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

Form 10-Q

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

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 66,279,877 common units of Copano Energy, L.L.C. outstanding at October 31, 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 September 30, 2011 and December 31, 2010		3
		Unaudited Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2011 and 2010		4
		Unaudited Consolidated Statements of Cash Flows for the Nine Months Ended September 30, 2011 and 2010		5
		Unaudited Consolidated Statement of Members’ Capital and Comprehensive Income (Loss) for the Nine Months Ended September 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		35
	Item 3.	Quantitative and Qualitative Disclosures About Market Risk		56
	Item 4.	Controls and Procedures		60
PART II — OTHER INFORMATION
	Item 1.	Legal Proceedings		61
	Item 1A.	Risk Factors		61
	Item 6.	Exhibits		61
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

	September 30,			December 31,
	2011			2010
	(In thousands, except unit information)
ASSETS
Current assets:
Cash and cash equivalents	$	53,534		$	59,930
Accounts receivable, net		108,339			96,662
Risk management assets		12,101			7,836
Prepayments and other current assets		8,311			5,179
Total current assets		182,285			169,607
Property, plant and equipment, net		1,078,948			912,157
Intangible assets, net		179,992			188,585
Investments in unconsolidated affiliates		529,958			604,304
Escrow cash		1,850			1,856
Risk management assets		17,128			11,943
Other assets, net		27,739			18,541
Total assets	$	2,017,900		$	1,906,993
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable	$	140,792		$	117,706
Accrued interest		19,945			10,621
Accrued tax liability		892			913
Risk management liabilities		7,285			9,357
Other current liabilities		33,948			14,495
Total current liabilities		202,862			153,092
Long term debt (includes $0 and $546 bond premium as of September 30, 2011 and December 31, 2010, respectively)		904,525			592,736
Deferred tax liability		2,135			1,883
Risk management and other noncurrent liabilities		2,150			4,525
Commitments and contingencies (Note 9)
Members’ capital:
Series A convertible preferred units, no par value, 11,399,097 units and 10,585,197 units issued and outstanding as of September 30, 2011 and December 31, 2010, respectively		285,168			285,172
Common units, no par value, 66,270,176 units and 65,915,173 units issued and outstanding as of September 30, 2011 and December 31, 2010, respectively		1,164,399			1,161,652
Paid in capital		59,250			51,743
Accumulated deficit		(592,676	)		(313,454	)
Accumulated other comprehensive loss		(9,913	)		(30,356	)
		906,228			1,154,757
Total liabilities and members’ capital	$	2,017,900		$	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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	(In thousands, except per unit information)
Revenue:
Natural gas sales	$	120,815		$	87,524		$	348,538		$	292,559
Natural gas liquids sales		191,370			118,999			521,129			353,119
Transportation, compression and processing fees		30,337			17,909			82,706			47,539
Condensate and other		11,169			13,272			37,299			41,204
Total revenue		353,691			237,704			989,672			734,421
Costs and expenses:
Cost of natural gas and natural gas liquids(1)		281,858			174,461			779,986			551,939
Transportation(1)		6,991			5,340			19,202			16,619
Operations and maintenance		16,091			13,004			46,953			38,337
Depreciation, amortization and impairment		21,911			15,218			56,143			46,002
General and administrative		10,031			9,869			34,530			31,311
Taxes other than income		1,502			1,315			4,029			3,658
Equity in loss (earnings) from unconsolidated affiliates		161,589			(2,049	)		158,581			19,788
Total costs and expenses		499,973			217,158			1,099,424			707,654
Operating (loss) income		(146,282	)		20,546			(109,752	)		26,767
Other income (expense):
Interest and other income		16			15			31			59
Loss on refinancing of unsecured debt		—			—			(18,233	)		—
Interest and other financing costs		(11,080	)		(12,943	)		(34,450	)		(41,239	)
(Loss) income before income taxes		(157,346	)		7,618			(162,404	)		(14,413	)
Provision for income taxes		(390	)		(320	)		(1,161	)		(660	)
Net (loss) income		(157,736	)		7,298			(163,565	)		(15,073	)
Preferred unit distributions		(8,279	)		(7,500	)		(24,235	)		(7,500	)
Net loss to common units	$	(166,015	)	$	(202	)	$	(187,800	)	$	(22,573	)
Basic and diluted net loss per common unit	$	(2.51	)	$	—		$	(2.84	)	$	(0.36	)
Weighted average number of common units		66,246			65,658			66,125			63,193
Distributions declared per common unit	$	0.575		$	0.575		$	1.725		$	1.725

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

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

4

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Nine Months Ended September 30,
	2011			2010
	(In thousands)
Cash Flows From Operating Activities:
Net loss	$	(163,565	)	$	(15,073	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and impairment		56,143			46,002
Amortization of debt issue costs		2,855			2,773
Equity in loss from unconsolidated affiliates		158,581			19,788
Distributions from unconsolidated affiliates		17,961			16,999
Loss on refinancing of unsecured debt		18,233			—
Non-cash gain on risk management activities, net		(4,723	)		(555	)
Equity-based compensation		7,445			7,118
Deferred tax provision		253			(19	)
Other non-cash items		(86	)		(458	)
Changes in assets and liabilities, net of acquisitions:
Accounts receivable		(11,132	)		10,586
Prepayments and other current assets		(2,952	)		2,135
Risk management activities		11,353			10,766
Accounts payable		17,459			(6,518	)
Other current liabilities		14,964			945
Net cash provided by operating activities		122,789			94,489
Cash Flows From Investing Activities:
Additions to property, plant and equipment		(175,323	)		(101,265	)
Additions to intangible assets		(5,316	)		(2,259	)
Acquisitions		(16,084	)		—
Investments in unconsolidated affiliates		(105,111	)		(11,186	)
Distributions from unconsolidated affiliates		2,368			2,555
Escrow cash		6			—
Proceeds from sale of assets		248			279
Other		98			280
Net cash used in investing activities		(299,114	)		(111,596	)
Cash Flows From Financing Activities:
Proceeds from long-term debt		725,000			80,000
Repayment of long-term debt		(412,665	)		(350,000	)
Payments of premiums and expenses on redemption of unsecured debt		(14,572	)		—
Deferred financing costs		(15,743	)		(995	)
Distributions to unitholders		(114,834	)		(107,612	)
Proceeds from issuance of Series A convertible preferred units, net of underwriting discounts and commissions of $8,935		—			291,065
Proceeds from public offering of common units, net of underwriting discounts and commissions of $7,223		—			164,786
Equity offering costs		(4	)		(6,236	)
Proceeds from option exercises		2,747			3,188
Net cash provided by financing activities		169,929			74,196
Net (decrease) increase in cash and cash equivalents		(6,396	)		57,089
Cash and cash equivalents, beginning of year		59,930			44,692
Cash and cash equivalents, end of period	$	53,534		$	101,781

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)		814		23,644			—		—		—		—		—		—			—			23,644			—
Accrued in-kind units		—		591			—		—		—		—		—		—			—			591			—
In-kind distributions		—		(24,235	)		—		—		—		—		—		—			—			(24,235	)		—
Cash distributions to common unitholders		—		—			—		—		—		—		—		(115,657	)		—			(115,657	)		—
Equity offering costs		—		(4	)		—		—		—		—		—		—			—			(4	)		—
Equity-based compensation		—		—			355		2,747		—		—		7,507		—			—			10,254			—
Net loss		—		—			—		—		—		—		—		(163,565	)		—			(163,565	)		(163,565	)
Derivative settlements reclassified to income		—		—			—		—		—		—		—		—			28,101			28,101			28,101
Unrealized loss-change in fair value of derivatives		—		—			—		—		—		—		—		—			(7,658	)		(7,658	)		(7,658	)
Comprehensive loss																									$	(143,122	)
Balance, September 30, 2011		11,399	$	285,168			66,270	$	1,164,399		—	$	—	$	59,250	$	(592,676	)	$	(9,913	)	$	906,228

	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, 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	)		—		—			—			—			—
Issuance of preferred units (paid-in-kind)		—		7,500			—		—			—			—			—		(7,500	)		—			—			—
Cash distributions to common unitholders		—		—			—		—			—			—			—		(108,161	)		—			(108,161	)		—
Issuance of units		10,327		300,000			7,446		172,008			—			—			—		—			—			472,008			—
Equity offering costs		—		(14,719	)		—		(7,754	)		—			—			—		—			—			(22,473	)		—
Equity-based compensation		—		—			382		3,188			—			—			7,041		—			—			10,229			—
Net loss		—		—			—		—			—			—			—		(15,073	)		—			(15,073	)		(15,073	)
Derivative settlements reclassified to income		—		—			—		—			—			—			—		—			(3,636	)		(3,636	)		(3,636	)
Unrealized gain-change in fair value of derivatives		—		—			—		—			—			—			—		—			3,930			3,930			3,930
Comprehensive loss																												$	(14,779	)
Balance, September 30, 2010		10,327	$	292,781			65,744	$	1,159,400			—		$	—		$	49,559	$	(289,001	)	$	(15,889	)	$	1,196,850

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 (“2010 10-K”).

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 results, 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:

	September 30, 2011
	Weighted
	Average		Gross
	Amortization		Carrying		Accumulated
	Period		Amount		Amortization			Net
	(In years)				(In thousands)
Rights-of-way and easements		19	$	130,217	$	(27,420	)	$	102,797
Contracts		17		108,416		(34,546	)		73,870
Customer relationships		11		4,864		(1,539	)		3,325
Total		18	$	243,497	$	(63,505	)	$	179,992

	December 31, 2010
	Weighted
	Average		Gross
	Amortization		Carrying		Accumulated
	Period		Amount		Amortization			Net
	(In years)				(In thousands)
Rights-of-way and easements		20	$	125,496	$	(23,234	)	$	102,262
Contracts		18		107,916		(25,153	)		82,763
Customer relationships		12		4,864		(1,304	)		3,560
Total		19	$	238,276	$	(49,691	)	$	188,585

During the three and nine months ended September 30, 2011 and 2010, we did not place in service any intangible assets with future renewals or extension costs. Amortization expense was $7,960,000 and $2,792,000 for the three months ended September 30, 2011 and 2010, respectively. Amortization expense was $13,814,000 and $8,354,000 for the nine months ended September 30, 2011 and 2010, respectively. During the three months ended September 30, 2011, we recorded a non-cash impairment charge of $5.0 million with respect to a contract under which we provide services to Rocky Mountains producers (see Accounting Standards Codification (“ASC”) 820 “Fair Value Measurement” and ASC 815 “Derivatives and Hedging” in Note 11).

Estimated aggregate amortization expense remaining for 2011 and each of the five succeeding fiscal years is approximately: 2011 — $2,974,000; 2012 — $11,969,000; 2013 — $11,796,000; 2014 — $11,518,000; 2015 — $11,457,000; and 2016 — $11,435,000.

8

Note 4 — Investments in Unconsolidated Affiliates

Our investments in unconsolidated affiliates consisted of the following at September 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 September 30, 2011, Fort Union is in compliance with this financial covenant.

Eagle Ford Gathering.  Our investment in Eagle Ford Gathering totaled $108,195,000 as of September 30, 2011. The summarized financial information for our investment in Eagle Ford Gathering, which is accounted for using the equity method, is as follows:

	As of and for the
	Nine Months Ended September 30,
	2011			2010
	(In thousands)
Operating revenue	$	10,494		$	—
Operating expenses		(5,609	)		(41	)
Depreciation and amortization		(1,064	)		—
Net income (loss)		3,821			(41	)
Ownership %		50	%		50	%
		1,911			(21	)
Copano’s share of management fees charged		74			20
Amortization of difference between the carried investment and the underlying equity in net assets		(7	)		—
Equity in earnings (loss) from unconsolidated affiliates	$	1,978		$	(1	)
Distributions	$	775		$	—
Contributions	$	73,514		$	9,492
Current assets	$	21,464		$	11,667
Noncurrent assets		211,859			22,763
Current liabilities		(23,886	)		(15,486	)
Noncurrent liabilities		(272	)		—
Net assets	$	209,165		$	18,944

Bighorn and Fort Union.  Our investments in Bighorn and Fort Union totaled $214,030,000 and $169,169,000, respectively, as of September 30, 2011.

9

Note 4 — Investments in Unconsolidated Affiliates (Continued)

We evaluate the carrying value of our investments in unconsolidated affiliates when circumstances indicate that our investment may not be fully recoverable. During the three months ended September 30, 2011, we recorded a $120.0 million non-cash impairment charge relating to our investment in Bighorn and a $45.0 million non-cash impairment charge relating to our investment in Fort Union. We determined that these charges were necessary primarily based on a downward shift in the Colorado Interstate Gas forward price curve and our expectations of a continued weak outlook for Rocky Mountains natural gas prices and, as producers focus more on rich-gas and shale plays, a continued lack of drilling activity in Wyoming’s Powder River Basin. We determined the fair value of our investments in Bighorn and Fort Union (see ASC 820 “Fair Value Measurement” and ASC 815 “Derivatives and Hedging” in Note 11) using a probability-weighted discounted cash flow model with a discount rate reflective of our cost of capital and estimated contract rates, volumes, operating and maintenance costs and capital expenditures.

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

	As of and for the Nine Months Ended September 30,
	2011						2010
	Bighorn			Fort Union			Bighorn			Fort Union
	(In thousands)
Operating revenue	$	20,436		$	41,011		$	23,793		$	42,852
Operating expenses		(7,089	)		(5,175	)		(8,904	)		(5,362	)
Depreciation and amortization		(3,874	)		(5,994	)		(3,887	)		(5,628	)
Interest income (expense) and other		62			(1,705	)		77			(3,520	)
Net income		9,535			28,137			11,079			28,342
Ownership %		51	%		37.04	%		51	%		37.04	%
		4,863			10,422			5,650			10,498
Priority allocation of earnings and other		460			—			379			—
Copano’s share of management fees charged		147			68			213			66
Amortization of difference between the carried investment and the underlying equity in net assets and impairment		(128,445	)		(49,817	)		(33,899	)		(4,817	)
Equity in (loss) earnings from unconsolidated affiliates	$	(122,975	)	$	(39,327	)	$	(27,657	)	$	5,747
Distributions	$	7,415		$	9,927		$	8,423		$	8,704
Contributions	$	530		$	—		$	810		$	774
Current assets	$	5,304		$	12,447		$	6,188		$	14,424
Noncurrent assets		86,587			198,227			89,750			206,580
Current liabilities		(1,852	)		(20,285	)		(1,206	)		(19,949	)
Noncurrent liabilities		(289	)		(63,046	)		(257	)		(78,190	)
Net assets	$	89,750		$	127,343		$	94,475		$	122,865

10

Note 4 — Investments in Unconsolidated Affiliates (Continued)

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

	As of and for the
	Nine Months Ended September 30,
	2011			2010
	(In thousands)
Operating revenue	$	21,283		$	24,112
Operating expenses		(17,887	)		(20,132	)
Depreciation and amortization		(1,394	)		(1,137	)
Other income, net		—			3
Net income	$	2,002		$	2,846
Equity in earnings from unconsolidated affiliates	$	1,743		$	2,123
Distributions	$	2,212		$	2,427
Contributions(1)	$	27,391		$	—
Current assets	$	5,306		$	4,278
Noncurrent assets		71,471			20,847
Current liabilities		(6,876	)		(5,594	)
Noncurrent liabilities		(170	)		(61	)
Net assets	$	69,731		$	19,470

(1) Contributions for the nine months ended September 30, 2011 were primarily made to Liberty Pipeline Group for the construction of its NGL pipeline.

Note 5 — Long-Term Debt

	September 30,		December 31,
	2011		2010
	(In thousands)
Revolving credit facility	$	295,000	$	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	$	904,525	$	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 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

11

Note 5 — Long-Term Debt (Continued)

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 September 30, 2011, we had no letters of credit outstanding.

The weighted average rate on borrowings under the revolving credit facility for the nine months ended September 30, 2011 and 2010 was 6.48% and 7.74%, 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 $5,468,000 and $4,709,000 for the nine months ended September 30, 2011 and 2010, respectively.

We incurred $7,833,000 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 term in accordance with ASC 470-50-40-21, “Debt — Modifications and Extinguishments-Line-of-Credit Arrangements.” As of September 30, 2011, the unamortized portion of debt issue costs totaled $10,655,000.

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 September 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 $20,852,000 for the nine months ended September 30, 2011 and 2010, respectively.

Interest and other financing costs relating to the 2021 Notes totaled $12,937,000 for the nine months ended September 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 September 30, 2011, the unamortized portion of debt issue costs totaled $7,547,000.

7.75% Senior Notes Due 2018.  At September 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 $14,912,000 for each of the nine months ended September 30, 2011 and 2010, respectively. Interest on the 2018 Notes is payable each June 1 and

12

Note 5 — Long-Term Debt (Continued)

December 1. Costs of issuing the 2018 Notes are being amortized over the term of the 2018 Notes and, as of September 30, 2011, the unamortized portion of debt issue costs totaled $3,627,000.

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 September 30, 2011.

Guarantor Financial Statements

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

13

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS

Note 5 — Long-Term Debt (Continued)

	September 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	$	4,142		$	—		$	49,392		$	—		$	—		$	53,534		$	9,650		$	—		$	50,280		$	—	$	—		$	59,930
Accounts receivable, net		2			—			108,337			—			—			108,339			14			—			96,648			—		—			96,662
Intercompany receivable		128,659			(1	)		(128,658	)		—			—			—			35,178			(1	)		(35,177	)		—		—			—
Risk management assets		—			—			12,101			—			—			12,101			—			—			7,836			—		—			7,836
Prepayments and other current assets		1,916			—			6,395			—			—			8,311			3,378			—			1,801			—		—			5,179
Total current assets		134,719			(1	)		47,567			—			—			182,285			48,220			(1	)		121,388			—		—			169,607
Property, plant and equipment, net		26			—			1,078,922			—			—			1,078,948			56			—			912,101			—		—			912,157
Intangible assets, net		—			—			179,992			—			—			179,992			—			—			188,585			—		—			188,585
Investments in unconsolidated affiliates		—			—			529,958			529,958			(529,958	)		529,958			—			—			604,304			604,304		(604,304	)		604,304
Investments in consolidated subsidiaries		1,683,951			—			—			—			(1,683,951	)		—			1,703,940			—			—			—		(1,703,940	)		—
Escrow cash		—			—			1,850			—			—			1,850			—			—			1,856			—		—			1,856
Risk management assets		—			—			17,128			—			—			17,128			—			—			11,943			—		—			11,943
Other assets, net		21,831			—			5,908			—			—			27,739			13,128			—			5,413			—		—			18,541
Total assets	$	1,840,527		$	(1	)	$	1,861,325		$	529,958		$	(2,213,909	)	$	2,017,900		$	1,765,344		$	(1	)	$	1,845,590		$	604,304	$	(2,308,244	)	$	1,906,993
LIABILITIES AND MEMBERS’/PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	1,458		$	—		$	139,334		$	—		$	—		$	140,792		$	17		$	—		$	117,689		$	—	$	—		$	117,706
Accrued interest		19,945			—			—			—			—			19,945			10,621			—			—			—		—			10,621
Accrued tax liability		892			—			—			—			—			892			913			—			—			—		—			913
Risk management liabilities		—			—			7,285			—			—			7,285			—			—			9,357			—		—			9,357
Other current liabilities		5,343			—			28,605			—			—			33,948			4,266			—			10,229			—		—			14,495
Total current liabilities		27,638			—			175,224			—			—			202,862			15,817			—			137,275			—		—			153,092
Long-term debt		904,525			—			—			—			—			904,525			592,736			—			—			—		—			592,736
Deferred tax liability		2,048			—			87			—			—			2,135			1,848			—			35			—		—			1,883
Risk management and other noncurrent liabilities		88			—			2,062			—			—			2,150			186			—			4,339			—		—			4,525
Members’/Partners’ capital:
Series A convertible preferred units		285,168			—			—			—			—			285,168			285,172			—			—			—		—			285,172
Common units		1,164,399			—			—			—			—			1,164,399			1,161,652			—			—			—		—			1,161,652
Paid in capital		59,250			1			1,214,619			686,291			(1,900,911	)		59,250			51,743			1			1,162,543			602,055		(1,764,599	)		51,743
Accumulated deficit		(592,676	)		(2	)		479,246			(156,333	)		(322,911	)		(592,676	)		(313,454	)		(2	)		571,754			2,249		(574,001	)		(313,454	)
Accumulated other comprehensive loss		(9,913	)		—			(9,913	)		—			9,913			(9,913	)		(30,356	)		—			(30,356	)		—		30,356			(30,356	)
		906,228			(1	)		1,683,952			529,958			(2,213,909	)		906,228			1,154,757			(1	)		1,703,941			604,304		(2,308,244	)		1,154,757
Total liabilities and members’/partners’ capital	$	1,840,527		$	(1	)	$	1,861,325		$	529,958		$	(2,213,909	)	$	2,017,900		$	1,765,344		$	(1	)	$	1,845,590		$	604,304	$	(2,308,244	)	$	1,906,993

14

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (Continued)

	Three Months Ended September 30, 2011																	Three Months Ended September 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	$	—		$	—	$	120,815		$	—		$	—		$	120,815		$	—		$	—	$	87,524		$	—		$	—		$	87,524
Natural gas liquids sales		—			—		191,370			—			—			191,370			—			—		118,999			—			—			118,999
Transportation, compression and processing fees		—			—		30,337			—			—			30,337			—			—		17,909			—			—			17,909
Condensate and other		—			—		11,169			—			—			11,169			—			—		13,272			—			—			13,272
Total revenue		—			—		353,691			—			—			353,691			—			—		237,704			—			—			237,704
Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		281,858			—			—			281,858			—			—		174,461			—			—			174,461
Transportation		—			—		6,991			—			—			6,991			—			—		5,340			—			—			5,340
Operations and maintenance		—			—		16,091			—			—			16,091			—			—		13,004			—			—			13,004
Depreciation, amortization and impairment		10			—		21,901			—			—			21,911			10			—		15,208			—			—			15,218
General and administrative		4,460			—		5,571			—			—			10,031			4,692			—		5,177			—			—			9,869
Taxes other than income		—			—		1,502			—			—			1,502			—			—		1,315			—			—			1,315
Equity in loss (earnings) from unconsolidated affiliates		—			—		161,589			161,589			(161,589	)		161,589			—			—		(2,049	)		(2,049	)		2,049			(2,049	)
Total costs and expenses		4,470			—		495,503			161,589			(161,589	)		499,973			4,702			—		212,456			(2,049	)		2,049			217,158
Operating (loss) income		(4,470	)		—		(141,812	)		(161,589	)		161,589			(146,282	)		(4,702	)		—		25,248			2,049			(2,049	)		20,546
Other income (expense):
Interest and other income		—			—		16			—			—			16			—			—		15			—			—			15
Interest and other financing costs		(10,952	)		—		(128	)		—			—			(11,080	)		(11,725	)		—		(1,218	)		—			—			(12,943	)
(Loss) income before income taxes and equity in earnings from consolidated subsidiaries		(15,422	)		—		(141,924	)		(161,589	)		161,589			(157,346	)		(16,427	)		—		24,045			2,049			(2,049	)		7,618
Provision for income taxes		(365	)		—		(25	)		—			—			(390	)		(285	)		—		(35	)		—			—			(320	)
(Loss) income before equity in earnings from consolidated subsidiaries		(15,787	)		—		(141,949	)		(161,589	)		161,589			(157,736	)		(16,712	)		—		24,010			2,049			(2,049	)		7,298
Equity in (loss) earnings from consolidated subsidiaries		(141,948	)		—		—			—			141,948			—			24,010			—		—			—			(24,010	)		—
Net (loss) income		(157,735	)		—		(141,949	)		(161,589	)		303,537			(157,736	)		7,298			—		24,010			2,049			(26,059	)		7,298
Preferred unit distributions		(8,279	)		—		—			—			—			(8,279	)		(7,500	)		—		—			—			—			(7,500	)
Net (loss) income to common units	$	(166,014	)	$	—	$	(141,949	)	$	(161,589	)	$	303,537		$	(166,015	)	$	(202	)	$	—	$	24,010		$	2,049		$	(26,059	)	$	(202	)

15

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (Continued)

	Nine Months Ended September 30, 2011																	Nine Months Ended September 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	$	—		$	—	$	348,538		$	—		$	—		$	348,538		$	—		$	—	$	292,559		$	—		$	—		$	292,559
Natural gas liquids sales		—			—		521,129			—			—			521,129			—			—		353,119			—			—			353,119
Transportation, compression and processing fees		—			—		82,706			—			—			82,706			—			—		47,539			—			—			47,539
Condensate and other		—			—		37,299			—			—			37,299			—			—		41,204			—			—			41,204
Total revenue		—			—		989,672			—			—			989,672			—			—		734,421			—			—			734,421
Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		779,986			—			—			779,986			—			—		551,939			—			—			551,939
Transportation		—			—		19,202			—			—			19,202			—			—		16,619			—			—			16,619
Operations and maintenance		—			—		46,953			—			—			46,953			—			—		38,337			—			—			38,337
Depreciation, amortization and impairment		30			—		56,113			—			—			56,143			30			—		45,972			—			—			46,002
General and administrative		17,876			—		16,654			—			—			34,530			15,718			—		15,593			—			—			31,311
Taxes other than income		—			—		4,029			—			—			4,029			—			—		3,658			—			—			3,658
Equity in loss (earnings) from unconsolidated affiliates		—			—		158,581			158,581			(158,581	)		158,581			—			—		19,788			19,788			(19,788	)		19,788
Total costs and expenses		17,906			—		1,081,518			158,581			(158,581	)		1,099,424			15,748			—		691,906			19,788			(19,788	)		707,654
Operating (loss) income		(17,906	)		—		(91,846	)		(158,581	)		158,581			(109,752	)		(15,748	)		—		42,515			(19,788	)		19,788			26,767
Other income (expense):
Interest and other income		—			—		31			—			—			31			—			—		59			—			—			59
Loss on refinancing of unsecured debt		(18,233	)		—		—			—			—			(18,233	)		—			—		—			—			—			—
Interest and other financing costs		(33,579	)		—		(871	)		—			—			(34,450	)		(37,789	)		—		(3,450	)		—			—			(41,239	)
(Loss) income before income taxes and equity in earnings from consolidated subsidiaries		(69,718	)		—		(92,686	)		(158,581	)		158,581			(162,404	)		(53,537	)		—		39,124			(19,788	)		19,788			(14,413	)
Provision for income taxes		(1,105	)		—		(56	)		—			—			(1,161	)		(625	)		—		(35	)		—			—			(660	)
(Loss) income before equity in earnings from consolidated subsidiaries		(70,823	)		—		(92,742	)		(158,581	)		158,581			(163,565	)		(54,162	)		—		39,089			(19,788	)		19,788			(15,073	)
Equity in (loss) earnings from consolidated subsidiaries		(92,742	)		—		—			—			92,742			—			39,089			—		—			—			(39,089	)		—
Net (loss) income		(163,565	)		—		(92,742	)		(158,581	)		251,323			(163,565	)		(15,073	)		—		39,089			(19,788	)		(19,301	)		(15,073	)
Preferred unit distributions		(24,235	)		—		—			—			—			(24,235	)		(7,500	)		—		—			—			—			(7,500	)
Net (loss) income to common units	$	(187,800	)	$	—	$	(92,742	)	$	(158,581	)	$	251,323		$	(187,800	)	$	(22,573	)	$	—	$	39,089		$	(19,788	)	$	(19,301	)	$	(22,573	)

16

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

NOTES TO UNAUDITED CONSOLIDATED FINANCIAL STATEMENTS — (Continued)

Note 5 — Long-Term Debt (Continued)

	Nine Months Ended September 30, 2011																	Nine Months Ended September 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	$	(124,348	)	$	—	$	247,137		$	17,961		$	(17,961	)	$	122,789		$	(63,627	)	$	—		$	158,116		$	16,999		$	(16,999	)	$	94,489
Cash Flows From Investing Activities:
Additions to property, plant and equipment and intangibles		—			—		(180,639	)		—			—			(180,639	)		—			—			(103,524	)		—			—			(103,524	)
Acquisitions		—			—		(16,084	)		—			—			(16,084	)		—			—			—			—			—			—
Investments in unconsolidated affiliates		—			—		(105,111	)		(105,111	)		105,111			(105,111	)		—			—			(11,186	)		(11,186	)		11,186			(11,186	)
Distributions from unconsolidated affiliates		—			—		2,368			2,368			(2,368	)		2,368			—			—			2,555			2,555			(2,555	)		2,555
Investments in consolidated affiliates		(99,864	)		—		—			—			99,864			—			(61,832	)		1			—			—			61,831			—
Distributions from consolidated affiliates		48,775			—		—			—			(48,775	)		—			95,255			—			—			—			(95,255	)		—
Proceeds from sale of assets		—			—		248			—			—			248			—			—			279			—			—			279
Other		—			—		104			—			—			104			—			—			280			—			—			280
Net cash (used in) provided by investing activities		(51,089	)		—		(299,114	)		(102,743	)		153,832			(299,114	)		33,423			1			(111,596	)		(8,631	)		(24,793	)		(111,596	)
Cash Flows From Financing Activities:
Proceeds from long-term debt		725,000			—		—			—			—			725,000			80,000			—			—			—			—			80,000
Repayment of long-term debt		(412,665	)		—		—			—			—			(412,665	)		(350,000	)		—			—			—			—			(350,000	)
Deferred financing costs		(15,743	)		—		—			—			—			(15,743	)		(995	)		—			—			—			—			(995	)
Payments of premiums and expenses on redemption of unsecured debt		(14,572	)		—		—			—			—			(14,572	)		—			—			—			—			—			—
Distributions to unitholders		(114,834	)		—		—			—			—			(114,834	)		(107,612	)		—			—			—			—			(107,612	)
Proceeds from public offering of common units		—			—		—			—			—			—			164,786			—			—			—			—			164,786
Equity offering costs		(4	)		—		—			—			—			(4	)		(6,236	)		—			—			—			—			(6,236	)
Equity offering of Series A convertible preferred units		—			—		—			—			—			—			291,065			—			—			—			—			291,065
Contributions from parent		—			—		99,864			—			(99,864	)		—			—			—			61,831			—			(61,831	)		—
Distributions to parent		—			—		(48,775	)		—			48,775			—			—			—			(95,255	)		—			95,255			—
Other		2,747			—		—			(105,111	)		(105,111	)		2,747			3,188			—			—			11,186			(11,186	)		3,188
Net cash provided by (used in) financing activities		169,929			—		51,089			105,111			(156,200	)		169,929			74,196			—			(33,424	)		11,186			22,238			74,196
Net increase (decrease) in cash and cash equivalents		(5,508	)		—		(888	)		20,329			(20,329	)		(6,396	)		43,992			1			13,096			19,554			(19,554	)		57,089
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	$	4,142		$	—	$	49,392		$	106,180		$	(106,180	)	$	53,534		$	47,853		$	—		$	53,928		$	79,450		$	(79,450	)	$	101,781

17

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		August 11, 2011		8,077,000
September 30, 2011		284,977	(1)	November 2011(1)		8,279,000

(1) Units will be issued on or about November 10, 2011

For additional information about our Series A preferred units, please read Note 6, “Members’ Capital and Distributions,” in Item 8 of our 2010 10-K.

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
September 30, 2011	$	0.575	October 12, 2011	October 31, 2011	November 10, 2011	$	38,705,000

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 September 30, 2011, the number of units available for grant under our LTIP totaled 2,204,880 of which up to 1,677,538 units were eligible to be issued as restricted common units, phantom units or unit awards.

Equity Awards.  We recognized non-cash compensation expense of $6,795,000 and $5,790,000 related to the amortization of equity-based compensation under our LTIP during the nine months ended September 30, 2011 and 2010, respectively. See Item 8 in our 2010 10-K for details on our equity-based compensation.

Unit Awards.  During the nine months ended September 30, 2011, we issued 72,450 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 September 30, 2011, we have accrued $554,000 for the third quarter 2011 EICP bonuses. Additionally, as of September 30, 2011, we have accrued $1,623,000 of the 2011 MICP incentive bonuses and estimate unrecognized compensation costs related to these outstanding liability awards to be $902,000, which is expected to be recognized as expense on a straight-line basis through February 2012, when we settle 2011 MICP bonuses.

18

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 nine months ended September 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:

	Three Months				Nine Months
	Ended				Ended
	September 30,				September 30,
	2011		2010		2011		2010
			(In thousands)
Employee options		800		1,096		800		1,096
Unit appreciation rights		401		359		401		359
Restricted units		43		54		43		54
Phantom units		993		884		993		884
Contingent incentive plan unit awards		73		33		73		61
Series A preferred units		11,399		8,082		11,399		2,724

19

Note 8 — Related Party Transactions

Natural Gas and Related Transactions

The following table summarizes transactions between us and affiliated entities:

	Three Months					Nine Months
	Ended					Ended
	September 30,					September 30,
	2011		2010			2011			2010
			(In thousands)
Affiliates of Mr. Lawing:(1)
Natural gas sales(2)	$	—	$	14		$	(1	)	$	16
Gathering and compression services(3)		—		2			3			7
Natural gas purchases(4)		—		67			82			455
Reimbursable costs(5)		57		57			171			207
Webb Duval:
Natural gas sales(2)		—		33			39			45
Natural gas purchases(4)		459		(179	)		90			(66	)
Transportation costs(6)		178		56			348			187
Management fees(7)		57		56			169			168
Reimbursable costs(7)		184		503			521			642
Payable to us as of September 30, 2011(8)							81
Payable by us as of September 30, 2011(9)							454
Eagle Ford Gathering:
Natural gas sales(2)		1,091		—			1,091			—
Gathering and compression services(3)		739		—			739			—
Natural gas purchases(4)		7,298		—			7,298			—
Management fees(7)		67		41			149			41
Reimbursable costs(7)		999		1,389			14,594			—
Capital project fees(7)		181		189			729			189
Payable to us as of September 30, 2011(8)							375
Payable by us as of September 30, 2011(9)							3,677
Liberty Pipeline Group:
NGL transportation services(3)		145		—			145			—
Management fees(7)		38		—			38			—
Reimbursable costs(7)		1,726		—			17,231			—
Payable to us as of September 30, 2011(8)							94
Payable by us as of September 30, 2011(9)							45
Southern Dome:
Management fees(7)		63		63			188			188
Reimbursable costs(7)		98		96			299			253
Payable to us as of September 30, 2011(8)							42
Bighorn:
Compressor rental fees(10)		299		417			1,114			1,250
Gathering costs(6)		—		—			—			16
Natural gas purchases(4)		—		—			—			3
Management fees(7)		96		139			289			417
Reimbursable costs(7)		579		648			1,741			1,873
Payable to us as of September 30, 2011(8)							21
Fort Union:
Gathering costs(6)		1,610		1,288			4,269			3,926
Treating costs(4)		—		—			6			52
Management fees(7)		62		60			185			180
Reimbursable costs(7)		57		32			833			161
Payable to us as of September 30, 2011(8)							6
Other:
Natural gas sales(2)		—		50			—			175
Payable to us as of September 30, 2011(8)							2

20

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. Effective October 1, 2011, Copano Operations terminated this services agreement.
(6)	Included in transportation on our consolidated statements of operations.
(7)	Management fees, reimbursable costs and capital project fees received from our unconsolidated affiliates are included in operations and maintenance and general and administrative expenses on our consolidated statements of operations.
(8)	Included in accounts receivable on the consolidated balance sheets.
(9)	Included in accounts payable on the consolidated balance sheets.
(10)	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 $15,000 and $70,000 for the three and nine months ended September 30, 2011, respectively. Michael G. MacDougall, a partner with TPG, was elected by our unitholders on May 18, 2011 to serve on our Board of Directors 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 $4,286,000 and $2,984,000, respectively, for the three months ended September 30, 2011 and 2010 and $6,317,000 and $7,104,000, respectively, for the nine months ended September 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 September 30, 2011 and 2010, rental expense for leased office space, vehicles, compressors and related field equipment used in our operations totaled $1,122,000 and $773,000, respectively. For the nine months ended September 30, 2011 and 2010, rental expense for leased office space, vehicles, compressors and related field equipment used in our operations totaled $3,179,000 and $2,506,000, respectively.

We are party to firm transportation or fractionation and product sales agreements with Wyoming Interstate Gas Company (“WIC”), Fort Union and Formosa Hydrocarbons Company, Inc. (“Formosa”) under which we are obligated to pay for natural gas or NGL services whether or not we use such services. The agreements with WIC, Fort Union and Formosa expire December 31, 2019, November 30, 2017 and March 31, 2023, respectively. Under these agreements, we are obligated to pay in aggregate approximately $4,079,000 for the remainder of 2011,

21

Note 9 — Commitments and Contingencies (Continued)

$17,021,000 in 2012, $24,728,000 in 2013, $23,905,000 in 2014, $22,489,000 in 2015 and $107,633,000 over the remainder of the contract terms.

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 September 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 September 30, 2011, we have accrued $1,324,000 of our 2011 obligation.

Regulatory Compliance

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

22

Note 10 — Supplemental Disclosures to the Statements of Cash Flows

	Nine Months Ended
	September 30,
	2011		2010
	(In thousands)
Cash payments for interest, net of $7,402,000 and $2,685,000 capitalized in 2011 and 2010, respectively	$	23,583	$	40,042
Cash payments for federal and state income taxes	$	925	$	655
In-kind distributions to Series A convertible preferred unitholders	$	24,235	$	7,500

We incurred a change in liabilities for investing activities that had not been paid as of September 30, 2011 and 2010 of $18,658,000 and $5,512,000, respectively. Such amounts are not included in the change in accounts payable and accrued liabilities or with acquisitions, additions to property, plant and equipment and intangible assets on the consolidated statements of cash flows. As of September 30, 2011 and 2010, we accrued $26,657,000 and $10,761,000, 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 as they pertain to: (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 recorded on our consolidated balance sheets at fair value. For derivatives designated as cash flow hedges under ASC 815, “Derivatives and Hedging,” we recognize the effective portion of changes in fair value as other comprehensive income (“OCI”) and

23

Note 11 — Financial Instruments (Continued)

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 September 30, 2011, we estimated that $11,885,000 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 nine months ended September 30, 2011, we reclassified $478,000 and $1,026,000, respectively, of losses from accumulated OCI to earnings as a result of determining the forecasted transaction was probable of not occurring.

At September 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		5,000		1,650
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

24

Note 11 — Financial Instruments (Continued)

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 September 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 September 30, 2011, our interest rate swaps were not designated as cash flow hedges.

As of September 30, 2011, we estimate that $185,000 of OCI related to previously designated swaps will be reclassified as a decrease to earnings in the next 12 months as the underlying interest rate swaps expire.

ASC 820 “Fair Value Measurement” and ASC 815 “Derivatives 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 September 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

25

Note 11 — Financial Instruments (Continued)

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

	Fair Value Measurements on Hedging Instruments(a)
	September 30, 2011
	Level 1		Level 2			Level 3		Total
	(In thousands)
Assets:
Natural Gas:
Short-term — Designated(b)	$	—	$	—		$	—	$	—
Short-term — Not designated(b)		—		—			—		—
Long-term — Designated(c)		—		—			—		—
Long-term — Not designated(c)		—		—			—		—
Natural Gas Liquids:
Short-term — Designated(b)		—		—			5,076		5,076
Short-term — Not designated(b)		—		—			1,285		1,285
Long-term — Designated(c)		—		—			8,947		8,947
Long-term — Not designated(c)		—		—			611		611
Crude Oil:
Short-term — Designated(b)		—		—			4,417		4,417
Short-term — Not designated(b)		—		—			1,323		1,323
Long-term — Designated(c)		—		—			7,074		7,074
Long-term — Not designated(c)		—		—			496		496
Total	$	—	$	—		$	29,229	$	29,229
Liabilities:
Natural Gas:
Short-term — Not designated(d)	$	—	$	129		$	—	$	129
Natural Gas Liquids:
Short-term — Designated(d)		—		—			2,730		2,730
Long-term — Designated(e)		—		—			—		—
Interest Rate:
Short-term — Not designated(d)		—		4,426			—		4,426
Long-term — Not designated(e)		—		176			—		176
Total	$	—	$	4,731		$	2,730	$	7,461
Total designated assets	$	—	$	—		$	22,784	$	22,784
Total not designated (liabilities)/assets	$	—	$	(4,731	)	$	3,715	$	(1,016	)

(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.”

26

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.

27

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.

As discussed in Notes 3 and 4, we recorded impairments with respect to our equity investments in Bighorn and Fort Union and a contract under which we provide services to Rocky Mountains producers during the three months ended September 30, 2011. The valuation of these investments required use of significant unobservable inputs. Our probability-weighted discounted cash flow analysis included the following input parameters that are not readily available: a discount rate reflective of our cost of capital and estimated contract rates, volumes, operating and maintenance costs and capital expenditures.

The following table presents, by level within the fair value hierarchy, certain assets that have been measured at fair value on a non-recurring basis.

	Fair Value Measurements of
	Impairments(a)
	September 30, 2011
	Level 3		Impairment Expense
	(In thousands)
Long-lived assets(b)	$	383,199	$	165,000
Long-lived intangible assets(c)		29,406		5,000

(a)	Measured on a non-recurring basis.
(b)	Impairments of equity investments in Bighorn and Fort Union are included on the consolidated balance sheets as a noncurrent asset under “Investments in unconsolidated affiliates” and on the consolidated statements of operations under “Equity in loss (earnings) from unconsolidated affiliates.”
(c)	Impairment of contract is included on the consolidated balance sheets as a noncurrent asset under “Intangible assets, net” and on the consolidated statements of operations under “Depreciation, amortization and impairment.”

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

	Three Months Ended September 30, 2011
	Natural Gas			Natural Gas Liquids			Crude Oil			Total
	(In thousands)
Assets balance, beginning of period	$	4		$	7,043		$	5,280		$	12,327
Total gains or losses:
Non-cash amortization of option premium		(1,486	)		(3,953	)		(2,004	)		(7,443	)
Other amounts included in earnings		—			(2,112	)		1,583			(529	)
Included in accumulated other comprehensive loss		1,482			7,768			8,452			17,702
Purchases		—			1,561			—			1,561
Settlements		—			2,881			—			2,881
Asset balance, end of period	$	—		$	13,188		$	13,311		$	26,499
Change in unrealized income included in earnings related to instruments still held as of the end of the period	$	—		$	(181	)	$	(267	)	$	(448	)

28

Note 11 — Financial Instruments (Continued)

	Nine Months Ended September 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		(4,409	)		(11,714	)		(5,946	)		(22,069	)
Other amounts included in earnings		—			(7,211	)		2,373			(4,838	)
Included in accumulated other comprehensive loss		4,322			7,245			8,609			20,176
Purchases		—			8,925			1,800			10,725
Settlements		—			7,593			—			7,593
Asset balance, end of period	$	—		$	13,188		$	13,311		$	26,499
Change in unrealized (income) loss included in earnings related to instruments still held as of the end of the period	$	—		$	(495	)	$	(208	)	$	(703	)

	Three Months Ended September 30, 2010
	Natural Gas			Natural Gas Liquids			Crude Oil			Total
	(In thousands)
Assets balance, beginning of period	$	653		$	36,237		$	21,529		$	58,419
Total gains or losses:
Non-cash amortization of option premium		(1,489	)		(4,154	)		(2,520	)		(8,163	)
Other amounts included in earnings		—			5,699			5,063			10,762
Included in accumulated other comprehensive loss		954			(15,048	)		(6,733	)		(20,827	)
Purchases		—			2,051			1,315			3,366
Settlements		—			(5,752	)		(5,382	)		(11,134	)
Asset balance, end of year	$	118		$	19,033		$	13,272		$	32,423
Change in unrealized loss (income) included in earnings related to instruments still held as of the end of the period	$	—		$	(135	)	$	316		$	181

	Nine Months Ended September 30, 2010
	Natural Gas			Natural Gas Liquids			Crude Oil			Total
	(In thousands)
Assets balance, beginning of period	$	2,752		$	15,641		$	24,213		$	42,606
Total gains or losses:
Non-cash amortization of option premium		(4,417	)		(12,317	)		(7,476	)		(24,210	)
Other amounts included in earnings		—			12,332			15,283			27,615
Included in accumulated other comprehensive loss		1,783			6,208			(8,069	)		(78	)
Purchases		—			9,433			4,740			14,173
Settlements		—			(12,264	)		(15,419	)		(27,683	)
Asset balance, end of period	$	118		$	19,033		$	13,272		$	32,423
Change in unrealized (income) loss included in earnings related to instruments still held as of the end of the period	$	—		$	(165	)	$	470		$	305

29

Note 11 — Financial Instruments (Continued)

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 September 30, 2011.

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 September 30, 2011
Natural gas	$	(5	)	$	(1,486	)	$	—		Natural gas sales
Natural gas liquids		1,102			(6,667	)		213		Natural gas liquids sales
Crude oil		6,901			(1,550	)		518		Condensate and other
Interest rate swaps		—			(74	)		—		Interest and other financing costs
Total	$	7,998		$	(9,777	)	$	731
Nine Months Ended September 30, 2011
Natural gas	$	(88	)	$	(4,410	)	$	—		Natural gas sales
Natural gas liquids		(11,496	)		(18,755	)		(104	)	Natural gas liquids sales
Crude oil		3,926			(4,682	)		558		Condensate and other
Interest rate swaps		—			(254	)		—		Interest and other financing costs
Total	$	(7,658	)	$	(28,101	)	$	454
Three Months Ended September 30, 2010
Natural gas	$	(535	)	$	(1,489	)	$	—		Natural gas sales
Natural gas liquids		(12,869	)		2,179			(116	)	Natural gas liquids sales
Crude oil		(3,764	)		2,971			(39	)	Condensate and other
Interest rate swaps		—			(117	)		—		Interest and other financing costs
Total	$	(17,168	)	$	3,544		$	(155	)
Nine Months Ended September 30, 2010
Natural gas	$	(2,634	)	$	(4,417	)	$	—		Natural gas sales
Natural gas liquids		6,784			577			(145	)	Natural gas liquids sales
Crude oil		(220	)		7,847			68		Condensate and other
Interest rate swaps		—			(371	)		—		Interest and other financing costs
Total	$	3,930		$	3,636		$	(77	)

30

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			Statements of
Hedging Instruments Under ASC 820	Income on Derivative			Operations Location
	(In thousands)
Three Months Ended September 30, 2011
Natural gas	$	(34	)	Natural gas sales
Natural gas liquids		556		Natural gas liquids sales
Crude oil		1,065		Condensate and other
Interest rate swaps		(54	)	Interest and other financing costs
Total	$	1,533
Nine Months Ended September 30, 2011
Natural gas	$	(162	)	Natural gas sales
Natural gas liquids		472		Natural gas liquids sales
Crude oil		1,814		Condensate and other
Interest rate swaps		(617	)	Interest and other financing costs
Total	$	1,507
Three Months Ended September 30, 2010
Natural gas	$	(15	)	Natural gas sales
Natural gas liquids		63		Natural gas liquids sales
Crude oil		(281	)	Condensate and other
Interest rate swaps		(1,101	)	Interest and other financing costs
Total	$	(1,334	)
Nine Months Ended September 30, 2010
Natural gas	$	(123	)	Natural gas sales
Natural gas liquids		214		Natural gas liquids sales
Crude oil		(205	)	Condensate and other
Interest rate swaps		(3,089	)	Interest and other financing costs
Total	$	(3,203	)

31

Note 12 — Fair Value of Financial Instruments

Amounts reflected in our consolidated balance sheets as of September 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 nine months ended September 30, 2011. Estimates of the fair value of our Senior Notes are based on market information as of September 30, 2011. A summary of the fair value and carrying value of the financial instruments is shown in the table below.

	September 30, 2011				December 31, 2010
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
	(In thousands)
Cash and cash equivalents	$	53,534	$	53,534	$	59,930	$	59,930
Revolving credit facility		295,000		295,000		10,000		9,873
2016 Notes		—		—		332,665		341,813
2018 Notes		249,525		252,020		249,525		254,516
2021 Notes		360,000		352,800		—		—

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 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 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.

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.

32

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 September 30, 2011:
Total segment gross margin	$	44,540		$	27,876		$	432		$	72,848		$	(8,006	)	$	64,842
Operations and maintenance expenses		9,082			6,930			79			16,091			—			16,091
Depreciation, amortization and impairment		7,182			8,623			5,764			21,569			342			21,911
General and administrative expenses		3,010			2,199			339			5,548			4,483			10,031
Taxes other than income		711			774			17			1,502			—			1,502
Equity in (earnings) loss from unconsolidated affiliates		(1,894	)		(652	)		164,135			161,589			—			161,589
Operating income (loss)	$	26,449		$	10,002		$	(169,902	)	$	(133,451	)	$	(12,831	)	$	(146,282	)
Natural gas sales	$	74,681		$	47,528		$	127		$	122,336		$	(1,521	)	$	120,815
Natural gas liquids sales		118,280			79,154			—			197,434			(6,064	)		191,370
Transportation, compression and processing fees		23,407			2,727			4,203			30,337			—			30,337
Condensate and other		2,874			8,417			299			11,590			(421	)		11,169
Sales to external customers	$	219,242		$	137,826		$	4,629		$	361,697		$	(8,006	)	$	353,691
Interest and other financing costs	$	—		$	—		$	—		$	—		$	11,080		$	11,080
Three Months Ended September 30, 2010:
Total segment gross margin	$	31,218		$	23,010		$	1,091		$	55,319		$	2,584		$	57,903
Operations and maintenance expenses		6,779			6,163			62			13,004			—			13,004
Depreciation and amortization		6,106			7,941			765			14,812			406			15,218
General and administrative expenses		2,432			2,361			362			5,155			4,714			9,869
Taxes other than income		597			702			16			1,315			—			1,315
Equity in loss (earnings) from unconsolidated affiliates		97			(671	)		(1,475	)		(2,049	)		—			(2,049	)
Operating income (loss)	$	15,207		$	6,514		$	1,361		$	23,082		$	(2,536	)	$	20,546
Natural gas sales	$	41,906		$	46,958		$	164		$	89,028		$	(1,504	)	$	87,524
Natural gas liquids sales		62,032			55,423			—			117,455			1,544			118,999
Transportation, compression and processing fees		11,263			2,229			4,417			17,909			—			17,909
Condensate and other		3,020			7,291			417			10,728			2,544			13,272
Sales to external customers	$	118,221		$	111,901		$	4,998		$	235,120		$	2,584		$	237,704
Interest and other financing costs	$	—		$	—		$	—		$	—		$	12,943		$	12,943

33

Note 13 — Segment Information (Continued)

							Rocky						Corporate
	Texas			Oklahoma			Mountains			Total Segments			and Other			Consolidated
				(In thousands)
Nine Months Ended September 30, 2011:
Total segment gross margin	$	135,685		$	79,623		$	2,245		$	217,553		$	(27,069	)	$	190,484
Operations and maintenance expenses		26,815			19,943			195			46,953			—			46,953
Depreciation, amortization and impairment		20,712			27,024			7,295			55,031			1,112			56,143
General and administrative expenses		8,731			6,766			1,003			16,500			18,030			34,530
Taxes other than income		1,938			2,056			18			4,012			17			4,029
Equity in loss (earnings) from unconsolidated affiliates		(1,698	)		(2,023	)		162,302			158,581			—			158,581
Operating income (loss)	$	79,187		$	25,857		$	(168,568	)	$	(63,524	)	$	(46,228	)	$	(109,752	)
Natural gas sales	$	211,466		$	141,264		$	380		$	353,110		$	(4,572	)	$	348,538
Natural gas liquids sales		315,879			224,174			—			540,053			(18,924	)		521,129
Transportation, compression and		61,989			7,927			12,790			82,706			—			82,706
Condensate and other		12,366			27,392			1,114			40,872			(3,573	)		37,299
Sales to external customers	$	601,700		$	400,757		$	14,284		$	1,016,741		$	(27,069	)	$	989,672
Interest and other financing costs	$	—		$	—		$	—		$	—		$	34,450		$	34,450
Segment assets	$	807,512		$	671,611		$	456,402		$	1,935,525		$	82,375		$	2,017,900
Nine Months Ended September 30, 2010:
Total segment gross margin	$	90,134		$	69,106		$	3,342		$	162,582		$	3,281		$	165,863
Operations and maintenance expenses		20,845			17,266			226			38,337			—			38,337
Depreciation and amortization		18,143			24,297			2,296			44,736			1,266			46,002
General and administrative expenses		7,606			6,338			1,487			15,431			15,880			31,311
Taxes other than income		1,860			1,779			19			3,658			—			3,658
Equity in loss (earnings) from unconsolidated affiliates		188			(2,311	)		21,911			19,788			—			19,788
Operating income (loss)	$	41,492		$	21,737		$	(22,597	)	$	40,632		$	(13,865	)	$	26,767
Natural gas sales	$	142,339		$	153,661		$	1,099		$	297,099		$	(4,540	)	$	292,559
Natural gas liquids sales		182,334			170,771			—			353,105			14			353,119
Transportation, compression and processing fees		29,288			4,860			13,391			47,539			—			47,539
Condensate and other		7,828			24,319			1,250			33,397			7,807			41,204
Sales to external customers	$	361,789		$	353,611		$	15,740		$	731,140		$	3,281		$	734,421
Interest and other financing costs	$	—		$	—		$	—		$	—		$	41,239		$	41,239

34

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.

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Recent Developments

Update on Eagle Ford Shale Projects.

•  The Eagle Ford Gathering pipeline began limited service in August 2011 and is expected to begin full service late in the fourth quarter 2011. As of October 31, 2011, this pipeline was flowing approximately 140,000 MMbtu/d.

•  Eagle Ford Gathering’s crossover pipeline began service in October 2011 to Williams Field Services’ Markham processing plant and is expected to begin service to Formosa Hydrocarbon’s Point Comfort facility by the end of 2011.

•  Construction on our 22,000 Bbls/d fractionator expansion at our Houston Central complex was completed in October 2011. Due to liquids-handling constraints downstream of Houston Central, we expect that our ability to use the expanded fractionation capacity will be limited until mid-to-late December.

•  The Liberty pipeline began limited service in August, and we anticipate that the pipeline will begin full service in mid-to-late December.

Declaration of Common Unit Distribution.  On October 12, 2011, our Board of Directors declared a cash distribution of $0.575 per common unit for the third quarter of 2011. This distribution will be paid on November 10, 2011 to all common unitholders of record at the close of business on October 31, 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 our natural gas and NGL volumes, which are a function primarily of 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 because some of our contracts in those segments have commodity-sensitive pricing terms. In addition, natural gas and NGL prices, and to a lesser degree, crude oil prices, also affect all of our segments indirectly because they influence exploration and production activity, which underlie the demand for our services and the long-term growth and sustainability of our business.

Commodity prices generally are influenced by various factors that affect supply and demand. These factors include regional drilling activity, storage levels, competing supplies (such as crude oil or liquefied natural gas imports or exports), and the availability and proximity of pipeline and NGL-handling capacity and markets for natural gas and NGLs. Many of the factors affecting demand are in turn dependent on overall economic activity. For example, demand for ethane, a primary feedstock for petrochemical and manufacturing industries, varies depending on overall economic activity. Factors that can cause volatility in crude oil prices, such as international political and economic events, can also affect NGL prices because the two tend to be highly correlated.

Producers typically increase drilling and well completions when prices are sufficient to make these activities economic and, depending on the severity and duration of an unfavorable pricing environment, may suspend these activities 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 existing 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, transportation capabilities and market demand.

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

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 the availability of equipment and services, 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 — that is, a greater likelihood that wells drilled will be productive — which reduces a producer’s overall drilling costs. Also, some producers rely on commodity price hedging to support drilling activity when prices are less favorable, and some may drill only to the extent that drilling activity is necessary to maintain their leasehold interests or under the terms of their capital commitments.

Third-Quarter 2011 Commodity Prices Overall.  Third-quarter natural gas and crude oil prices on the NYMEX were down 3% and 12%, respectively, compared to the second quarter of 2011. Our average NGL prices for the third quarter were down slightly on the Mont Belvieu index and more significantly on the Conway index compared to the second quarter of 2011.

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.

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	Quarterly Data for Texas
	Q1 2010		Q2 2010		Q3 2010		Q4 2010		Q1 2011		Q2 2011		Q3 2011
Houston Ship Channel ($/MMBtu)	$	5.36	$	4.04	$	4.33	$	3.78	$	4.06	$	4.29	$	4.23
Mont Belvieu ($/Bbl)	$	47.66	$	43.14	$	40.16	$	48.03	$	51.22	$	58.57	$	59.43
NYMEX crude oil ($/Bbl)	$	78.72	$	78.03	$	76.20	$	85.17	$	94.10	$	102.56	$	89.76
Service throughput (MMBtu/d)		582,958		559,876		590,116		648,941		654,996		665,040		765,744
Plant inlet (MMBtu/d)		457,233		469,019		516,949		574,616		560,903		588,533		686,398
NGLs produced (Bbls/d)		15,339		18,382		19,685		21,388		23,228		26,913		30,904
Segment gross margin (in thousands)	$	27,165	$	31,751	$	31,218	$	38,548	$	45,011	$	46,134	$	44,540

The first-of-the-month price for natural gas on the Houston Ship Channel index was $3.73 per MMBtu for October 2011, and the spot price was $3.53 per MMBtu on October 31, 2011. The weighted-average daily price for NGLs at Mont Belvieu for October 2011, based on our third quarter 2011 product mix, was $59.63 per Bbl.

Our standardized processing margins averaged $0.922 and $0.471 per gallon for the three months ended September 30, 2011 and 2010, and $0.872 and $0.534 per gallon for the nine months ended September 30, 2011 and 2010, respectively. The average standardized processing margin for the period from January 1, 1989 through September 30, 2011 is $0.191 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 for 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.

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	Quarterly Data for Oklahoma
	Q1 2010		Q2 2010		Q3 2010		Q4 2010		Q1 2011		Q2 2011		Q3 2011
CenterPoint East ($/MMBtu)	$	5.22	$	3.86	$	4.14	$	3.53	$	3.93	$	4.14	$	4.05
Conway ($/Bbl)	$	44.44	$	36.34	$	36.53	$	43.91	$	46.36	$	50.17	$	49.21
NYMEX crude oil ($/Bbl)	$	78.72	$	78.03	$	76.20	$	85.17	$	94.10	$	102.56	$	89.76
Service throughput (MMBtu/d)		248,784		259,972		270,184		267,353		269,550		283,870		288,440
Plant inlet (MMBtu/d)		152,190		156,204		156,676		154,257		147,710		157,424		158,070
NGLs produced (Bbls/d)		15,334		16,653		16,541		16,480		16,037		17,331		17,453
Segment gross margin (in thousands)	$	24,275	$	21,821	$	23,010	$	24,511	$	23,082	$	28,665	$	27,876

The first-of-the-month price for natural gas on the CenterPoint East index was $3.58 per MMBtu for October 2011 and the spot price was $3.47 per MMBtu on October 31, 2011. The weighted-average daily price for NGLs at Conway for October 2011, based on our third quarter 2011 product mix, was $45.29 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 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 third quarter of 2011 reflected a substantial increase in the average basis differential between Mont Belvieu and Conway, which was $9.00 per Bbl as compared to $6.91 per Bbl for the second quarter of 2011. Prices for purity ethane accounted for 56% of this basis differential. For October 2011, the basis differential averaged $12.85 per Bbl. The average basis differential between Houston Ship Channel and CenterPoint East natural gas index prices was $0.18 per MMBtu for the third quarter of 2011, and was $0.08 per MMBtu for October 2011.

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

Mont Belvieu — Conway Basis⁽¹⁾

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

Pricing Trends in the Rocky Mountains.  The following graph and table summarize prices for natural gas on Colorado Interstate Gas, 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		Q3 2011
Colorado Interstate Gas ($/MMBtu)	$	5.14	$	3.61	$	3.50	$	3.42	$	3.83	$	3.98	$	3.91
Pipeline throughput (MMBtu/d)(1)		931,319		900,047		913,730		886,568		581,051		533,329		670,543	(3)
Segment gross margin (in thousands)(2)	$	1,103	$	1,148	$	1,091	$	1,098	$	1,042	$	771	$	432

(1)	Includes 100% of Bighorn and Fort Union volumes, but does not reflect an additional 288,966 MMBtu/d, 327,894 MMBtu/d and 223,557 MMBtu/d of additional long-term contractually committed volumes that Fort Union did not gather but which were the basis of payments received by Fort Union in the first, second and third quarters of 2011, respectively.
(2)	Excludes results and volumes associated with our equity interests in Bighorn and Fort Union.
(3)	Fort Union volumes increased during the third quarter of 2011 following a temporary force majeure event on TransCanada’s Bison pipeline.

The first-of-the-month price for natural gas on the Colorado Interstate Index was $3.56 per MMBtu for October 2011 and the spot price was $3.42 per MMBtu on October 31, 2011.

Third Quarter 2011 Drilling and Production Activity.

•  Drilling.  Drilling activity in the third quarter remained very strong 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 were consistent with the first two quarters of 2011. Drilling activity in the Mississippi Lime

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area in north central Oklahoma and southern Kansas has increased as producers further explore the play. 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 third quarter of 2011 increased 11% compared to the second quarter of 2011. In Texas, volume increases reflected a 25% increase in Eagle Ford Shale volumes (including volumes from Eagle Ford Gathering that began flowing in August 2011, and offset by lower volumes on our DK pipeline due to expiration of a temporary arrangement for interruptible service), a 41% increase in north Barnett Shale Combo volumes on our Saint Jo system and a 22% increase in third-party pipeline volumes we received from Kinder Morgan at our Houston Central complex, offset by decreases on our other systems due to natural production declines around these systems. Volumes in Oklahoma were consistent with second-quarter volumes, as increases in the Woodford Shale and Mississippi Lime volumes offset natural production declines in other Oklahoma fields in which we operate. In the Rocky Mountains, Fort Union volumes were up 36% following a temporary force majeure event on TransCanada’s Bison Pipeline, during which a portion of Bison’s volumes were diverted to Fort Union. Volumes on Bighorn declined 3% due to limited drilling activity in the Powder River Basin.

•  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 continue to evaluate 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 fractionation capacity and 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.

We believe a lack of infrastructure also is among the factors contributing to the recent widening basis spread between Conway and Mont Belvieu. Mont Belvieu prices, particularly for ethane, have been supported by strong demand from the petrochemical market along the Gulf Coast. At the same time, Conway NGL prices have declined as insufficient takeaway capacity has resulted in an oversupply in the region.

We expect that over the next two years, the effects of these capacity constraints will be moderated by new fractionation facilities and NGL transportation infrastructure, including new NGL pipelines linking the Mid-Continent to the Gulf Coast.

In the near term, these effects could limit the benefits producers receive from rich gas production and could affect the level of drilling and well completion activity in some rich gas plays. In addition, activity in the Eagle Ford Shale could ultimately be impacted by insufficient demand and storage capacity for residue gas and natural gas liquids as well as by a shortage of required resources, such as water used in hydraulic fracturing.

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Factors Affecting Operating Results and Financial Condition

Our results for the third quarter reflect modest declines in natural gas and NGL prices and a temporary reduction in NGL volumes at our Houston Central complex due to downstream liquids-handling constraints. Houston Central NGL volumes were curtailed during the quarter due to a turnaround at Formosa’s Point Comfort facility and a shut-down of our propane line to Dow for scheduled maintenance. These factors offset the benefits of natural gas volume growth due to strong drilling activity and the start-up of Eagle Ford Gathering’s pipeline. We expect that liquids-handling constraints will continue to be a factor in the fourth quarter but will be largely resolved before the end of the year.

For the three months ended September 30, 2011, we recorded a $120.0 million non-cash impairment charge relating to our investment in Bighorn, a $45.0 million non-cash impairment charge relating to our investment in Fort Union and a $5.0 million non-cash impairment charge relating to a contract under which we provide services to Rocky Mountains producers. We determined that these charges were necessary primarily based on a downward shift in the Colorado Interstate Gas forward price curve and our expectations of a continued weak outlook for Rocky Mountains natural gas prices and, as producers focus more on rich-gas and shale plays, a continued lack of drilling activity in Wyoming’s Powder River Basin.

Higher NGL and crude oil prices in 2011 combined with lower strike prices on our commodity derivative instruments reduced our cash flow from commodity hedge settlements. Also, a substantial widening of the Conway-Mont Belvieu basis differential limited the effectiveness of our derivative instruments for hedging Oklahoma NGLs. For the first nine months of 2011, we paid $7.7 million in net cash settlements from our commodity hedge portfolio, compared to receiving $27.6 million in net cash settlements for the first nine 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: (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.

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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) 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 of 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 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.

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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 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. The reconciliation of the non-GAAP financial measures for the three and nine months ended September 30, 2010 have been recast to conform with the revised calculation to allow for direct comparisons to current year activity.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	($ In thousands)
Reconciliation of total segment gross margin to operating (loss) income:
Operating (loss) income	$	(146,282	)	$	20,546		$	(109,752	)	$	26,767
Add: Operations and maintenance expenses		16,091			13,004			46,953			38,337
Depreciation, amortization and impairment		21,911			15,218			56,143			46,002
General and administrative expenses		10,031			9,869			34,530			31,311
Taxes other than income		1,502			1,315			4,029			3,658
Equity in loss (earnings) from unconsolidated affiliates		161,589			(2,049	)		158,581			19,788
Total segment gross margin	$	64,842		$	57,903		$	190,484		$	165,863
Reconciliation of EBITDA, adjusted EBITDA and total distributable cash flow to net (loss) income:
Net (loss) income	$	(157,736	)	$	7,298		$	(163,565	)	$	(15,073	)
Add: Depreciation, amortization and impairment		21,911			15,218			56,143			46,002
Interest and other financing costs		11,080			12,943			34,450			41,239
Provision for income taxes		390			320			1,161			660
EBITDA		(124,355	)		35,779			(71,811	)		72,828
Add: Amortization of commodity derivative options		7,442			8,163			22,069			24,211
Distributions from unconsolidated affiliates		6,757			6,563			20,329			19,554
Loss on refinancing of unsecured debt		—			—			18,233			—
Equity-based compensation		2,093			2,448			9,184			7,849
Equity in loss (earnings) from unconsolidated affiliates		161,589			(2,049	)		158,581			19,788
Unrealized (gain) loss from commodity risk management activities		(2,332	)		389			(2,695	)		150
Other non-cash operating items		576			(295	)		(272	)		1,933
Adjusted EBITDA		51,770			50,998			153,618			146,313
Less: Interest expense		(11,029	)		(11,856	)		(33,623	)		(39,171	)
Current income tax expense and other		(305	)		(141	)		(929	)		(740	)
Maintenance capital expenditures		(3,510	)		(3,290	)		(11,111	)		(6,370	)
Total distributable cash flow	$	36,926		$	35,711		$	107,955		$	100,032

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

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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, 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			Q3 2011
Fee-based		27	%		33	%		37	%		38	%		41	%		41	%		43	%
Percentage-of-proceeds(1)		39	%		31	%		30	%		32	%		32	%		33	%		31	%
Keep-whole and other(2)		36	%		33	%		29	%		34	%		39	%		40	%		36	%
Net hedging(3)		(2	)%		3	%		4	%		(4	)%		(12	)%		(14	)%		(10	)%

(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

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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;

•  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 Securities and Exchange Commission (“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 and under Item 1A, “Risk Factors” in our Quarterly Report on Form 10-Q for the three and six months ended June 30, 2011. 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						Nine Months Ended
	September 30,						September 30,
	2011			2010			2011			2010
	($ In thousands)
Total segment gross margin(1)	$	64,842		$	57,903		$	190,484		$	165,863
Operations and maintenance expenses		16,091			13,004			46,953			38,337
Depreciation, amortization and impairment		21,911			15,218			56,143			46,002
General and administrative expenses		10,031			9,869			34,530			31,311
Taxes other than income		1,502			1,315			4,029			3,658
Equity in loss (earnings) from unconsolidated affiliates(2)		161,589			(2,049	)		158,581			19,788
Operating (loss) income		(146,282	)		20,546			(109,752	)		26,767
Loss on refinancing of unsecured debt		—			—			(18,233	)		—
Interest and other financing costs, net		(11,064	)		(12,928	)		(34,419	)		(41,180	)
Provision for income taxes		(390	)		(320	)		(1,161	)		(660	)
Net (loss) income		(157,736	)		7,298			(163,565	)		(15,073	)
Preferred unit distributions		(8,279	)		(7,500	)		(24,235	)		(7,500	)
Net loss to common units	$	(166,015	)	$	(202	)	$	(187,800	)	$	(22,573	)
Basic and diluted net loss per common unit	$	(2.51	)	$	—		$	(2.84	)	$	(0.36	)
Weighted average number of common units		66,246			65,658			66,125			63,193
Total segment gross margin:
Texas	$	44,540		$	31,218		$	135,685		$	90,134
Oklahoma		27,876			23,010			79,623			69,106
Rocky Mountains(3)		432			1,091			2,245			3,342
Segment gross margin		72,848			55,319			217,553			162,582
Corporate and other(4)		(8,006	)		2,584			(27,069	)		3,281
Total segment gross margin(1)	$	64,842		$	57,903		$	190,484		$	165,863
Segment gross margin per unit:
Texas:
Service throughput ($/MMBtu)	$	0.63		$	0.58		$	0.71		$	0.57
Oklahoma:
Service throughput ($/MMBtu)	$	1.05		$	0.93		$	1.04		$	0.97
Volumes:
Texas:(5)
Service throughput (MMBtu/d)(6)		765,744			590,116			694,802			577,678
Pipeline throughput (MMBtu/d)		463,321			319,538			436,210			321,450
Plant inlet volumes (MMBtu/d)		686,398			516,949			612,405			481,285
NGLs produced (Bbls/d)		30,904			19,685			27,040			17,818
Oklahoma:(7)
Service throughput (MMBtu/d)(6)		288,440			270,184			286,320			259,710
Plant inlet volumes (MMBtu/d)		158,070			156,676			160,737			156,771
NGLs produced (Bbls/d)		17,453			16,541			17,498			16,180
Capital Expenditures:
Maintenance capital expenditures	$	3,510		$	3,290		$	11,111		$	6,370
Expansion capital expenditures		82,675			29,290			203,576			101,232
Total capital expenditures	$	86,185		$	32,580		$	214,687		$	107,602
Operations and maintenance expenses:
Texas	$	9,082		$	6,779		$	26,815		$	20,845
Oklahoma		6,930			6,163			19,943			17,266
Rocky Mountains		79			62			195			226
Total operations and maintenance expenses	$	16,091		$	13,004		$	46,953		$	38,337

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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 unconsolidated affiliates. The following table summarizes the throughput for the periods indicated:

		Three Months Ended				Nine Months Ended
		September 30,				September 30,
		2011		2010		2011		2010
Bighorn and Fort Union(a)	MMBtu/d		670,543		913,730		595,302		914,967
Southern Dome
Plant inlet	MMBtu/d		11,970		12,338		11,630		13,046
NGLs produced	Bbls/d		429		444		418		466
Webb Duval(b)	MMBtu/d		48,628		53,668		48,705		56,145
Eagle Ford Gathering	MMBtu/d		58,295		—		58,295		—
Liberty Pipeline Group	Bbls/d		4,252		—		4,252		—

(a)

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. Fort Union volumes do not reflect an additional 223,557 MMBtu/d and 279,918 MMBtu/d in long-term contractually committed volumes that Fort Union did not gather but which were the basis of payments received by Fort Union for the three and nine months ended September 30, 2011, respectively.

(b)

Net of intercompany volumes.

(3)	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.
(4)	Corporate and other includes results attributable to our commodity risk management activities.
(5)	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.
(6)	“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.
(7)	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.

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

Texas Segment Gross Margin.  Texas segment gross margin was $44.5 million for the three months ended September 30, 2011 compared to $31.2 million for the three months ended September 30, 2010, an increase of $13.3 million, or 43%, reflecting 48% higher NGL prices and an increase in revenue associated with fee-based contracts, including $0.7 million in deficiency fees receivable on volumes committed to us by producers but not delivered. Texas segment gross margin per unit of service throughput increased $0.05 per MMBtu to $0.63 per MMBtu for the three months ended September 30, 2011 compared to $0.58 per MMBtu for the three months ended September 30, 2010. The Texas segment gross margin also benefited from increases in gathering, NGL production and processed volumes of 45%, 57% and 33%, respectively, during the three months ended September 30, 2011 as compared to the three months ended September 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.

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Oklahoma Segment Gross Margin.  Oklahoma segment gross margin was $27.9 million for the three months ended September 30, 2011 compared to $23.0 million for the three months ended September 30, 2010, an increase of $4.9 million, or 21%. The increase in segment gross margin was primarily due to a period-over-period increase in NGL prices of 35% partially offset by a decrease in average natural gas prices of 2%. 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 during the three months ended September 30, 2011 as compared to the three months ended September 30, 2010. Oklahoma segment gross margin also increased because of increases in service throughput, NGL production and of total plant inlet volumes of 7%, 6% and 1% as a result of volume growth from the Woodford Shale and increased activity at the Harrah plant, respectively, during the three months ended September 30, 2011 as compared to the three months ended September 30, 2010. The Oklahoma segment gross margin per unit of service throughput also increased $0.12 per MMBtu to $1.05 per MMBtu for the three months ended September 30, 2011 compared to $0.93 per MMBtu for the three months ended September 30, 2010.

Rocky Mountains Segment Gross Margin.  Rocky Mountains segment gross margin was $0.4 million for the three months ended September 30, 2011 compared to $1.1 million for the three months ended September 30, 2010, a decrease of $0.7 million, or 64%. This decrease is primarily the result of decreased volumes from Bighorn and increased demand fees we paid under our existing firm gathering agreements with Fort Union. As a result of production declines in the area, we are unable to utilize all of our demand capacity on Fort Union.

Corporate and Other.  Corporate and other includes our commodity risk management activities and was a loss of $8.0 million for the three months ended September 30, 2011 compared to a gain of $2.6 million for the three months ended September 30, 2010. The loss for the three months ended September 30, 2011 included $7.4 million of non-cash amortization expense relating to the option component of our commodity derivative instruments and $2.9 million of net cash settlements paid on expired commodity derivative instruments offset by $2.3 million of unrealized gains on our commodity derivative instruments. The gain for the three months ended September 30, 2010 included $11.1 million of net cash settlements received on expired commodity derivative instruments partially offset by $8.2 million of non-cash amortization expense relating to the option component of our commodity derivative instruments and $0.3 million of unrealized mark-to-market losses on our commodity derivative instruments.

Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $16.1 million for the three months ended September 30, 2011 compared to $13.0 million for the three months ended September 30, 2010. The 24% increase is attributable primarily to (i) increased payroll, utilities, chemicals and repair and maintenance expenses in our Texas segment of $2.3 million, including expenses for expanded operations related to new Eagle Ford Shale assets and repairs at the Saint Jo plant, and (ii) increased payroll, operating costs for new compressors, fuel, utilities and supplies expenses in our Oklahoma segment of $0.8 million, including expenses for the operations of the Harrah plant acquired in April 2011.

Depreciation, Amortization and Impairment.  Depreciation, amortization and impairment totaled $21.9 million for the three months ended September 30, 2011 compared with $15.2 million for the three months ended September 30, 2010, an increase of 44%. This increase relates primarily to a $5.0 million non-cash impairment on a contract under which we provide services to Rocky Mountains producers. There was also additional depreciation and amortization resulting from capital expenditures made after September 30, 2010, including expenditures relating the expansion of our Saint Jo plant, the construction of our DK pipeline, the acquisition of the Harrah plant and the installation of two compressor stations in Oklahoma in the fourth quarter of 2010.

General and Administrative Expenses.  General and administrative expenses totaled $10.0 million for the three months ended September 30, 2011 compared to $9.9 million for the three months ended September 30, 2010. The 1% increase consists primarily of (i) increases in personnel, compensation and benefits costs of $0.6 million, partially offset by (i) a decrease of $0.3 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 and (ii) a reduction in expenses for acquisition initiatives that were not consummated of $0.2 million.

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Equity in Loss/Earnings from Unconsolidated Affiliates.  Equity in loss from unconsolidated affiliates totaled $161.6 million for the three months ended September 30, 2011 compared to earnings of $2.0 million for the three months ended September 30, 2010. The decrease consists primarily of non-cash impairment expense of $165.0 million on our investments in Bighorn and Fort Union, primarily based on a downward shift in the Colorado Interstate Gas forward price curve and our expectations of a continued weak outlook for Rocky Mountains natural gas prices and drilling activity in Wyoming’s Powder River Basin, partially offset by equity earnings of $2.0 million from Eagle Ford Gathering, which began limited service during the three months ended September 30, 2011. Equity in earnings from unconsolidated affiliates for the three months ended September 30, 2010 consisted of $2.2 million of equity earnings from Fort Union and $0.6 million of equity earnings from Southern Dome offset by $0.6 million of equity loss from Bighorn.

Interest and Other Financing Costs.  Interest and other financing costs totaled $11.1 million for the three months ended September 30, 2011 compared to $12.9 million for the three months ended September 30, 2010, a decrease of $1.8 million, or 14%. The decrease in interest and other financing costs resulted from (i) $2.0 million of additional capitalized interest costs related to the construction of expansion capital projects and (ii) $1.0 million decrease in unrealized mark-to-market gains on undesignated interest rate swaps partially offset by a $1.2 million increase in interest expense on our revolving credit facility and senior notes. Average borrowings under our credit arrangements for the three months ended September 30, 2011 and 2010 were $863.2 million and $621.3 million, respectively, with average interest rates of 6.9% and 8.9%, respectively. Please read “— Liquidity and Capital Resources — Our Indebtedness.”

Nine Months Ended September 30, 2011 Compared To Nine Months Ended September 30, 2010

Texas Segment Gross Margin.  Texas segment gross margin was $135.7 million for the nine months ended September 30, 2011 compared to $90.1 million for the nine months ended September 30, 2010, an increase of $45.6 million, or 51%, reflecting 30% higher NGL prices, a $10.1 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 $5.9 million in deficiency fees receivable on volumes committed to us but not delivered. Texas segment gross margin per unit of service throughput increased $0.14 per MMBtu to $0.71 per MMBtu for the nine months ended September 30, 2011 compared to $0.57 per MMBtu for the nine months ended September 30, 2010. The Texas segment gross margin also benefited from increases in gathering, NGL production and processed volumes of 36%, 52% and 27%, respectively, during the nine months ended September 30, 2011 compared to the nine months ended September 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 Saint Jo plant in the north Barnett Shale Combo play.

Oklahoma Segment Gross Margin.  Oklahoma segment gross margin was $79.6 million for the nine months ended September 30, 2011 compared to $69.1 million for the nine months ended September 30, 2010, an increase of $10.5 million, or 15%. The increase in segment gross margin was primarily due to a period-over-period increase in NGL prices of 25% offset by a decrease in average natural gas prices of 8%. The segment gross margin also benefited from the April 1, 2011 acquisition of the Harrah plant which added an additional $2.9 million of gross margin during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. Oklahoma segment gross margin also increased because of increases in service throughput, NGL production and total plant inlet volumes of 10%, 8% and 3% as a result of volume growth from the Woodford Shale and increased activity at the Harrah and Burbank plants, respectively, during the nine months ended September 30, 2011 as compared to the nine months ended September 30, 2010. The Oklahoma segment gross margin per unit of service throughput increased $0.07 per MMBtu to $1.04 per MMBtu for the nine months ended September 30, 2011 compared to $0.97 per MMBtu for the nine months ended September 30, 2010.

Rocky Mountains Segment Gross Margin.  Rocky Mountains segment gross margin was $2.2 million for the nine months ended September 30, 2011 compared to $3.3 million for the nine months ended September 30, 2010, a decrease of $1.1 million, or 33%. This decrease is primarily the result of decreased production from Bighorn and increased demand fees we paid under our existing firm gathering agreements with Fort Union. As a result of production declines in the area, we are unable to utilize all of our demand capacity on Fort Union.

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Corporate and Other.  Corporate and other includes our commodity risk management activities and was a loss of $27.1 million for the nine months ended September 30, 2011 compared to a gain of $3.3 million for the nine months ended September 30, 2010. The loss for the nine months ended September 30, 2011 included $22.1 million of non-cash amortization expense relating to the option component of our commodity derivative instruments and $7.7 million of net cash settlements paid on expired commodity derivative instruments partially offset by $2.7 million of unrealized gain on our commodity derivative instruments. The gain for the nine months ended September 30, 2010 included $27.6 million of net cash settlements received on expired commodity derivative instruments offset by $24.2 million of non-cash amortization expense relating to the option component of our commodity derivative instruments and $0.1 million of unrealized mark-to-market losses on our commodity derivative instruments.

Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $47.0 million for the nine months ended September 30, 2011 compared to $38.3 million for the nine months ended September 30, 2010. The 23% increase is attributable primarily to (i) increased payroll, utilities, chemicals and repair and maintenance expenses in our Texas segment of $6.0 million, including expenses for expanded operations related to new Eagle Ford Shale assets and repairs at our Saint Jo plant and (ii) increased payroll, operating costs for new compressors, fuel, utilities and supplies expenses in our Oklahoma segment of $2.7 million, including expenses for the operations of the Burbank and Harrah plants acquired in April 2010 and April 2011, respectively.

Depreciation, Amortization and Impairment.  Depreciation, amortization and impairment totaled $56.1 million for the nine months ended September 30, 2011 compared with $46.0 million for the nine months ended September 30, 2010, an increase of 22%. This increase relates primarily to a $5.0 million non-cash impairment with respect to a contract under which we provide services to Rocky Mountains producers as well as additional depreciation and amortization resulting from capital expenditures made after September 30, 2010, including expenditures relating to the fractionation facility at our Houston Central complex, the expansion of our Saint Jo plant, acquisition 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 $34.5 million for the nine months ended September 30, 2011 compared to $31.3 million for the nine months ended September 30, 2010. The 10% increase consists primarily of (i) increases in personnel, compensation and benefits costs of $2.3 million, (ii) an increase of $0.9 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) an increase in costs of preparing and processing tax forms (Schedule K-1s) for unitholders of $0.3 million and (iv) an increase in expenses for acquisition initiatives that were not consummated totaling $0.3 million offset by (i) a $0.6 million increase in management fees received from our unconsolidated affiliates, primarily Eagle Ford Gathering.

Equity in Loss/Earnings from Unconsolidated Affiliates.  Equity in loss from unconsolidated affiliates totaled $158.6 million for the nine months ended September 30, 2011 compared to $19.8 million for the nine months ended September 30, 2010. The increase in equity loss consists primarily of a non-cash impairment of $165.0 million relating to our investments in Bighorn and Fort Union, primarily based on a downward shift in the Colorado Interstate Gas forward price curve and our expectations of a continued weak outlook for Rocky Mountains natural gas prices and drilling activity in Wyoming’s Powder River Basin, partially offset by increased equity earnings from our investment in Eagle Ford Gathering. During the nine months ended September 30, 2010, equity in loss from unconsolidated affiliates included a $25 million non-cash impairment relating to our investment in Bighorn partially offset by equity earnings from Fort Union of $5.7 million.

Interest and Other Financing Costs.  Interest and other financing costs totaled $34.5 million for the nine months ended September 30, 2011 compared to $41.2 million for the nine months ended September 30, 2010, a decrease of $6.7 million, or 16%. The decrease in interest and other financing costs resulted from (i) $4.7 million of additional capitalized interest costs related to the construction of expansion capital projects, (ii) a $1.3 million decrease in unrealized mark-to-market gains on undesignated interest rate swaps and (iii) a $1.3 million decrease in interest rate swap settlements, offset by (i) an increase in interest expense on our revolving credit facility and senior notes of $0.4 million and (ii) a $0.1 million increase in the amortization of debt issue costs. Average borrowings

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under our credit arrangements for the nine months ended September 30, 2011 and 2010 were $754.4 million and $724.6 million, respectively, with average interest rates of 7.6% and 8.0%, 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.

	Nine Months Ended
	September 30,
	2011			2010
	(In thousands)
Net cash provided by operating activities	$	122,789		$	94,489
Net cash used in investing activities		(299,114	)		(111,596	)
Net cash provided by financing activities		169,929			74,196

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 $122.8 million for the nine months ended September 30, 2011 compared to $94.5 million for the nine months ended September 30, 2010. The increase in cash provided by operating activities of $28.3 million was attributable to the following changes:

•  a $10.3 million increase in cash flow provided by operating activities in 2011 compared with the same period in 2010;

•  a $1.0 million increase in cash distributions received from our unconsolidated affiliates in 2011 compared to the same period in 2010;

•  a $16.5 million decrease in interest payments in 2011 compared to the same period in 2010 as a result of the timing of our interest payments and increased capitalized interest; and

•  a $0.5 million decrease in cash flow used for risk management activities for 2011 as compared to 2010.

Investing Cash Flows.  Net cash used in investing activities was $299.1 million and $111.6 million for the nine months ended September 30, 2011 and 2010, respectively. Investing activities for the nine months ended September 30, 2011 included (i) $196.4 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) $105.1 million of investments in Eagle Ford Gathering, Liberty Pipeline Group, Webb Duval and Bighorn, offset by $2.4 million of distributions from Bighorn and Southern Dome in excess of equity earnings. Investing activities for the nine months ended September 30, 2010 included (i) $103.5 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) $11.2 million of investments in Eagle Ford Gathering, Bighorn and Fort Union offset by (i) $2.6 million of distributions from Bighorn and Southern Dome in excess of equity earnings and (ii) other investing activities of $0.5 million.

Financing Cash Flows.  Net cash provided by financing activities totaled $169.9 million during the nine months ended September 30, 2011 and included (i) net borrowings under our revolving credit facility of $285.0 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 $2.7 million offset by (i) distributions to our unitholders of $114.8 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 $15.8 million. Net cash provided by financing activities totaled $74.2 million during the nine months ended September 30, 2010 and included (i) proceeds from

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the placement of Series A convertible preferred units net of underwriting discounts and commissions and fees of $285.3 million, (ii) 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 $164.3 million and (iii) proceeds from the exercise of unit options of $3.2 million offset by (i) net repayments under our revolving credit facility of $270.0 million, (ii) distributions to our unitholders of $107.6 million and (iii) deferred financing costs of $1.0 million.

Liquidity and Capital Resources

Sources of Liquidity.  Cash generated from operations (including distributions from our unconsolidated affiliates), 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 commodity derivatives in late 2010, and in the first, third and fourth quarters of 2011 to hedge against potential future declines in commodity prices.

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.

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.  Our business is 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

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lives, or other capital expenditures that are incurred in maintaining existing system volumes and related cash flows; and

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

During the nine months ended September 30, 2011, our capital expenditures totaled $214.7 million, consisting of $11.1 million of maintenance capital and $203.6 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 and cryogenic processing upgrade 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 $75.2 million in expansion capital expenditures in 2011 to complete these projects and to enhance the capabilities and capacities of our current asset base. Based on our current scope of operations, we anticipate incurring approximately $12 million to $14 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 nine months ended September 30, 2011, our capital contributions to our unconsolidated affiliates totaled $105.1 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 of approximately $33.0 million to Eagle Ford Gathering for completion of the pipeline and crossover projects, $1.7 million to Bighorn for a compression and pipeline project and $0.2 million to Liberty Pipeline Group for completion of the NGL pipeline project.

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)			In-Service Date
Houston Central fractionation expansion		—		—		22,000			44,000	$	42		Fourth Quarter 2011
Houston Central cryogenic upgrade		—		—		200,000(5	)		—	$	21		First Quarter 2012
Houston Central processing expansion		—		—		700,000			1,100,000	$	145		First Quarter 2013
DK pipeline extension		59		24”		195,000			303,000	$	100		Fourth Quarter 2011
Eagle Ford Gathering(2)
Initial pipeline		117		24”- 30”		325,000			—	$	175(4	)	Fourth Quarter 2011
Crossover project		66		20”- 24”		176,000			—	$	100(4	)	Fourth Quarter 2011
Interconnect to Markham plant		5		20”		200,000			—	$	27(4	)	Fourth Quarter 2011
Liberty NGL pipeline(3)		87		12”		75,000			—	$	60(4	)	Fourth 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.
(4)	Joint venture project costs presented are gross amounts; our share of such costs is 50%.
(5)	Upgrade increases the efficiency of existing 200,000 Mcf/d cryogenic facility at Houston Central complex

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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)	$	38,705	$	154,821

(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 October 31, 2011, we had 43,300 outstanding restricted units and 990,111 outstanding phantom units.

Our Indebtedness

As of September 30, 2011, our aggregate outstanding indebtedness totaled $904.5 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 revolving 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).

•  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 September 30, 2011, we had $295.0 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 September 30, 2011, our consolidated leverage ratio was 3.98 to 1.0.

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•  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 September 30, 2011, our senior secured leverage ratio was 1.32 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 September 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 amended credit agreement, at September 30, 2011, we could borrow an additional $291 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 September 30, 2011, our ratio of consolidated cash flow to fixed charges was 3.85 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 September 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.

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-

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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 $0.1 million to our total segment gross margin for the nine months ended September 30, 2011. We also calculated that a $0.10 per MMBtu increase in the price of natural gas would have resulted in a $0.9 million decrease to our total segment gross margin, and vice versa, for the nine months ended September 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 nine 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 September 30, 2011, our commodity hedge portfolio totaled a net asset of $26.5 million, which consists of assets aggregating $29.2 million less liabilities aggregating $2.7 million. For additional information, please read Note 11, “Financial Instruments,” 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

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(1)	$	0.5300		1,700	$	—		—
2011	$	0.5300		500	$	0.5450		500
2011	$	0.6200		500	$	—		—
2011	$	0.5500		500	$	—		—
2012	$	0.5900		1,000	$	—		—
2012	$	0.5900		500
2012(2)	$	0.6700		400	$	—		—

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

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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)	$	1.1500		700	$	—		—
2012	$	1.0700		600	$	—		—
2012	$	1.1700		600	$	—		—
2012	$	1.3200		400	$	—		—
2013	$	1.2400		600	$	—		—
2013	$	1.2750		350	$	—		—

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

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		315	$	—		—
2012(1)	$	1.3900		135
2013	$	1.6000		200	$	—		—
2013	$	1.6800		100	$	—		—

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

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		125	$	—		—
2012(1)	$	1.3600		225
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.

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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(1)	$	79.00		300
2012	$	83.00		500
2012(1)	$	83.00		150
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.

Interest Rate Swaps.  As of September 30, 2011, the fair value of our interest rate swaps liability totaled $4.6 million. For additional information on our interest rate swaps, please read Note 11, “Financial Instruments,” 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 nine months ended September 30, 2011, ONEOK Hydrocarbons, L.P. (19%), Dow Hydrocarbon and Resources LLC, (15%), ONEOK Energy Services, L.P. (12%), Enterprise Products Operating, L.P. (9%) and Kinder Morgan (7%) collectively accounted for approximately 62% of our revenue. As of September 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 27% 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.

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We also diligently review the creditworthiness of other counterparties to which we may have credit exposure, including hedge counterparties. Our risk management policy requires that we review and report the credit ratings of our hedging counterparties on a monthly basis. As of September 30, 2011, the value of our commodity net hedge positions by counterparty consisted of assets with JP Morgan (23%), Scotia Capital (21%), Wells Fargo (15%), Barclays Bank PLC (15%), Credit Suisse (13%) and Goldman Sachs (13%). As of September 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 September 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 September 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 and under Part II, Item 1A, “Risk Factors,” in our Quarterly Report on Form 10-Q for the three and six months ended June 30, 2011. These risks and uncertainties could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be materially adversely affected.

Item 6.   Exhibits.

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

Number			Description
	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).
	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).

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Number			Description
	4	.8	Form of Global Note representing 7.125% Senior Notes due 2021 (included in Exhibit A to Exhibit 4.5 above).
	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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized, in the City of Houston, State of Texas, on November 4, 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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