Gathering, Liberty Pipeline Group, Webb Duval and Bighorn, offset by $1.2 million of distributions from Bighorn in excess of equity earnings. Investing activities for the second quarter of 2010 included (i) $60.4 million of capital expenditures related to the construction of the gathering lines upstream of our Saint Jo plant, rights-of-way acquisition and construction of the DK pipeline in south Texas, as well as constructing well interconnects to attach volumes in new areas, and (ii) $1.5 million of investments in Bighorn and Fort Union offset

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by (i) $2.0 million of distributions from Bighorn and Southern Dome in excess of equity earnings and (ii) other investing activities of $0.8 million.

Financing Cash Flows.  Net cash provided by financing activities totaled $107.9 million during the six months ended June 30, 2011 and included (i) net borrowings under our revolving credit facility of $185.0 million, (ii) issuance of our senior unsecured notes due 2021 of $360.0 million and (iii) proceeds from the exercise of common unit options of $2.4 million, offset by (i) distributions to our unitholders of $76.6 million, (ii) tender and redemption of our senior unsecured notes due 2016 of $332.6 million, (iii) bond tender and consent premiums of $14.6 million and (iv) deferred financing costs of $15.7 million. Net cash provided by financing activities totaled $5.8 million during the six months ended June 30, 2010 and included (i) net proceeds from our public offering of common units in 2010 (including units issued upon the underwriters’ exercise of their option to purchase additional units) of $164.2 million and (ii) proceeds from the exercise of unit options of $1.0 million offset by (i) net repayments under our revolving credit facility of $90.0 million and (ii) distributions to our unitholders of $69.4 million.

Liquidity and Capital Resources

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

For additional discussion, please read “— Our Long-Term Growth Strategy” under Item 7 of our 2010 10-K.

Outlook.  Recent commodity prices and financial market conditions have supported significant opportunities for volume growth from shale resource plays but drilling activity around our assets in the Powder River Basin and in areas where producers employ conventional drilling techniques has been minimal. It remains unclear when producers in these areas will undertake sustained increases in drilling activity. Our ability to generate cash from operations, and to comply with the covenants under our debt instruments would be adversely affected if we experienced declining volumes in combination with unfavorable commodity prices over a sustained period.

We purchase commodity derivatives during favorable pricing environments so that the cash from their settlements will help to offset the effects of unfavorable pricing environments in the future. We purchased new commodity derivatives in late 2010 and the first quarter of 2011 to hedge against potential future declines in commodity prices. Some of our derivative instruments for 2010 had strike prices based on the 2008 pricing environment, which were substantially higher than those of instruments we acquired in 2009 and 2010, as well as the strike prices for instruments we could acquire today. We have settled most of our derivatives with 2008 strike prices, so to the extent we rely on derivative instruments to offset unfavorable pricing in 2011, our cash from settlements of derivative instruments will be lower than in 2010.

We believe that our cash from operations, cash on hand and our amended and restated revolving credit facility will provide sufficient liquidity to meet our short-term capital requirements and to fund our committed capital expenditures for at least the next 12 months. If our plans change or our assumptions prove inaccurate, or if we make further acquisitions, we may need to raise additional capital.

Acquisitions and organic expansion have been, and our management believes will continue to be, key elements of our business strategy. In addition, we continue to consider opportunities for strategic greenfield projects. We intend to finance growth projects primarily through the issuance of debt and equity. Generally, we believe that over the long term, our cost of equity capital relative to master limited partnerships, or MLPs, of similar size will be favorable because, unlike many of our competitors that are MLPs, neither our management nor any other party

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holds incentive distribution rights that entitle them to increasing percentages of cash distributions as per-unit cash distributions increase.

The timing, size or success of any acquisition or expansion effort and the associated potential capital commitments are unpredictable. To consummate larger acquisitions or capital projects, we will require access to additional capital on competitive terms. Our access to capital over the longer term will depend on our future operating performance, financial condition and credit rating and, more broadly, on the availability of equity and debt financing, which will be affected by prevailing conditions in our industry, the economy and the financial markets, and other financial and business factors, many of which are beyond our control.

Capital Expenditures.  The natural gas gathering, transportation 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 made to replace partially or fully depreciated assets to maintain the existing operating capacity of our assets and to extend their useful lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and

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

During the six months ended June 30, 2011, our capital expenditures totaled $128.5 million, consisting of $7.6 million of maintenance capital and $120.9 million of expansion capital. We used funds from operations and borrowings under our amended and restated revolving credit facility to fund our capital expenditures. Our expansion capital expenditures related mainly to (i) the fractionation expansion at our Houston Central complex, (ii) extension of our DK pipeline to the Houston Central complex, (iii) our acquisition of the Harrah plant and (iv) construction of lateral pipelines and well connections to attach volumes from the Eagle Ford Shale and the north Barnett Shale Combo plays. We anticipate incurring approximately an additional $170 million in expansion capital expenditures in 2011 enhancing the capabilities and capacities of our current asset base. Based on our current scope of operations, we anticipate incurring approximately $14 million to $16 million of maintenance capital expenditures over the next 12 months.

On April 1, 2011, we purchased the Harrah plant, a 38,000 Mcf/d natural gas processing plant, and other related gathering and processing facilities in Oklahoma County, Oklahoma, for $16.1 million, funded with cash on hand. Our Oklahoma segment historically delivered natural gas to the Harrah plant for processing. This acquisition enables us to increase our margin on gas processed at the Harrah plant and provides us with additional cryogenic processing capacity.

Investment in Unconsolidated Affiliates.  During six months ended June 30, 2011, our capital contributions to our unconsolidated affiliates totaled $65.1 million and consisted primarily of contributions to Eagle Ford Gathering for its construction of gathering pipelines and the related crossover project and Liberty Pipeline Group for construction of its NGL pipeline. We anticipate making additional cash contributions to Eagle Ford Gathering of approximately $27 million and $48 million for its initial pipeline project and its crossover project, respectively, and additional cash contributions to Liberty Pipeline Group of approximately $14 million for its NGL pipeline project.

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Eagle Ford Shale Growth Strategy.  We have undertaken various expansion capital projects in Texas to accomplish our Eagle Ford Shale growth strategy. The table below provides summary descriptions of our major projects under this strategy.

Major Eagle Ford Growth Projects
	Length		Diameter		Initial		Expanded		Estimated Costs
Project	(miles)		(range)		Capacity(1)		Capacity(1)		($ in millions)			Expected In-Service Date
Houston Central fractionation expansion		—		—		22,000		44,000	$	66		Fourth Quarter 2011
Houston Central processing expansion		—		—		400,000		—	$	145		First Quarter 2013
DK pipeline extension		58		24”		195,000		303,000	$	100		Fourth Quarter 2011
Eagle Ford Gathering(2)
Initial pipeline		117		24”- 30”		325,000		—	$	175(4	)	Third Quarter 2011
Crossover project		66		20”- 24”		176,000		—	$	100(4	)	Fourth Quarter 2011
Interconnect to Markham plant		7		20”		200,000		—	$	27(4	)	Fourth Quarter 2011
Liberty NGL pipeline(3)		83		12”		75,000		—	$	65(4	)	Third Quarter 2011

(1)	Throughput or processing capacity is presented in Mcf/d. Fractionation capacity is presented in Bbls/d.
(2)	Constructed through Eagle Ford Gathering.
(3)	Constructed through Liberty Pipeline Group. Revised estimate as of August 2, 2011, reflecting increased right-of-way costs and costs for additional equipment and pipeline re-routing.
(4)	Joint venture project costs presented are gross amounts; our share of such costs is 50%.

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

	One Quarter		Four Quarters
Common units(1)	$	38,687	$	154,748

(1) Includes distributions on restricted common units and phantom units issued under our Long-Term Incentive Plan (“LTIP”). Distributions made on restricted units and phantom units issued to date are subject to the same vesting provisions as the restricted units and phantom units. As of August 1, 2011, we had 59,272 outstanding restricted units and 992,957 outstanding phantom units.

Our Indebtedness

As of June 30, 2011, our aggregate outstanding indebtedness totaled $804.5 million and we were in compliance with the financial covenants under our revolving credit facility and our incurrence covenants under the indentures governing our senior notes.

Credit Ratings.  Moody’s Investors Service has assigned a Corporate Family rating of Ba3 with a negative outlook, a B1 rating for our senior unsecured 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 stable outlook and a B+ rating for our senior unsecured notes.

Amended and Restated Revolving Credit Facility.  On June 10, 2011, we entered into a second amended and restated credit agreement with Bank of America, N.A., as Administrative Agent, which increased our $550 million senior secured revolving credit facility to $700 million. The significant changes to the amended credit facility include:

•  The maturity date is extended from October 18, 2012 to June 10, 2016.

•  Interest is determined, at our election, by reference to (a) the British Bankers Association LIBOR rate, or LIBOR, plus an applicable rate between 2.0% and 3.25% per annum or (b) the highest of (1) the federal funds rate plus 0.50%, (2) the prime rate and (3) LIBOR plus 1.0%, plus, in each case, an applicable rate between 1.0% and 2.25% per annum. The applicable rates vary depending on our consolidated leverage ratio (as defined in the amended credit agreement).

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•  The quarterly commitment fee on the unused amount of the revolving credit facility is determined by reference to an applicable rate between 0.375% and 0.5% per annum. The applicable rate varies depending on our consolidated leverage ratio (as defined in the amended credit agreement).

•  A sublimit of up to $100 million is available for letters of credit and a sublimit of up to $75 million is available for swing line loans.

As of June 30, 2011, we had $195.0 million outstanding under the revolving credit facility and we had no letters of credit outstanding. We have not experienced any difficulties in obtaining funding from any of our lenders, but the lack of or delay in funding by one or more members of our banking group could negatively affect our liquidity position. Future borrowings under our revolving credit facility are available for acquisitions, capital expenditures, working capital and general corporate purposes, and the facility may be drawn on and repaid without restriction so long as we are in compliance with its terms, including the financial covenants described below.

•  The maximum consolidated leverage ratio (total debt to Consolidated EBITDA as defined in the amended credit agreement) permitted under the agreement is 5.25 to 1.0. Subject to conditions and limitations described in the amended credit agreement, up to 15% of our Consolidated EBITDA for purposes of calculating this ratio may consist of projected EBITDA attributable to material capital projects (generally, capital projects expected to exceed $20 million) then under construction, including our net share of projected EBITDA attributable to capital projects pursued by joint ventures in which we own interests (“Material Project EBITDA”). At June 30, 2011, our consolidated leverage ratio was 3.64 to 1.0.

•  The maximum senior secured leverage ratio (total senior secured debt to Consolidated EBITDA as defined in the amended credit agreement) permitted under the agreement is 4.0 to 1.0. Up to 15% of our Consolidated EBITDA for purposes of calculating this ratio may consist of Material Project EBITDA. At June 30, 2011, our senior secured leverage ratio was 0.92 to 1.0.

•  The minimum consolidated interest coverage ratio (Consolidated EBITDA to interest as defined in the amended credit agreement) as of the end of any fiscal quarter may not be less than 2.50 to 1.00. At June 30, 2011, our consolidated interest coverage ratio was 4.05 to 1.00.

Based on our trailing four-quarter Consolidated EBITDA, as defined under the revolving credit facility, at June 30, 2011 we could borrow an additional $360 million before reaching our maximum leverage ratio of 5.25 to 1.0.

Please read “— How We Evaluate Our Operations” for a discussion of Consolidated EBITDA’s similarity to the non-GAAP financial measures used by our management.

Senior Notes.  The indentures governing our senior unsecured notes restrict our ability to pay cash distributions. Before we can pay a distribution to our unitholders, we must demonstrate that our ratio of consolidated cash flow to fixed charges (each as defined in the senior notes indentures) is at least 1.75 to 1.0. At June 30, 2011, our ratio of consolidated cash flow to fixed charges was 3.86 to 1.0.

In April 2011, we issued $360 million in 7.125% senior notes due 2021 and used the proceeds to purchase all of our outstanding 8.125% senior notes due 2016.

For additional details on our indebtedness, please read Note 5, “Long-Term Debt,” to our unaudited consolidated financial statements included in Item 1 of this report.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of June 30, 2011.

Recent Accounting Pronouncements

For information on new accounting pronouncements, please read Note 2, “New Accounting Pronouncements,” to our unaudited consolidated financial statements included in Item 1 of this report.

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Critical Accounting Policies

For a discussion of our critical accounting policies for revenue recognition, impairment of long-lived assets, risk management activity and equity method of accounting for unconsolidated affiliates, which remain unchanged, please read “Management’s Discussion and Analysis of Financial Condition and Results of Operation — Critical Accounting Policies and Estimates” in our 2010 10-K.

Item 3.   Quantitative and Qualitative Disclosures about Market Risk.

Market risk is the risk of loss arising from adverse changes in market rates and prices. We are exposed to market risks, including changes in commodity prices and interest rates. We may use financial instruments such as options, swaps and other derivatives to mitigate the effects of the identified risks. In general, we attempt to hedge risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required 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 can be volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices primarily as a result of: (i) processing at our processing plants or third-party processing plants, (ii) purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and (iii) transporting and fractionating NGLs. To the extent that they influence the level of drilling activity, commodity prices also affect all of our segments indirectly.

Sensitivity.  In order to calculate the sensitivity of our total segment gross margin to commodity price changes, we adjusted our operating models for actual commodity prices, plant recovery rates and volumes. We have calculated that a $0.01 per gallon change in either direction of NGL prices would have resulted in a corresponding change of approximately $0.6 million to our total segment gross margin for the six months ended June 30, 2011. We also calculated that a $0.10 per MMBtu increase in the price of natural gas would have resulted in a $0.1 million decrease to our total segment gross margin, and vice versa, for the six months ended June 30, 2011. These relationships are not necessarily linear. When actual prices fall below the strike prices of our hedges, our sensitivity to further changes in commodity prices is reduced. However, our hedge instruments do not reduce our sensitivity to commodity prices to the extent that commodity prices remain above strike prices. Commodity prices exceeded the strike prices of our hedges in the first six months of 2011; therefore, our hedges did not reduce our sensitivity to changes in commodity prices during that period.

Our Hedge Portfolio

Commodity Hedges.  As of June 30, 2011, our commodity hedge portfolio totaled a net asset of $12.2 million, which consists of assets aggregating $17.5 million less liabilities aggregating $5.3 million. For additional information, please read Note 11, “Risk Management Activities,” to our unaudited consolidated financial statements included in Item 1 of this report.

Houston Ship Channel Index Purchased Natural Gas Options

	Call Spread						Call
	Call Strike				Call
	(Per MMBtu)				Volumes		Strike		Volume
	Bought		Sold		(MMBtu/d)		(Per MMBtu)		(MMBtu/d)
2011	$	6.9500	$	10.0000		7,100	$	10.0000		10,000

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Mont Belvieu Purity Ethane Purchased Puts and Entered into Swaps

	Put				Swap
	Strike		Volumes		Price		Volumes
	(Per gallon)		(Bbls/d)		(Per gallon)		(Bbls/d)
2011	$	0.5300		2,200	$	0.5450		500
2011	$	0.6200		500	$	—		—
2011	$	0.5500		500	$	—		—
2012	$	0.5900		1,000	$	—		—

Mont Belvieu TET Propane Purchased Puts and Entered into Swaps

	Put				Swap
	Strike		Volumes		Price		Volumes
	(Per gallon)		(Bbls/d)		(Per gallon)		(Bbls/d)
2011(1)	$	0.8265		1,100	$	—		—
2011	$	0.9340		700	$	0.9750		700
2011	$	1.3300		900	$	—		—
2012	$	1.1500		700	$	—		—
2012	$	1.0700		600	$	—		—
2012	$	1.1700		600	$	—		—
2012	$	1.3200		400	$	—		—
2013	$	1.2400		600	$	—		—
2013(2)	$	1.2750		350	$	—		—

(1)	Instrument is not designated as a cash flow hedge under hedge accounting.
(2)	Instrument purchased July 2011.

Mont Belvieu Non-TET Isobutane Purchased Puts and Entered into Swaps

	Put				Swap
	Strike		Volumes		Price		Volumes
	(Per gallon)		(Bbls/d)		(Per gallon)		(Bbls/d)
2011(1)	$	1.0205		300	$	—		—
2011(1)	$	1.1100		100	$	1.1800		100
2011	$	1.3900		160	$	—		—
2011	$	1.7100		200	$	—		—
2012	$	1.3900		450	$	—		—
2013	$	1.6000		200	$	—		—
2013	$	1.6800		100	$	—		—

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

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

	Put				Swap
	Strike		Volumes		Price		Volumes
	(Per gallon)		(Bbls/d)		(Per gallon)		(Bbls/d)
2011(1)	$	1.0205		300	$	—		—
2011(1)	$	1.0850		200	$	1.1700		200
2011	$	1.3500		140	$	—		—
2011	$	1.7100		350	$	—		—
2012	$	1.3500		250	$	—		—
2012	$	1.3600		350	$	—		—
2012	$	1.4600		150	$	—		—
2013	$	1.5800		300	$	—		—
2013	$	1.6500		100	$	—		—

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

Mont Belvieu Non-TET Purchased Natural Gasoline Puts

	Put
	Strike		Volumes
	(Per gallon)		(Bbls/d)
2011	$	1.4100		300

Natural Gas Basis Swaps

	Purchased Houston Ship				Sold CenterPoint
	Channel Index				East Index
	Price		Volume		Price		Volume
	(per MMBtu)		(MMBtu/d)		(per MMBtu)		(MMBtu/d)
2011(1)	$	0.1050		10,000	$	0.3050		10,000

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

WTI Crude Oil Purchased Puts

	Put
	Strike		Volumes
	(Per Bbl)		(Bbls/d)
2011(1)	$	55.00		1,000
2011(1)	$	60.00		400
2011	$	77.00		700
2011	$	79.00		400
2011	$	85.00		200
2012	$	79.00		300
2012	$	83.00		650
2012	$	85.00		350
2012	$	90.00		200
2013	$	90.00		400
2013	$	99.00		350

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

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Interest Rate Swaps.  As of June 30, 2011, the fair value of our interest rate swaps liability totaled $5.5 million. For additional information on our interest rate swaps, please read Note 11, “Risk Management Activities,” to our unaudited consolidated financial statements included in Item 1 of the report.

Counterparty Risk

We are diligent in attempting to ensure that we provide credit only to credit-worthy customers. However, our purchase and resale of natural gas exposes us to significant credit risk, as our margin on any sale is generally a very small percentage of the total sale price. Therefore, a credit loss could be very large relative to our overall profitability. For the six months ended June 30, 2011, ONEOK Hydrocarbons, L.P. (19%), Dow Hydrocarbon and Resources LLC, (16%), ONEOK Energy Services, L.P. (12%), Kinder Morgan (7%) and Enterprise Products Operating, L.P. (9%) collectively accounted for approximately 63% of our revenue. As of June 30, 2011, all of these companies, or their parent companies, were rated investment grade by Moody’s Investors Service and Standard & Poor’s Ratings Services. Companies accounting for another approximately 28% of our revenue have an investment grade parent, are themselves investment grade, have provided us with credit support in the form of a letter of credit issued by an investment grade financial institution or have provided prepayment for our services.

We also diligently review the creditworthiness of other counterparties to which we may have credit exposure, including hedge counterparties. Our risk management policy requires that we review and report the credit ratings of our hedging counterparties on a monthly basis. As of June 30, 2011, the value of our commodity net hedge positions by counterparty consisted of assets with Barclays Bank PLC (28%), JP Morgan (23%), Credit Suisse (16%), Scotia Capital (18%) and Wells Fargo (25%), and liabilities owed to Goldman Sachs (10%). As of June 30, 2011, all of our counterparties were rated A2 and A or better by Moody’s Investors Service and Standard & Poor’s Ratings Services, respectively. Our hedge counterparties have not posted collateral to secure their obligations to us.

We have historically experienced minimal collection issues with our counterparties; however, nonpayment or nonperformance by one or more significant counterparties could adversely impact our liquidity.

Item 4.   Controls and Procedures.

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) as of the end of the period covered by this report. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon the evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective at June 30, 2011 at the reasonable assurance level. There has been no change in our internal controls over financial reporting (as defined in Rule 13a-15(f) under the Exchange Act) that occurred during the quarter ended June 30, 2011 that has materially affected or is reasonably likely to materially affect such internal controls over financial reporting.

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PART II — OTHER INFORMATION

Item 1.   Legal Proceedings.

Please read Note 9, “Commitments and Contingencies,” to our unaudited consolidated financial statements included in Part I, Item 1 of this report which is incorporated in this item by reference.

Item 1A.   Risk Factors.

In addition to the factors discussed elsewhere in this report, including the financial statements and related notes, you should consider carefully the risks and uncertainties described under Item 1A, “Risk Factors,” in our 2010 10-K. These risks and uncertainties could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be materially adversely affected.

Federal and state legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs for producers and additional operating restrictions or delays affecting production of natural gas, which could adversely affect us.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the Safe Drinking Water Act’s Underground Injection Control Program and has begun the process of drafting guidance documents on regulating requirements for companies that plan to conduct hydraulic fracturing using diesel. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices, and a number of federal agencies are analyzing a number of environmental issues associated with hydraulic fracturing. The EPA has commenced a study of the potential environmental effects of hydraulic fracturing activities, with initial results expected to be available by late 2012 and final results by 2014. In addition, the U.S. Department of Energy and the U.S. Government Accountability Office are studying different aspects of how hydraulic fracturing might adversely affect the environment, and the U.S. Department of the Interior is considering disclosure requirements or other mandates for hydraulic fracturing on federal land, which, if adopted, would affect our operations on federal lands. A committee of the United States House of Representatives also has conducted an investigation of hydraulic fracturing practices. These studies, depending on their results, could spur initiatives to regulate hydraulic fracturing under the Safe Drinking Water Act or under newly established legislation. In addition, Congress is considering two companion bills, known as the “Fracturing Responsibility and Awareness of Chemicals Act,” or “FRAC Act,” that would repeal an exemption in the Safe Drinking Water Act for the underground injection of hydraulic fracturing fluids other than diesel near drinking water sources and require federal regulation of hydraulic fracturing and require disclosure of the chemicals used in the fracturing process. In addition, some states, including Wyoming and Texas, have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances. For example, Wyoming, where we have natural gas gathering system operations, has adopted legislation requiring drilling operators conducting hydraulic fracturing activities in that state to publicly disclose the chemical used in the hydraulic fracturing process. Moreover, in Texas, a law was recently adopted in June 2011 that requires written disclosure to the Railroad Commission of Texas and the public of specific information about the fluids, proppants and additives used in hydraulic fracturing operations. If new federal or state laws or regulations that significantly restrict hydraulic fracturing are adopted, such legal requirements could reduce demand for our gathering and processing or fractionation services.

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Recently proposed rules regulating air emissions from oil and natural gas operations could cause us as well as natural gas exploration and production operators to incur increased capital expenditures and operating costs as well as cause us to experience reduced demand for our gathering, processing or fractionation services.

On July 28, 2011, the U.S. Environmental Protection Agency (“EPA”) proposed rules that would establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, EPA’s proposed rule package includes New Source Performance Standards (“NSPS”) to address emissions of sulfur dioxide and volatile organic compounds (“VOCs”), and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The EPA’s proposal would require the reduction of VOC emissions from oil and natural gas production facilities by mandating the use of “green completions” for hydraulic fracturing, which requires the operator to recover rather than vent the gas and natural gas liquids that come to the surface during completion of the fracturing process. The proposed rules also would establish specific requirements regarding emissions from compressors, dehydrators, storage tanks and other production equipment. In addition, the rules would establish new leak detection requirements for natural gas processing plants. The EPA will receive public comment and hold hearings regarding the proposed rules and must take final action on them by February 28, 2012. If finalized, these rules could require a number of modifications to our customers’ operations as well as our own operations, including the installation of new equipment. Compliance with such rules could result in significant costs, including increased capital expenditures and operating costs, which may adversely impact our business. Moreover, the impact of such costs and expenditures by our customers could result in reduced exploration and production activity, and in turn, reduced demand for our gathering, processing or fractionation services.

Item 6.   Exhibits.

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

Number			Description
	3	.1	Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.1 to Registration Statement on Form S-1 filed July 30, 2004).
	3	.2	Certificate of Amendment to Certificate of Formation of Copano Energy Holdings, L.L.C. (now Copano Energy, L.L.C.) (incorporated by reference to Exhibit 3.2 to Registration Statement on Form S-1 filed July 30, 2004).
	3	.3	Fourth Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed July 21, 2010).
	3	.4	Amendment No. 1 to Fourth Amended and Restated Limited Liability Company Agreement of Copano Energy, L.L.C. (incorporated by reference to Exhibit 3.1 to Current Report on Form 8-K filed July 22, 2010).
	4	.1	Indenture, dated as of February 7, 2006, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Guarantors party thereto and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed February 8, 2006).
	4	.2	Indenture, dated May 16, 2008, among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed May 19, 2008).
	4	.3	Form of Global Note representing 7.75% Senior Notes due 2018 (included in 144A/Regulation S Appendix to Exhibit 4.1 above).
	4	.4	Registration Rights Agreement, dated July 21, 2010, by and between Copano Energy, L.L.C. and TPG Copenhagen, L.P. (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed July 22, 2010).
	4	.5	Fourth Supplemental Indenture, dated April 5, 2011, to the Indenture, dated February 7, 2006, by and among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Guarantors name therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed April 5, 2011).

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Number			Description
	4	.6	Indenture, dated April 5, 2011, by and among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.2 to Current Report on Form 8-K filed April 5, 2011).
	4	.7	First Supplemental Indenture, dated April 5, 2011, to the Indenture, dated April 5, 2011, by and among Copano Energy, L.L.C., Copano Energy Finance Corporation, the Guarantors named therein and U.S. Bank National Association, as Trustee (incorporated by reference to Exhibit 4.3 to Current Report on Form 8-K filed April 5, 2011).
	4	.8	Form of Global Note representing 7.125% Senior Notes due 2021 (included in Exhibit A to Exhibit 4.5 above).
	10	.1	Second Amended and Restated Credit Agreement dated as of June 10, 2011, among Copano Energy, L.L.C., as the Borrower, the lenders from time to time party thereto, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, JP Morgan Chase Bank, N.A. and Wells Fargo Bank, National Association, as Co-Syndication Agents and BNP Paribas and Royal Bank of Canada, as Co-Documentation Agents (incorporated by reference to Exhibit 4.1 to Current Report on Form 8-K filed June 15, 2011).
	10	.2*	Amended and Restated Copano Energy, L.L.C. Long Term Incentive Plan.
	31	.1*	Sarbanes-Oxley Section 302 certification of Principal Executive Officer.
	31	.2*	Sarbanes-Oxley Section 302 certification of Principal Financial Officer.
	32	.1**	Sarbanes-Oxley Section 906 certification of Principal Executive Officer.
	32	.2**	Sarbanes-Oxley Section 906 certification of Principal Financial Officer.
	101	.CAL**	XBRL Calculation Linkbase Document.
	101	.DEF**	XBRL Definition Linkbase Document.
	101	.INS**	XBRL Instance Document.
	101	.LAB**	XBRL Labels Linkbase Document.
	101	.PRE**	XBRL Presentation Linkbase Document.
	101	.SCH**	XBRL Schema Document.

*	Filed herewith.
**	Furnished herewith.
†	Portions of this exhibit have been omitted pursuant to a request for confidential treatment.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on August 5, 2011.

Copano Energy, L.L.C.

By:  /s/  R. Bruce Northcutt

R. Bruce Northcutt

President and Chief Executive Officer

(Principal Executive Officer)

By:  /s/  Carl A. Luna

Carl A. Luna

Senior Vice President and Chief Financial Officer

(Principal Financial Officer)

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