UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2012

OR

¨ 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	51-0411678
(State or Other Jurisdiction of Incorporation or Organization)	(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  x    No  ¨

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).

x  Yes    ¨  No

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

Large accelerated filer  x Accelerated filer  ¨ Non-accelerated filer  ¨ Smaller reporting company  ¨

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

There were 72,237,243 common units of Copano Energy, L.L.C. outstanding on May 4, 2012. Copano Energy, L.L.C.’s common units trade on the NASDAQ stock exchange under the symbol “CPNO.”

TABLE OF CONTENTS

		Page
	PART I—FINANCIAL INFORMATION
Item 1.	Financial Statements		3
	Unaudited Consolidated Balance Sheets as of March 31, 2012 and December 31, 2011		3
	Unaudited Consolidated Statements of Operations for the Three Months Ended March 31, 2012 and 2011		4
	Unaudited Consolidated Statements of Comprehensive Income (Loss) for the Three Months Ended March 31, 2012 and 2011		5
	Unaudited Consolidated Statements of Cash Flows for the Three Months Ended March 31, 2012 and 2011		6
	Unaudited Consolidated Statements of Members’ Capital for the Three Months Ended March 31, 2012 and 2011		7
	Notes to Unaudited Consolidated Financial Statements		8
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		46
Item 4.	Controls and Procedures		49
	PART II—OTHER INFORMATION
Item 1.	Legal Proceedings		50
Item 1A.	Risk Factors		50
Item 6.	Exhibits		51

2

Item 1. Financial Statements.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

	March 31,			December 31,
	2012			2011
	(In thousands, except unit information)
ASSETS
Current assets:
Cash and cash equivalents	$	58,337		$	56,962
Accounts receivable, net (1)		131,013			119,193
Risk management assets		4,564			4,322
Prepayments and other current assets		3,660			5,114
Total current assets		197,574			185,591
Property, plant and equipment, net		1,137,370			1,103,699
Intangible assets, net		161,696			192,425
Investments in unconsolidated affiliates		438,649			544,687
Escrow cash		1,848			1,848
Risk management assets		4,447			6,452
Other assets, net		30,525			29,895
Total assets	$	1,972,109		$	2,064,597
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable (1)	$	138,639		$	155,921
Accrued interest		24,754			8,686
Accrued tax liability		1,511			1,182
Risk management liabilities		2,736			3,565
Other current liabilities		23,352			22,040
Total current liabilities		190,992			191,394
Long term debt (includes $3,330 and $0 bond premium as of March 31, 2012 and December 31, 2011, respectively)		897,855			994,525
Deferred tax liability		2,472			2,199
Other noncurrent liabilities		4,837			4,581
Commitments and contingencies (Note 9)
Members’ capital:
Series A convertible preferred units, no par value, 11,976,175 units and 11,684,074 units issued and outstanding as of March 31, 2012 and December 31, 2011, respectively		285,168			285,168
Common units, no par value, 72,228,365 units and 66,341,458 units issued and outstanding as of March 31, 2012 and December 31, 2011, respectively		1,353,334			1,164,853
Paid in capital		67,503			62,277
Accumulated deficit		(813,728	)		(624,121	)
Accumulated other comprehensive loss		(16,324	)		(16,279	)
		875,953			871,898
Total liabilities and members’ capital	$	1,972,109		$	2,064,597

(1) Inclusive of related party transactions discussed in Note 8.

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 March 31,
	2012			2011
	(In thousands, except per unit information)
Revenue:
Natural gas sales (1)	$	86,212		$	103,795
Natural gas liquids sales		195,187			149,001
Transportation, compression and processing fees (1)(2)		39,839			24,471
Condensate and other (1)		15,990			12,658
Total revenue		337,228			289,925
Costs and expenses:
Cost of natural gas and natural gas liquids(1)(3)(4)		265,951			223,730
Transportation (1)(4)		6,449			5,849
Operations and maintenance		18,642			15,099
Depreciation and amortization		19,088			16,869
Impairment		28,744			—
General and administrative (1)		14,944			12,598
Taxes other than income		1,366			1,130
Equity in loss (earnings) from unconsolidated affiliates		114,728			(1,702	)
Total costs and expenses		469,912			273,573
Operating (loss) income		(132,684	)		16,352
Other income (expense):
Interest and other income		38			7
Interest and other financing costs		(14,424	)		(11,916	)
(Loss) income before income taxes		(147,070	)		4,443
Provision for income taxes		(601	)		(911	)
Net (loss) income		(147,671	)		3,532
Preferred unit distributions		(8,698	)		(7,880	)
Net loss to common units	$	(156,369	)	$	(4,348	)
Basic and diluted net loss per common unit	$	(2.20	)	$	(0.07	)
Weighted average number of common units		70,960			65,985
Distributions declared per common unit	$	0.575		$	0.575

(1) Inclusive of related party transactions discussed in Note 8.

(2) Inclusive of affiliate transactions totaling $2,002 and $2 for the three months ended March 31, 2012 and 2011, respectively.

(3) Inclusive of affiliate transactions totaling $25,029 and $5 for the three months ended March 31, 2012 and 2011, respectively.

(4) Exclusive of operations and maintenance, depreciation and 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 COMPREHENSIVE INCOME (LOSS)

	Three Months Ended March 31,
	2012			2011
	(In thousands)
Net (loss) income	$	(147,671	)	$	3,532
Other comprehensive (loss) income:
Derivative settlements reclassified to income		4,017			8,382
Unrealized loss-change in fair value of derivatives		(4,062	)		(15,649	)
Total other comprehensive loss		(45	)		(7,267	)
Comprehensive loss	$	(147,716	)	$	(3,735	)

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

5

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF CASH FLOWS

	Three Months Ended March 31,
	2012			2011
	(In thousands)
Cash Flows From Operating Activities:
Net (loss) income	$	(147,671	)	$	3,532
Adjustments to reconcile net (loss) income to net cash provided by operating activities:
Depreciation and amortization		19,088			16,869
Impairment		28,744			—
Amortization of debt issue costs		973			982
Equity in loss (income) from unconsolidated affiliates		114,728			(1,702	)
Distributions from unconsolidated affiliates		6,126			5,531
Non-cash gain on risk management activities, net		(158	)		(1,216	)
Equity-based compensation		2,782			2,473
Deferred tax provision		272			602
Other non-cash items		201			55
Changes in assets and liabilities:
Accounts receivable		(11,478	)		(696	)
Prepayments and other current assets		1,455			930
Risk management activities		1,048			(1,917	)
Accounts payable		(10,241	)		2,519
Other current liabilities		16,245			569
Net cash provided by operating activities		22,114			28,531
Cash Flows From Investing Activities:
Additions to property, plant and equipment		(52,865	)		(40,009	)
Additions to intangible assets		(1,195	)		(1,307	)
Investments in unconsolidated affiliates		(19,362	)		(26,800	)
Distributions from unconsolidated affiliates		4,203			942
Escrow cash		—			6
Proceeds from sale of assets		43			159
Other		1,696			(161	)
Net cash used in investing activities		(67,480	)		(67,170	)
Cash Flows From Financing Activities:
Proceeds from long-term debt		220,375			85,000
Repayment of long-term debt		(317,000	)		—
Deferred financing costs		(3,433	)		(114	)
Distributions to unitholders		(41,643	)		(37,928	)
Proceeds from public offering of common units, net of underwriting discounts and commissions of $7,590		188,083			—
Equity offering costs		(359	)		—
Proceeds from option exercises		718			1,139
Net cash provided by financing activities		46,741			48,097
Net increase in cash and cash equivalents		1,375			9,458
Cash and cash equivalents, beginning of year		56,962			59,930
Cash and cash equivalents, end of period	$	58,337		$	69,388

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

6

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED STATEMENTS OF MEMBERS’ CAPITAL

	Series A Preferred					Common										Accumulated
	Number		Preferred			Number		Common			Paid-in		Accumulated			Other Comprehensive
	of Units		Units			of Units		Units			Capital		Deficit			(Loss) Income				Total
	(In thousands)
Balance, December 31, 2011		11,684	$	285,168			66,341	$	1,164,853		$	62,277	$	(624,121	)		$	(16,279	)	$	871,898
Issuance of preferred units (paid-in-kind)		292		8,486			—		—			—		—				—			8,486
Accrued in-kind units		—		212			—		—			—		—				—			212
In-kind distributions		—		(8,698	)		—		—			—		—				—			(8,698	)
Cash distributions to common unitholders		—		—			—		—			—		(41,936	)			—			(41,936	)
Issuance of common units		—		—			5,750		188,083			—		—				—			188,083
Equity offering costs		—		—			—		(320	)		—		—				—			(320	)
Equity-based compensation		—		—			137		718			5,226		—				—			5,944
Net loss		—		—			—		—			—		(147,671	)			—			(147,671	)
Derivative settlements reclassified to income		—		—			—		—			—		—				4,017			4,017
Unrealized loss-change in fair value of derivatives		—		—			—		—			—		—				(4,062	)		(4,062	)
Balance, March 31, 2012		11,976	$	285,168			72,228	$	1,353,334		$	67,503	$	(813,728	)		$	(16,324	)	$	875,953
	Series A Preferred					Common							Accumulated			Accumulated
	Number		Preferred			Number		Common			Paid-in		Earnings			Other Comprehensive
	of Units		Units			of Units		Units			Capital		(Deficit)			(Loss) Income				Total
											(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)		265		7,688			—		—			—		—				—			7,688
Accrued in-kind units		—		192			—		—			—		—				—			192
In-kind distributions		—		(7,880	)		—		—			—		—				—			(7,880	)
Cash distributions to common unitholders		—		—			—		—			—		(38,435	)			—			(38,435	)
Equity-based compensation		—		—			129		1,139			3,419		—				—			4,558
Net income		—		—			—		—			—		3,532				—			3,532
Derivative settlements reclassified to income		—		—			—		—			—		—				8,382			8,382
Unrealized loss-change in fair value of derivatives		—		—			—		—			—		—				(15,649	)		(15,649	)
Balance, March 31, 2011		10,850	$	285,172			66,044	$	1,162,791		$	55,162	$	(348,357	)		$	(37,623	)	$	1,117,145

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

7

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 and to serve as a holding company for our operating subsidiaries. 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 to petrochemical companies or other midstream companies as a mixture or as fractionated purity products and deliver them through our plant interconnects, trucking facilities 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, 2011 (“2011 10-K”).

Note 2 — Recent Accounting Pronouncements

We adopted Accounting Standards Update (“ASU”) 2011-05, “Comprehensive Income (Topic 220): Presentation of Comprehensive Income,” which amended comprehensive income presentation guidance. We elected to present the components of other comprehensive income in two separate but consecutive statements. The adoption did not impact our consolidated financial results.

We adopted ASU 2011-04, “Amendments to Achieve Common Fair Value Measurement and Disclosure Requirements in U.S. GAAP and International Financial Reporting Standards,” by changing certain fair value measurement principles and enhancing our disclosure of unobservable inputs discussed in Note 11. The adoption did not impact our consolidated financial results.

8

Note 2 — Recent Accounting Pronouncements (continued)

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 and have determined that none are expected to 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 as of the dates indicated:

	March 31, 2012
	Weighted Average Remaining Amortization Period		Gross Carrying Amount		Accumulated Amortization			Net
	(In years)		(In thousands)
Rights-of-way and easements		19	$	146,793	$	(30,456	)	$	116,337
Contracts		10		68,717		(26,527	)		42,190
Customer relationships		10		4,864		(1,695	)		3,169
Total		17	$	220,374	$	(58,678	)	$	161,696
	December 31, 2011
	Weighted Average Remaining Amortization Period		Gross Carrying Amount		Accumulated Amortization			Net
	(In years)		(In thousands)
Rights-of-way and easements		19	$	145,598	$	(28,822	)	$	116,776
Contracts		17		108,416		(36,014	)		72,402
Customer relationships		11		4,864		(1,617	)		3,247
Total		18	$	258,878	$	(66,453	)	$	192,425

During the three months ended March 31, 2012 and 2011, we did not place in service any intangible assets with future renewals or extension costs. Amortization expense was $3,180,000 and $2,898,000 for the three months ended March 31, 2012 and 2011, respectively.

During the three months ended March 31, 2012, we recorded a non-cash impairment charge of $28.7 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 2012 and each of the five succeeding fiscal years is approximately: 2012 — $8,477,000; 2013 — $11,301,000; 2014 — $11,138,000; 2015 — $10,988,000; 2016 — $10,940,000 and 2017 — $10,755,000.

Note 4 — Investments in Unconsolidated Affiliates

Our investments in unconsolidated affiliates consisted of the following at March 31, 2012.

		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
Double Eagle Pipeline LLC (“Double Eagle Pipeline”)	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

9

Note 4 — Investments in Unconsolidated Affiliates (continued)

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 at least 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 March 31, 2012, Fort Union is in compliance with this financial covenant.

Eagle Ford Gathering. Our investment in Eagle Ford Gathering totaled $133,352,000 and $120,910,000 as of March 31, 2012 and December 31, 2011, respectively. 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 Three Months Ended March 31,
	2012			2011
	(In thousands)
Operating revenue	$	74,157		$	—
Operating expenses		(67,086	)		(100	)
Depreciation and amortization		(2,979	)		—
Other		(76	)		—
Net income (loss)		4,016			(100	)
Ownership %		50	%		50	%
		2,008			(50	)
Copano’s share of management fees charged		75			20
Amortization of difference between the carried investment and the underlying equity in net assets		(20	)		—
Equity in earnings (loss) from Eagle Ford Gathering	$	2,063		$	(30	)
Distributions	$	5,496		$	—
Contributions	$	15,950		$	14,414
Current assets	$	27,675		$	5,374
Noncurrent assets		256,646			95,179
Current liabilities		(24,417	)		(11,959	)
Noncurrent liabilities		(345	)		—
Net assets	$	259,559		$	88,594

Bighorn and Fort Union. Our investments in Bighorn and Fort Union totaled $96,199,000 and $165,401,000, respectively, as of March 31, 2012, and $212,071,000 and $169,856,000, respectively, as of December 31, 2011.

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 March 31, 2012, we recorded a $115 million non-cash impairment charge relating to our investment in Bighorn and a $5 million non-cash impairment charge relating to our investment in Fort Union. We determined that these charges were necessary primarily based on the low natural gas price environment and our expectation for a lower level of drilling by producers in the 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.

10

Note 4 — Investments in Unconsolidated Affiliates (continued)

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

	As of and for the Three Months Ended March 31,
	2012						2011
	Bighorn			Fort Union			Bighorn			Fort Union
	(In thousands)
Operating revenue	$	6,223		$	15,280		$	7,163		$	14,358
Operating expenses		(2,745	)		(1,395	)		(2,716	)		(1,625	)
Depreciation and amortization		(1,374	)		(1,998	)		(1,293	)		(1,998	)
Interest income (expense) and other		26			(448	)		23			(477	)
Net income		2,130			11,439			3,177			10,258
Ownership %		51	%		37.04	%		51	%		37.04	%
		1,086			4,237			1,620			3,800
Priority allocation of earnings and other		155			—			146			—
Copano’s share of management fees charged		49			24			49			23
Amortization of difference between the carried investment and the underlying equity in net assets and impairment		(116,663	)		(6,173	)		(2,813	)		(1,606	)
Equity in (loss) earnings from Bighorn and Fort Union	$	(115,373	)	$	(1,912	)	$	(998	)	$	2,217
Distributions	$	1,846		$	2,519		$	2,695		$	3,334
Contributions	$	1,396		$	—		$	300		$	—
Current assets	$	5,128		$	17,091		$	4,993		$	13,780
Noncurrent assets		87,306			194,142			87,660			202,381
Current liabilities		(1,522	)		(18,696	)		(764	)		(18,553	)
Noncurrent liabilities		(316	)		(55,534	)		(276	)		(70,344	)
Net assets	$	90,596		$	137,003		$	91,613		$	127,264

Other. Our investments in our other unconsolidated affiliates (Webb Duval, Double Eagle Pipeline, Liberty Pipeline Group and Southern Dome) totaled $43,697,000 and $41,849,000 as of March 31, 2012 and December 31, 2011, respectively. The summarized financial information for our investments in other unconsolidated affiliates is presented below in aggregate:

	As of and for the
	Three Months Ended March 31,
	2012			2011
	(In thousands)
Operating revenue	$	5,332		$	6,720
Operating expenses		(3,837	)		(5,720	)
Depreciation and amortization		(984	)		(378	)
Other		2			2
Net income	$	513		$	624
Equity in earnings from unconsolidated affiliates	$	494		$	513
Distributions	$	468		$	444
Contributions(1)	$	2,000		$	11,053
Current assets	$	4,176		$	13,678
Noncurrent assets		81,233			32,922
Current liabilities		(5,613	)		(7,822	)
Noncurrent liabilities		(176	)		(63	)
Net assets	$	79,620		$	38,715

(1) Contributions for the three months ended March 31, 2012 and 2011 were primarily made to Double Eagle Pipeline and Liberty Pipeline Group, respectively.

11

Note 5 — Long-Term Debt

	March 31, 2012		December 31, 2011
	(In thousands)
Revolving credit facility	$	135,000	$	385,000
Senior Notes:
7.75% senior unsecured notes due 2018		249,525		249,525
7.125% senior unsecured notes due 2021		510,000		360,000
Unamortized bond premium-senior unsecured notes due 2021		3,330		—
Total Senior Notes		762,855		609,525
Total long-term debt	$	897,855	$	994,525

Revolving Credit Facility

Our $700 million senior secured revolving credit facility with Bank of America, N.A., as Administrative Agent, matures on June 10, 2016. The revolving credit facility contains covenants (some of which require us to 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 revolving credit facility as of March 31, 2012.

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.

The weighted average interest rate on borrowings under the revolving credit facility for the three months ended March 31, 2012 and 2011 was 2.9% and 1.4%, respectively, and the quarterly commitment fee on the unused portion of the revolving credit facility as of the end of those periods was 0.5% and 0.25%, respectively. Interest and other financing costs related to the revolving credit facility totaled $2,423,000 and $1,122,000 for the three months ended March 31, 2012 and 2011, respectively. Costs incurred with the establishment and amendment and restatement of this credit facility are being amortized over its term, and as of March 31, 2012, the unamortized portion of debt issue costs totaled $9,635,000.

Senior Notes

7.125% Senior Notes due 2021. On February 7, 2012, we completed a registered underwritten offering of an additional $150,000,000 in aggregate principal amount (the “new notes”) of our existing 7.125% senior unsecured notes due 2021 (the “2021 Notes”). The new notes were issued under the same indenture as the 2021 Notes and are part of the same series of debt securities. The new notes priced at 102.25% of their principal amount, for net proceeds of approximately $150.1 million, excluding accrued interest on the new notes and after deducting related fees and expenses (including underwriting discounts and commissions). We used the net proceeds from the new notes to repay a portion of the outstanding indebtedness under our revolving credit facility.

Interest on the 2021 Notes is payable each April 1 and October 1. Interest and other financing costs related to the 2021 Notes totaled $8,230,000 for the three months ended March 31, 2012. Costs of issuing the 2021 Notes are being amortized over the term of the 2021 Notes and, as of March 31, 2012, the unamortized portion of debt issue costs totaled $10,472,000.

7.75% Senior Notes due 2018. Interest on the our 7.75% senior unsecured notes due 2018 (the “2018 Notes” and, together with the 2021 Notes, the “Senior Notes”) is payable each June 1 and December 1. Interest and other financing costs related to the 2018 Notes totaled $4,971,000 for each of the three months ended March 31, 2012 and 2011. Costs of issuing the 2018 Notes are being amortized over the term of the 2018 Notes and, as of March 31, 2012, the unamortized portion of debt issue costs totaled $3,355,000.

8.125% Senior Notes due 2016. Pursuant to a tender offer and subsequent mandatory redemption completed in April 2011, we repurchased or redeemed all of our then outstanding 8.125% senior unsecured notes due 2016 (the “2016 Notes”) using the net proceeds from our April 2011 issuance of the 2021 Notes. Interest and other financing costs related to the 2016 Notes totaled $6,950,000 for the three months ended March 31, 2011.

12

Note 5 — Long-Term Debt (continued)

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 March 31, 2012.

Guarantor Financial Statements

Condensed consolidating unaudited financial information for Copano and its 100%-owned subsidiaries is presented below.

13

Note 5 — Long-Term Debt (continued)

	March 31, 2012																		December 31, 2011
	Parent			Co- Issuer			Guarantor Subsidiaries			Investment in Non- Guarantor Subsidiaries			Eliminations			Total			Parent			Co- Issuer			Guarantor Subsidiaries			Investment in Non- Guarantor Subsidiaries			Eliminations			Total
																(In thousands)
ASSETS
Current assets:
Cash and cash equivalents	$	27,293		$	—		$	31,044		$	—		$	—		$	58,337		$	9,064		$	—		$	47,898		$	—		$	—		$	56,962
Accounts receivable, net		2,270			—			128,743			—			—			131,013			2,374			—			116,819			—			—			119,193
Intercompany receivable		191,844			(1	)		(191,843	)		—			—			—			153,059			(1	)		(153,058	)		—			—			—
Risk management assets		—			—			4,564			—			—			4,564			—			—			4,322			—			—			4,322
Prepayments and other current assets		2,703			—			957			—			—			3,660			3,975			—			1,139			—			—			5,114
Total current assets		224,110			(1	)		(26,535	)		—			—			197,574			168,472			(1	)		17,120			—			—			185,591
Property, plant and equipment, net		6			—			1,137,364			—			—			1,137,370			16			—			1,103,683			—			—			1,103,699
Intangible assets, net		—			—			161,696			—			—			161,696			—			—			192,425			—			—			192,425
Investments in unconsolidated affiliates		—			—			438,649			438,649			(438,649	)		438,649			—			—			544,687			544,687			(544,687	)		544,687
Investments in consolidated subsidiaries		1,563,345			—			—			—			(1,563,345	)		—			1,698,260			—			—			—			(1,698,260	)		—
Escrow cash		—			—			1,848			—			—			1,848			—			—			1,848			—			—			1,848
Risk management assets		—			—			4,447			—			—			4,447			—			—			6,452			—			—			6,452
Other assets, net		23,462			—			7,063			—			—			30,525			21,136			—			8,759			—			—			29,895
Total assets	$	1,810,923		$	(1	)	$	1,724,532		$	438,649		$	(2,001,994	)	$	1,972,109		$	1,887,884		$	(1	)	$	1,874,974		$	544,687		$	(2,242,947	)	$	2,064,597
LIABILITIES AND MEMBERS’/PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	—		$	—		$	138,639		$	—		$	—		$	138,639		$	31		$	—		$	155,890		$	—		$	—		$	155,921
Accrued interest		24,754			—			—			—			—			24,754			8,686			—			—			—			—			8,686
Accrued tax liability		1,511			—			—			—			—			1,511			1,182			—			—			—			—			1,182
Risk management liabilities		—			—			2,736			—			—			2,736			—			—			3,565			—			—			3,565
Other current liabilities		5,566			—			17,786			—			—			23,352			6,809			—			15,231			—			—			22,040
Total current liabilities		31,831			—			159,161			—			—			190,992			16,708			—			174,686			—			—			191,394
Long-term debt		897,855			—			—			—			—			897,855			994,525			—			—			—			—			994,525
Deferred tax liability		2,372			—			100			—			—			2,472			2,119			—			80			—			—			2,199
Other noncurrent liabilities		2,912			—			1,925			—			—			4,837			2,634			—			1,947			—			—			4,581
Members’/Partners’ capital:
Series A convertible preferred units		285,168			—			—			—			—			285,168			285,168			—			—			—			—			285,168
Common units		1,353,334			—			—			—			—			1,353,334			1,164,853			—			—			—			—			1,164,853
Paid in capital		67,503			1			1,198,550			696,453			(1,895,004	)		67,503			62,277			1			1,208,051			687,763			(1,895,815	)		62,277
Accumulated deficit		(813,728	)		(2	)		381,120			(257,804	)		(123,314	)		(813,728	)		(624,121	)		(2	)		506,489			(143,076	)		(363,411	)		(624,121	)
Accumulated other comprehensive loss		(16,324	)		—			(16,324	)		—			16,324			(16,324	)		(16,279	)		—			(16,279	)		—			16,279			(16,279	)
		875,953			(1	)		1,563,346			438,649			(2,001,994	)		875,953			871,898			(1	)		1,698,261			544,687			(2,242,947	)		871,898
Total liabilities and members’/ partners’ capital	$	1,810,923		$	(1	)	$	1,724,532		$	438,649		$	(2,001,994	)	$	1,972,109		$	1,887,884		$	(1	)	$	1,874,974		$	544,687		$	(2,242,947	)	$	2,064,597

14

Note 5 — Long-Term Debt (continued)

	Three Months Ended March 31, 2012																	Three Months Ended March 31, 2011
	Parent			Co- Issuer		Guarantor Subsidiaries			Investment in Non- Guarantor Subsidiaries			Eliminations			Total			Parent			Co- Issuer		Guarantor Subsidiaries			Investment in Non- Guarantor Subsidiaries			Eliminations			Total
	(In thousands)
Revenue:
Natural gas sales	$	—		$	—	$	86,212		$	—		$	—		$	86,212		$	—		$	—	$	103,795		$	—		$	—		$	103,795
Natural gas liquids sales		—			—		195,187			—			—			195,187			—			—		149,001			—			—			149,001
Transportation, compression and processing fees		—			—		39,839			—			—			39,839			—			—		24,471			—			—			24,471
Condensate and other		—			—		15,990			—			—			15,990			—			—		12,658			—			—			12,658
Total revenue		—			—		337,228			—			—			337,228			—			—		289,925			—			—			289,925
Costs and expenses:
Cost of natural gas and natural gas liquids		—			—		265,951			—			—			265,951			—			—		223,730			—			—			223,730
Transportation		—			—		6,449			—			—			6,449			—			—		5,849			—			—			5,849
Operations and maintenance		—			—		18,642			—			—			18,642			—			—		15,099			—			—			15,099
Depreciation and amortization		10			—		19,078			—			—			19,088			10			—		16,859			—			—			16,869
Impairment		—			—		28,744			—			—			28,744			—			—		—			—			—			—
General and administrative		7,454			—		7,490			—			—			14,944			7,523			—		5,075			—			—			12,598
Taxes other than income		—			—		1,366			—			—			1,366			—			—		1,130			—			—			1,130
Equity in loss (earnings) from unconsolidated affiliates		—			—		114,728			114,728			(114,728	)		114,728			—			—		(1,702	)		(1,702	)		1,702			(1,702	)
Total costs and expenses		7,464			—		462,448			114,728			(114,728	)		469,912			7,533			—		266,040			(1,702	)		1,702			273,573
Operating (loss) income		(7,464	)		—		(125,220	)		(114,728	)		114,728			(132,684	)		(7,533	)		—		23,885			1,702			(1,702	)		16,352
Other income (expense):
Interest and other income		—			—		38			—			—			38			—			—		7			—			—			7
Interest and other financing costs		(14,255	)		—		(169	)		—			—			(14,424	)		(11,638	)		—		(278	)		—			—			(11,916	)
(Loss) income before income taxes and equity in (loss) earnings from consolidated subsidiaries		(21,719	)		—		(125,351	)		(114,728	)		114,728			(147,070	)		(19,171	)		—		23,614			1,702			(1,702	)		4,443
Provision for income taxes		(582	)		—		(19	)		—			—			(601	)		(890	)		—		(21	)		—			—			(911	)
(Loss) income before equity in (loss) earnings from consolidated subsidiaries		(22,301	)		—		(125,370	)		(114,728	)		114,728			(147,671	)		(20,061	)		—		23,593			1,702			(1,702	)		3,532
Equity in (loss) earnings from consolidated subsidiaries		(125,370	)		—		—			—			125,370			—			23,593			—		—			—			(23,593	)		—
Net (loss) income		(147,671	)		—		(125,370	)		(114,728	)		240,098			(147,671	)		3,532			—		23,593			1,702			(25,295	)		3,532
Preferred unit distributions		(8,698	)		—		—			—			—			(8,698	)		(7,880	)		—		—			—			—			(7,880	)
Net (loss) income to common units	$	(156,369	)	$	—	$	(125,370	)	$	(114,728	)	$	240,098		$	(156,369	)	$	(4,348	)	$	—	$	23,593		$	1,702		$	(25,295	)	$	(4,348	)
Net (loss) income	$	(147,671	)	$	—	$	(125,370	)	$	(114,728	)	$	240,098		$	(147,671	)	$	3,532		$	—	$	23,593		$	1,702		$	(25,295	)	$	3,532
Other comprehensive (loss) income:
Derivative settlements reclassified to income		4,017			—		4,017			—			(4,017	)		4,017			8,382			—		8,382			—			(8,382	)		8,382
Unrealized (loss) gain-change in fair value of derivatives		(4,062	)		—		(4,062	)		—			4,062			(4,062	)		(15,649	)		—		(15,649	)		—			15,649			(15,649	)
Total other comprehensive income loss		(45	)		—		(45	)		—			45			(45	)		(7,267	)		—		(7,267	)		—			7,267			(7,267	)
Comprehensive income (loss)	$	(147,716	)	$	—	$	(125,415	)	$	(114,728	)	$	240,143		$	(147,716	)	$	(3,735	)	$	—	$	16,326		$	1,702		$	(18,028	)	$	(3,735	)

15

Note 5 — Long-Term Debt (continued)

	Three Months Ended March 31, 2012																	Three Months Ended March 31, 2011
	Parent			Co- Issuer		Guarantor Subsidiaries			Investment in Non- Guarantor Subsidiaries			Eliminations			Total			Parent			Co- Issuer		Guarantor Subsidiaries			Investment in Non- Guarantor Subsidiaries			Eliminations			Total
	(In thousands)
Cash Flows From Operating Activities:
Net cash (used in) provided by operating activities	$	(38,013	)	$	—	$	60,127		$	6,126		$	(6,126	)	$	22,114		$	(39,329	)	$	—	$	67,860		$	5,531		$	(5,531	)	$	28,531
Cash Flows From Investing Activities:
Additions to property, plant and equipment and intangibles		—			—		(54,060	)		—			—			(54,060	)		—			—		(41,316	)		—			—			(41,316	)
Investments in unconsolidated affiliates		—			—		(19,362	)		(19,362	)		19,362			(19,362	)		—			—		(26,800	)		(26,800	)		26,800			(26,800	)
Distributions from unconsolidated affiliates		—			—		4,203			4,203			(4,203	)		4,203			—			—		942			942			(942	)		942
Investments in consolidated subsidiaries		(17,995	)		—		—			—			17,995			—			(25,467	)		—		—			—			25,467			—
Distributions from consolidated subsidiaries		27,496			—		—			—			(27,496	)		—			21,500			—		—			—			(21,500	)		—
Proceeds from sale of assets		—			—		43			—			—			43			—			—		159			—			—			159
Other		—			—		1,696			—			—			1,696			—			—		(155	)		—			—			(155	)
Net cash provided by (used in) investing activities		9,501			—		(67,480	)		(15,159	)		5,658			(67,480	)		(3,967	)		—		(67,170	)		(25,858	)		29,825			(67,170	)
Cash Flows From Financing Activities:
Proceeds from long-term debt		220,375			—		—			—			—			220,375			85,000			—		—			—			—			85,000
Repayment of long-term debt		(317,000	)		—		—			—			—			(317,000	)		—			—		—			—			—			—
Deferred financing costs		(3,433	)		—		—			—			—			(3,433	)		(114	)		—		—			—			—			(114	)
Distributions to unitholders		(41,643	)		—		—			—			—			(41,643	)		(37,928	)		—		—			—			—			(37,928	)
Proceeds from public offering of common units		188,083			—		—			—			—			188,083			—			—		—			—			—			—
Equity offering costs		(359	)		—		—			—			—			(359	)		—			—		—			—			—			—
Contributions from parent		—			—		17,995			—			(17,995	)		—			—			—		25,467			26,800			(52,267	)		—
Distributions to parent		—			—		(27,496	)		—			27,496			—			—			—		(21,500	)		—			21,500			—
Other		718			—		—			19,362			(19,362	)		718			1,139			—		—			—			—			1,139
Net cash provided by (used in) financing activities		46,741			—		(9,501	)		19,362			(9,861	)		46,741			48,097			—		3,967			26,800			(30,767	)		48,097
Net increase (decrease) in cash and cash equivalents		18,229			—		(16,854	)		10,329			(10,329	)		1,375			4,801			—		4,657			6,473			(6,473	)		9,458
Cash and cash equivalents, beginning of year		9,064			—		47,898			121,322			(121,322	)		56,962			9,650			—		50,280			85,851			(85,851	)		59,930
Cash and cash equivalents, end of period	$	27,293		$	—	$	31,044		$	131,651		$	(131,651	)	$	58,337		$	14,451		$	—	$	54,937		$	92,324		$	(92,324	)	$	69,388

16

Note 6 — Members’ Capital and Distributions

Series A Convertible Preferred Units

The following table summarizes the quarterly distributions in kind (paid in the form of additional Series A convertible preferred units) during 2012.

Quarter Ending	Series A Convertible Preferred Units Issued As In-Kind  Distributions		Issue Date			Amount
December 31, 2011		292,101		February 9, 2012		$	8,486,000
March 31, 2012		299,404		May 2012	(1)	$	8,698,000

(1) Units will be issued on or about May 10, 2012.

For additional information about our Series A convertible preferred units, please read Note 6, “Members’ Capital and Distributions,” under Item 8 in our 2011 10-K.

Common Units

On January 19, 2012, we completed a registered underwritten offering of 5,750,000 common units at $34.03 per unit, for net proceeds of $187,762,000, after deducting underwriting discounts and offering expenses. We used the net proceeds to repay a portion of the outstanding indebtedness under our revolving credit facility.

The following table sets forth information regarding distributions to our unitholders during 2012.

Quarter Ending	Distribution Per Unit		Date Declared		Record Date		Payment Date		Amount
December 31, 2011	$	0.575		January 11, 2012		January 26, 2012		February 9, 2012	$	42,064,000
March 31, 2012	$	0.575		April 11, 2012		April 30, 2012		May 10, 2012	$	42,113,000

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 March 31, 2012, the number of units available for grant under our LTIP totaled 2,113,768 of which up to 1,583,790 units were eligible to be issued as restricted common units, phantom units or unit awards.

Equity Awards. We recognized non-cash compensation expense of $3,099,000 and $2,073,000 related to the amortization of equity-based compensation under our LTIP during the three months ended March 31, 2012 and 2011, respectively. Please read Note 6, “Members’ Capital and Distributions,” under Item 8 in our 2011 10-K for details on our equity-based compensation.

Unit Awards. During the three months ended March 31, 2012, we issued 74,606 unit awards (common units that are not subject to vesting or forfeiture) at a grant date issue price of $35.19 to settle the fourth quarter 2011 Employee Incentive Compensation Program and the 2011 Management Incentive Compensation Plan bonuses.

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

17

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

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 months ended March 31, 2012 and 2011, 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 Ended March 31,
	2012		2011
	(In thousands)
Options		729		894
Unit appreciation rights		389		326
Restricted units		44		60
Phantom units		958		879
Contingent incentive plan unit awards		—		30
Series A preferred units		11,976		10,850

18

Note 8 — Related Party Transactions

Summary of Transactions With Affiliated Entities

	Financial Statement Classification - Three Months Ended March 31, 2012
	Natural Gas Sales			Transportation, Compression and Processing Fees		Condensate and Other		Cost of Natural Gas and Natural Gas Liquids			Transportation		General and Administrative(2)		Reimbursable Costs(3)		Accounts Payable		Accounts Receivable
Webb Duval	$	—		$	—	$	—	$	56		$	284	$	57	$	202	$	51	$	90
Eagle Ford Gathering		—			2,002		—		24,973			—		179		139		10,627		77
Liberty Pipeline Group		—			—		—		—			315		57		64		146		32
Double Eagle Pipeline		—			—		—		—			—		175		1,844		—		205
Southern Dome		—			—		—		—			—		63		108		—		43
Bighorn		—			—		312		—			—		96		650		—		89
Fort Union		—			—		—		—			1,593		65		128		—		55
Other		—			—		—		—			—		—		—		—		8
Total related party transactions	$	—		$	2,002	$	312	$	25,029		$	2,192	$	692	$	3,135	$	10,824	$	599
	Financial Statement Classification - Three Months Ended March 31, 2011
	Natural Gas Sales			Transportation, Compression and Processing Fees		Condensate and Other		Cost of Natural Gas and Natural Gas Liquids			Transportation		General and Administrative(2)		Reimbursable Costs(3)		Accounts Payable		Accounts Receivable
Affiliates of Mr. Lawing(1)	$	(1	)	$	2	$	—	$	60		$	—	$	—	$	57	$	18	$	—
Webb Duval		—			—		—		(61	)		51		56		113		41		53
Eagle Ford Gathering		—			—		—		—			—		329		10,113		—		311
Liberty Pipeline Group		—			—		—		—			—		—		3,494		—		147
Southern Dome		—			—		—		—			—		63		96		—		41
Bighorn		—			—		417		—			—		96		583		2		96
Fort Union		—			—		—		6			1,280		62		717		8		2
Other		—			—		—		—			—		—		—		—		5
Total related party transactions	$	(1	)	$	2	$	417	$	5		$	1,331	$	606	$	15,173	$	69	$	655

(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. The contracts with the affiliates of Mr. Lawing underlying these transactions were assigned to non-affiliates in 2011.

(2) Management fees and capital project fees received from our unconsolidated affiliates consists of the total compensation paid to us by our unconsolidated affiliates and is included as a reduction in general and administrative expenses on our consolidated statements of operations.

(3) Reimbursable costs consist of expenses incurred by our affiliates for which Copano makes payment but is reimbursed by the affiliate. These amounts are settled through related party accounts receivable and payable and are not included on statements of operations.

19

Note 8 — Related Party Transactions (continued)

Other Transactions

Certain of our operating subsidiaries incurred costs payable to an affiliate of TPG Copenhagen, L.P., an affiliate of TPG Capital, L.P., for compression services totaling $162,000 and $32,000 for the three months ended March 31, 2012 and 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.

Our management believes that the terms and provisions 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 March 31, 2012 and 2011, rental expense for leased office space, vehicles, compressors and related field equipment used in our operations totaled $1,772,000 and $924,000, 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. Our commitments under these agreements with WIC, Fort Union and Formosa expire between 2017 and 2023. Under these agreements, we are obligated to pay an aggregate amount of approximately $12,960,000 for the remainder of 2012, $24,728,000 in 2013, $23,905,000 in 2014, $22,489,000 in 2015, $22,224,000 in 2016 and $85,409,000 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 that had been contractually dedicated by us for resale to Targa. As of March 31, 2012, we had fixed contractual commitments to provide Targa a total of 2.373 billion cubic feet of natural gas for each of 2012 and 2013. Under the terms of the agreement, we are obligated to pay annual fees ($1.15 per thousand cubic feet (“Mcf”) and $1.25 per Mcf for 2012 and 2013, respectively) to the extent our natural gas deliveries to Targa fall below the committed quantity. In February 2012, we paid $1,567,000 to Targa in settlement of our 2011 obligation. As of March 31, 2012, we have accrued $171,000 of our 2012 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

Please read Note 11, “Commitments and Contingencies,” under Item 8 in our 2011 10-K.

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

Note 10 — Supplemental Disclosures to the Statements of Cash Flows

	Three Months Ended March 31,
	2012		2011
	(In thousands)
Cash payments for interest, net of $1,368,000 and $1,404,000 capitalized in 2012 and 2011, respectively	$	1,412	$	12,351
In-kind distributions of Series A convertible preferred units	$	8,698	$	7,880

We incurred a change in liabilities of ($3,254,000) and $12,250,000 for investing activities that had not been paid as of March 31, 2012 and 2011, 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

20

Note 10 — Supplemental Disclosures to the Statements of Cash Flows (continued)

of cash flows. As of March 31, 2012 and 2011, we accrued $22,939,000 and $20,249,000, 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 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.

Commodity Risk Hedging Program

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 as a function of the contract terms under which we are compensated for our services or pay third-parties for their services and primarily results from: (i) processing natural gas at our plants or third-party plants, (ii) purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and (iii) transporting and fractionating NGLs at index-related prices. 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 compliance with the risk management policy. The Audit Committee of our Board of Directors monitors the implementation of our risk management policy, and we have engaged an independent firm to monitor our compliance with the policy on a monthly basis. Our risk management policy provides that 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. Our risk management policy requires derivative transactions to take place either on the New York Mercantile Exchange (NYMEX) through a clearing member firm or with over-the-counter counterparties, with investment grade ratings from both Moody’s Investors Service and Standard & Poor’s Ratings Services and with complete industry standard contractual documentation. All of our hedge counterparties are also lenders under our revolving credit facility, and the payment obligations in connection with our hedge transactions are secured by a first priority lien on the collateral securing our revolving credit facility indebtedness that ranks equal in right of payment with liens granted in favor of our secured lenders. As long as this first priority lien is in effect, we will have no obligation to post cash, letters of credit or other additional collateral to secure these hedges at any time, even if our counterparty’s exposure to our credit increases over the term of the hedge as a result of higher commodity prices or because there has been a change in our creditworthiness.

Financial instruments that we acquire pursuant to our risk management policy are 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 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 no longer probable that the original forecasted transaction will 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 March 31, 2012, we estimated that $10,940,000 of OCI will be reclassified as a decrease to earnings in the next 12 months as a result of monthly settlements of instruments hedging NGLs and crude oil.

21

Note 11 — Financial Instruments (continued)

At March 31, 2012, the notional volumes of our commodity positions were:

Commodity	Instrument	Unit	2012		2013
NGLs	Puts	Bbl/d		5,400		2,650
Crude oil	Puts	Bbl/d		1,500		1,100
At December 31, 2011, the notional volumes of our commodity positions were:
Commodity	Instrument	Unit	2012		2013
NGLs	Puts	Bbl/d		5,400		1,650
Crude oil	Puts	Bbl/d		1,500		750

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 March 31, 2012, we hold a notional amount of $95.0 million in interest rate swaps, which have a weighted average fixed rate of 4.30% and expire in October 2012. As of March 31, 2012, our interest rate swaps were not designated as cash flow hedges.

As of March 31, 2012, we estimate that $98,000 of OCI related to previously designated interest rate swaps will be reclassified as a decrease to earnings as the underlying swaps expire in 2012.

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, 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.

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

Our Level 2 instruments include interest rate swaps. Valuation of our Level 2 derivative contracts are based on observable market prices, which include 3-month LIBOR interest rate curves, incorporating discount rates.

Our Level 3 instruments include NGL and WTI option contracts. Valuation of our Level 3 derivative contracts incorporates the use of option valuation models using significant unobservable inputs in addition to forward prices obtained from a third party pricing service and a financial system. To the extent certain model inputs are observable, such as prices of WTI Crude and Mont Belvieu NGLs, we include observable market price and volatility data as inputs to our valuation model in addition to incorporating discount rates. Our unobservable inputs include implied volatilities and market prices for NGLs and WTI volatilities for illiquid periods of the curves. Significant increases (decreases) in price curves would result in a significantly lower (higher) fair value measurement. On the other hand, significant increases (decreases) in volatility would result in a significantly higher (lower) fair value measurement. Our modeling methodology incorporates available market information to generate these inputs through techniques such as regression based interpolation and extrapolation.

We have an internal risk management group, which is responsible for our derivatives valuation, and reports to our Chief Financial Officer and Risk Management Committee. At each balance sheet date, they substantiate the reasonableness of our market-based inputs by (1) comparing the forward prices obtained from a third-party pricing service against other available market data (e.g. counterparty quotes) to confirm that the forward prices received are reasonable in relation to

22

Note 11 — Financial Instruments (continued)

the market price, and (2) analyzing historical data to confirm reasonableness of volatilities. In addition, as of each balance sheet date, our risk management group performs an analysis of all instruments subject to ASC 820 and includes in Level 3 all of those for which fair value is based on significant unobservable inputs. This analysis consists of validating the observability of market-based inputs by analyzing available information, including transaction volumes and open market positions. The risk management group presents its analyses of all instruments to the Risk Management Committee quarterly for approval of fair value hierarchy classification, as well as for discussion of changes in fair value from period to period. We chart movement in our market inputs to ensure that the shifts substantiate any changes in fair value.

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 March 31, 2012 and December 31, 2011. As required by ASC 820, assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. Management’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of fair value of assets and liabilities and their placement within the fair value hierarchy levels.

		xxxxxxx.xx		xxxxxxx.xx			xxxxxxx.xx		xxxxxxx.xx
	Fair Value Measurements on Hedging  Instruments(a)
	March 31, 2012
	Level 1		Level 2			Level 3		Total
	(In thousands)
Assets:
Natural Gas Liquids:
Short-term – Designated(b)		—		—			3,277		3,277
Short-term – Not designated(b)		—		—			432		432
Long-term – Designated(c)		—		—			2,017		2,017
Crude Oil:
Short-term – Designated(b)		—		—			672		672
Short-term – Not designated(b)		—		—			183		183
Long-term – Designated(c)		—		—			1,868		1,868
Long-term – Not designated(c)		—		—			562		562
Total	$	—	$	—		$	9,011	$	9,011
Liabilities:
Interest Rate:
Short-term – Not designated(d)		—		2,736			—		2,736
Total	$	—	$	2,736		$	—	$	2,736
Total designated assets	$	—	$	—		$	7,834	$	7,834
Total not designated (liabilities)/assets	$	—	$	(2,736	)	$	1,177	$	(1,559	)

(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.”

		xxxxxx.xx		xxxxxx.xx		xxxxxx.xx		xxxxxx.xx
	Fair Value Measurements on Hedging  Instruments(a)
	December 31, 2011
	Level 1		Level 2		Level 3		Total
	(In thousands)
Assets:
Natural Gas Liquids:
Short-term – Designated(b)		—		—		1,641		1,641
Short-term – Not designated(b)		—		—		952		952
Long-term – Designated(c)		—		—		2,878		2,878
Crude Oil:
Short-term – Designated(b)		—		—		1,341		1,341
Short-term – Not designated(b)		—		—		388		388
Long-term – Designated(c)		—		—		3,574		3,574
Total	$	—	$	—	$	10,774	$	10,774

23

Note 11 — Financial Instruments (continued)

	Fair Value Measurements on Hedging  Instruments(a)
	December 31, 2011
	Level 1		Level 2			Level 3		Total
	(In thousands)
Liabilities:
Interest Rate:
Short-term—Not designated(d)		—		3,565			—		3,565
Total	$	—	$	3,565		$	—	$	3,565
Total designated assets	$	—	$	—		$	9,434	$	9,434
Total not designated (liabilities)/assets	$	—	$	(3,565	)	$	1,340	$	(2,225	)

(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.”

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 March 31, 2012. 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) March 31, 2012
	Level 3		Impairment Expense
	(In thousands)
Long-lived assets(b)	$	261,600	$	120,000
Long-lived intangible assets(c)	$	—	$	28,744

(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 a contract is included on the consolidated balance sheets as a noncurrent asset under “Intangible assets, net” and on the consolidated statements of operations under “Impairment.”

The following table provides a description of the unobservable inputs utilized in the valuation of our derivatives classified as Level 3 in the fair value hierarchy:

24

Note 11 — Financial Instruments (continued)

Quantitative Information about Level 3 Fair Value Measurements

	Fair Value as of March 31, 2012		Valuation Technique		Unobservable Inputs		Range
	(In thousands)
Natural gas liquids options:
Ethane	$	2,734		Asian Option		Volatility		32.79%-35.71%
						Forward Price Curve	$	0.41-$0.44	(1)
Propane		2,055		Asian Option		Volatility		10.66%-13.58%
						Forward Price Curve	$	1.27-$1.31	(1)
Iso-butane		410		Asian Option		Volatility		19.71%-22.63%
						Forward Price Curve	$	1.85-$1.93	(1)
Normal butane		528		Asian Option		Volatility		16.81%-19.72%
						Forward Price Curve	$	1.80-$1.82	(1)
Total natural gas liquid options	$	5,727
Crude oil options	$	3,284		Option Model		Volatility		24.59%-27.51%

(1) Price shown is dollar per gallon.

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

	Three Months Ended March 31, 2012
	Natural Gas Liquids			Crude Oil			Total
	(In thousands)
Assets balance, beginning of period	$	5,470		$	5,304		$	10,774
Total gains or losses:
Non-cash amortization of option premium		(3,445	)		(1,595	)		(5,040	)
Other amounts included in earnings		429			(459	)		(30	)
Included in accumulated other comprehensive loss		1,404			(1,499	)		(95	)
Purchases		2,418			1,533			3,951
Settlements		(549	)		—			(549	)
Asset balance, end of period	$	5,727		$	3,284		$	9,011
Change in unrealized loss included in earnings related to instruments still held as of the end of the period	$	636		$	717		$	1,353

	Three Months Ended March 31, 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		(1,454	)		(3,857	)		(1,960	)		(7,271	)
Other amounts included in earnings		—			(1,943	)		488			(1,455	)
Included in accumulated other comprehensive loss		1,398			(6,862	)		(1,899	)		(7,363	)
Purchases		—			7,364			1,800			9,164
Settlements		—			2,001			—			2,001
Asset balance, end of period	$	31		$	5,053		$	4,904		$	9,988
Change in unrealized (income) loss included in earnings related to instruments still held as of the end of the period	$	—		$	(140	)	$	151		$	11

25

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 statements of comprehensive income (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 March 31, 2012.

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

The Effect of Derivative Instruments on the Statements of Operations
Derivatives Designated as Cash Flow Hedges Under ASC 815	Amount of Gain (Loss) Recognized in OCI on Derivatives (Effective Portion)			Amount of Gain (Loss) Reclassified from Accumulated OCI into Income (Effective Portion)			Amount of Gain (Loss) Recognized in Income on Derivative (Ineffective Portion and Amount Excluded from Effectiveness Testing)			Statements of Operations Location
				(In thousands)
Three Months Ended March 31, 2012
Natural gas liquids	$	(1,234	)	$	(2,637	)	$	105		Natural gas liquids sales
Crude oil		(2,828	)		(1,330	)		49		Condensate and other
Interest rate swaps		—			(50	)		—		Interest and other financing costs
Total	$	(4,062	)	$	(4,017	)	$	154
Three Months Ended March 31, 2011
Natural gas	$	(57	)	$	(1,454	)	$	—		Natural gas sales
Natural gas liquids		(12,135	)		(5,272	)		(140	)	Natural gas liquids sales
Crude oil		(3,457	)		(1,559	)		133		Condensate and other
Interest rate swaps		—			(97	)		—		Interest and other financing costs
Total	$	(15,649	)	$	(8,382	)	$	(7	)

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

The Effect of Derivative Instruments on the Statements of Operations
Derivatives Not Designated as Hedging Instruments Under ASC 820	Amount of Gain (Loss) Recognized in Income on Derivative			Statements of Operations Location
(In thousands)
Three Months Ended March 31, 2012
Natural gas liquids	$	(225	)	Natural gas liquids sales
Crude oil		(508	)	Condensate and other
Interest rate swaps		(118	)	Interest and other financing costs
Total	$	(851	)
Three Months Ended March 31, 2011
Natural gas	$	(63	)	Natural gas sales
Natural gas liquids		197		Natural gas liquids sales
Crude oil		353		Condensate and other
Interest rate swaps		(182	)	Interest and other financing costs
Total	$	305

26

Note 12 — Fair Value of Financial Instruments

The fair value of our financial instrument liabilities are not recorded at fair value on our consolidated balance sheets and the estimated fair value does not affect our results of operations. Cash and cash equivalents approximate fair value is equal to the amount reflected in our consolidated balance sheets as of March 31, 2012. Our revolving credit facility is considered a Level 2 fair value measurement under the fair value hierarchy as we estimate the fair value based on recent debt transactions that we considered similar to our revolving credit facility. Our Senior Notes are considered a Level 2 fair value measurement under the fair value hierarchy as we estimate the fair value based on prices of recent trades or bid and ask pricing as quoted by a large financial institution that is an active market participant in our Senior Notes. A summary of the fair value and carrying value of the financial instruments is shown in the table below.

	March 31, 2012				December 31, 2011
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
	(In thousands)
Cash and cash equivalents	$	58,337	$	58,337	$	56,962	$	56,962
Revolving credit facility	$	135,000	$	135,000	$	385,000	$	385,000
2018 Notes	$	249,525	$	262,001	$	249,525	$	267,566
2021 Notes	$	510,000	$	532,950	$	360,000	$	366,300

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:

• 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 and includes a processing plant located in southwest Louisiana. In addition to our 100%-owned operations, this segment includes our equity investments in Webb Duval, Eagle Ford Gathering, Liberty Pipeline Group and Double Eagle Pipeline.

• 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 also 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. In addition to our 100%-owned producer services business, 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.

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Note 13 — Segment Information (continued)

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

	Texas			Oklahoma			Rocky Mountains			Total Segments			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended March 31, 2012:
Total segment gross margin	$	45,341		$	24,199		$	358		$	69,898		$	(5,070	)	$	64,828
Operations and maintenance expenses		10,618			7,981			43			18,642			—			18,642
Depreciation and amortization		9,349			8,654			765			18,768			320			19,088
Impairment		—			—			28,744			28,744			—			28,744
General and administrative expenses		4,042			2,488			855			7,385			7,559			14,944
Taxes other than income		672			686			2			1,360			6			1,366
Equity in (earnings) loss from unconsolidated affiliates		(2,168	)		(388	)		117,284			114,728			—			114,728
Operating income (loss)	$	22,828		$	4,778		$	(147,335	)	$	(119,729	)	$	(12,955	)	$	(132,684	)
Natural gas sales	$	57,139		$	29,021		$	52		$	86,212		$	—		$	86,212
Natural gas liquids sales		137,006			61,198			—			198,204			(3,017	)		195,187
Transportation, compression and processing fees		31,307			4,430			4,102			39,839			—			39,839
Condensate and other		3,655			14,076			312			18,043			(2,053	)		15,990
Sales to external customers	$	229,107		$	108,725		$	4,466		$	342,298		$	(5,070	)	$	337,228
Interest and other financing costs	$	—		$	—		$	—		$	—		$	14,424		$	14,424
Segment assets	$	883,389		$	644,372		$	304,234		$	1,831,995		$	140,114		$	1,972,109
Three Months Ended March 31, 2011:
Total segment gross margin	$	45,011		$	23,082		$	1,042		$	69,135		$	(8,789	)	$	60,346
Operations and maintenance expenses		8,825			6,219			55			15,099			—			15,099
Depreciation and amortization		6,669			9,043			765			16,477			392			16,869
General and administrative expenses		2,766			2,178			368			5,312			7,286			12,598
Taxes other than income		542			570			1			1,113			17			1,130
Equity in loss (earnings) from unconsolidated affiliates		219			(702	)		(1,219	)		(1,702	)		—			(1,702	)
Operating income (loss)	$	25,990		$	5,774		$	1,072		$	32,836		$	(16,484	)	$	16,352
Natural gas sales	$	60,101		$	45,085		$	125		$	105,311		$	(1,516	)	$	103,795
Natural gas liquids sales		88,680			66,122			—			154,802			(5,801	)		149,001
Transportation, compression and processing fees		17,676			2,422			4,373			24,471			—			24,471
Condensate and other		4,863			8,851			417			14,131			(1,473	)		12,658
Sales to external customers	$	171,320		$	122,480		$	4,915		$	298,715		$	(8,790	)	$	289,925
Interest and other financing costs	$	—		$	—		$	—		$	—		$	11,916		$	11,916

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

You should read the following discussion of our financial condition and results of operations in conjunction with the unaudited 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 under Item 8 in our Annual Report on Form 10-K for the year ended December 31, 2011 (the “2011 10-K”).

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

/d:	Per day
$/gal:	U.S. dollars per gallon
Bbls:	Barrels
Bcf:	One billion cubic feet
Btu:	One British thermal unit
GPM:	Gallons per minute
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
Tcf:	One trillion cubic feet
Throughput:	The volume of natural gas or NGLs transported or passing through a pipeline, plant, terminal or other facility

Forward-Looking Statements

This report contains “forward-looking statements” within the meaning of the federal securities laws. All statements in this report other than statements of historical fact, including those under “—Trends and Uncertainties,” “—Our Results of Operations” and “—Liquidity and Capital Resources” are forward-looking statements. Forward-looking statements address activities, events or developments that we expect or anticipate will or may occur in the future, including references to future goals or intentions. These statements can be identified by the use of forward-looking terminology, including “may,” “believe,” “expect,” “anticipate,” “estimate,” “continue,” or similar words. These statements include assertions related to plans for growth of our business, future capital expenditures and competitive strengths and goals. We make these statements based on our past experience and our perception of historical trends, current conditions and expected future developments as well as other considerations we believe are appropriate under the circumstances. Whether actual results and developments in the future will conform to our expectations is subject to numerous risks and uncertainties, many of which are beyond our control. Therefore, actual outcomes and results could materially differ from what is expressed or implied 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 and condensate and the NGL content of new gas supplies;

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

• 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, cost expectations and operating performance standards for construction projects;

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

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

• the effectiveness of our hedging program;

• general economic conditions;

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

• the effects of government regulations and policies; and

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

This report and our 2011 10-K include cautionary statements identifying important factors that could cause our actual results to differ materially from our expectations expressed or implied in forward-looking statements. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements set forth in this report and under Item 1A, “Risk Factors” in our 2011 10-K. All forward-looking statements in this report and all subsequent written or oral forward-looking statements attributable to us 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.

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.

Texas. 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 services and includes a processing plant located in southwest Louisiana. In addition to our 100%-owned operations, this segment includes:

• our 50% interest in Eagle Ford Gathering LLC (“Eagle Ford Gathering”), which provides midstream natural gas services to Eagle Ford Shale producers;

• our 50% interest in Liberty Pipeline Group LLC (“Liberty Pipeline Group”), which transports mixed NGLs from our Houston Central complex to the Texas Gulf Coast;

• our 62.5% interest in Webb Duval Gatherers (“Webb Duval”), which provides natural gas gathering in south Texas; and

• our 50% interest in Double Eagle Pipeline LLC (“Double Eagle Pipeline”), which is constructing a condensate and crude oil gathering system that will serve Eagle Ford Shale producers.

Oklahoma. Our Oklahoma segment provides midstream natural gas services in central and east Oklahoma, including primarily low-pressure gathering of natural gas and related services such as compression, dehydration, treating, processing and nitrogen rejection. This segment includes our majority interest in Southern Dome, LLC (“Southern Dome”), which provides gathering and processing services within the Southern Dome prospect in the southern portion of Oklahoma County.

Rocky Mountains. Our Rocky Mountains segment provides midstream natural gas services in the Powder River Basin of Wyoming, including gathering and treating of natural gas. In addition to our 100%-owned producer services business, this segment includes:

• our 51% interest in Bighorn Gas Gathering, L.L.C. (“Bighorn”), which provides gathering services to Powder River Basin producers; and

• our 37.04% interest in Fort Union Gas Gathering, L.L.C. (“Fort Union”), which provides gathering and treating services to Powder River Basin producers.

Corporate and other. 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

Houston Central Cryogenic Processing Upgrade. On March 20, 2012, we announced that repairs to the newly installed 200 MMcf/d cryogenic tower at our Houston Central complex had been completed on March 13, 2012. In April 2012, during a shutdown of Kinder Morgan’s Laredo-to-Katy pipeline for scheduled maintenance, we shut down the new cryogenic tower for additional repairs, and for modifications to enhance plant performance. The cryogenic tower was down for eight days in mid-April, which will have a negative impact on our second-quarter Texas segment gross margin. The modified tower is now online and meeting our performance expectations.

Houston Central Processing Expansion. In addition to the 400 MMcf/d cryogenic expansion we announced in April 2011, which is under construction, our Board has approved a project to install an additional 400 MMcf/d of cryogenic processing capacity at our Houston Central complex. This additional cryogenic capacity will enable us to process rich Eagle Ford Shale gas more efficiently through increased NGL recoveries and reduced operating costs. The second 400 MMcf/d cryogenic facility should enable us to relegate the lean oil facilities to providing overflow or interruptible volume services. The project, which we estimate will cost $190 million, is supported by a new long-term, fee-based capacity commitment with a major producer. We expect to place this additional cryogenic processing capacity into service in mid-2014. Please read “Trends and Uncertainties” for a discussion of plant operations and the impact of processing gas with high NGL content.

Declaration of Common Unit Distribution. On April 11, 2012, our Board of Directors declared a cash distribution of $0.575 per common unit for the first quarter of 2012. This distribution will be paid on May 10, 2012 to all common unitholders of record at the close of business on April 30, 2012.

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 under Item 7 in our 2011 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 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 and completion technology, 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 they may suspend or reduce these activities when they have become uneconomic. The point at which producer activity becomes economic depends on a combination of factors in addition to commodity prices. In some cases producers of rich gas can benefit from NGL prices under their contracts; for these producers, strong NGL prices can offset the potential disincentive of weak natural gas prices. Strong crude oil prices may 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 producer’s financial resources (including access to debt and borrowing costs) and operating costs, the availability of necessary drilling equipment and services, the expected composition of wellhead production and the availability and proximity of downstream infrastructure, services and market outlets needed to accommodate it. 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 necessary to maintain their leasehold interests or capital commitments.

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Changes in drilling and completion activity are reflected in our throughput volumes only gradually because of the time required to complete and attach new wells (or if drilling is declining, because of continuing production from existing wells). Delays can range from a few days in areas with minimal completion and attachment processes to as long as 18 months if extensive dewatering or completion of downstream facilities is required. The impact of declines in drilling activity is mitigated to the extent we are entitled to deficiency fees under our producer contracts; however, we may be subject to increased credit risk over the period for which a producer is making payments to us that are not supported by physical volumes. In addition, our cash flow will be affected because deficiency fees are not paid monthly; rather, they become payable after the end of a longer commitment period, typically annually.

First-Quarter 2012 Commodity Prices Overall. First-quarter natural gas and crude oil prices on the NYMEX were down 23% and up 9%, respectively, compared to the fourth quarter of 2011. Our average NGL prices for the first quarter on the Mont Belvieu and Conway indices were down 12% and 10%, respectively, compared to the fourth 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.

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

	Quarterly Data for Texas
	Q1 2011		Q2 2011		Q3 2011		Q4 2011		Q1 2012
Houston Ship Channel ($/MMBtu)	$	4.06	$	4.29	$	4.23	$	3.49	$	2.65
Mont Belvieu ($/Bbl)	$	51.22	$	58.57	$	59.43	$	57.76	$	52.64
NYMEX crude oil ($/Bbl)	$	94.10	$	102.56	$	89.76	$	94.06	$	102.93
100%-Owned
Service throughput (MMBtu/d)		654,996		665,040		765,744		844,469		944,033
Plant inlet (MMBtu/d)		560,903		588,533		686,398		803,282		833,163
NGLs produced (Bbls/d)		23,228		26,913		30,904		33,951		35,344
Segment gross margin (in thousands)	$	45,011	$	46,134	$	44,540	$	48,752	$	45,341
Joint Ventures(1)
Pipeline throughput (MMBtu/d)		49,450		48,045		106,923		206,962		269,433
NGL throughput (Bbls/d)		—		—		4,252		4,946		13,000
Gross margin (in thousands)	$	422	$	720	$	6,706	$	23,347	$	9,815

(1) Includes 100% of results and volumes from Eagle Ford Gathering, Webb Duval, Liberty Pipeline Group and Double Eagle Pipeline.

The first-of-the-month price for natural gas on the Houston Ship Channel index was $2.11 per MMBtu for April 2012, and the spot price was $2.23 per MMBtu on May 4, 2012. The weighted-average daily price for NGLs at Mont Belvieu for April 2012, based on our first-quarter 2012 product mix, was $50.48 per Bbl.

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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.

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

	Quarterly Data for Oklahoma
	Q1 2011		Q2 2011		Q3 2011		Q4 2011		Q1 2012
CenterPoint East ($/MMBtu)	$	3.93	$	4.14	$	4.05	$	3.38	$	2.60
Conway ($/Bbl)	$	46.36	$	50.17	$	49.21	$	43.49	$	39.18
NYMEX crude oil ($/Bbl)	$	94.10	$	102.56	$	89.76	$	94.06	$	102.93
100%-Owned
Service throughput (MMBtu/d)		269,550		283,870		288,440		307,346		318,285
Plant inlet (MMBtu/d)		147,710		157,424		158,070		159,344		157,052
NGLs produced (Bbls/d)		16,037		17,331		17,453		17,471		16,961
Segment gross margin (in thousands)	$	23,082	$	28,665	$	27,876	$	25,457	$	24,199
Joint Ventures(1)
Plant inlet (MMBtu/d)		11,182		11,730		11,970		10,287		10,017
NGLs produced (Bbls/d)		393		432		429		358		363
Gross margin (in thousands)	$	1,421	$	1,364	$	1,331	$	980	$	1,003

(1) Includes 100% of results and volumes from Southern Dome.

The first-of-the-month price for natural gas on the CenterPoint East index was $2.01 per MMBtu for April 2012 and the spot price was $2.21 per MMBtu on May 4, 2012. The weighted-average daily price for NGLs at Conway for April 2012, based on our first-quarter 2012 product mix, was $34.89 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 first quarter of 2012 reflected a decrease in the average basis differential between Mont Belvieu and Conway, which was $10.39 per Bbl as compared to $13.99 per Bbl for the fourth quarter of 2011. Prices for purity ethane accounted for 47% of this basis differential. For April 2012, the basis differential averaged $12.36 per Bbl. The average basis differential between Houston Ship Channel and CenterPoint East natural gas index prices was $0.04 per MMBtu for the first quarter of 2012, $(0.02) per MMBtu for April 2012 and $0.02 on May 4, 2012.

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

(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.

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

	Quarterly Data for Rocky Mountains
	Q1 2011		Q2 2011		Q3 2011		Q4 2011		Q1 2012
Colorado Interstate Gas ($/MMBtu)	$	3.83	$	3.98	$	3.91	$	3.43	$	2.62
100%-Owned
Segment gross margin (in thousands)	$	1,042	$	771	$	432	$	396	$	358
Joint Ventures(1)
Pipeline throughput (MMBtu/d)		581,051		533,329		670,543		630,843		787,366
Gross margin (in thousands)	$	21,524	$	19,407	$	20,488	$	24,332	$	21,462

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(1) Includes 100% of results and volumes from Bighorn and Fort Union. Does not reflect an additional 127,503 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 quarter of 2012.

The first-of-the-month price for natural gas on the Colorado Interstate Index was $1.84 per MMBtu for April 2012 and the spot price was $1.95 per MMBtu on May 4, 2012.

Other Industry Trends. Continued growth in rich natural gas volumes from the rich gas shale plays has placed additional pressure on existing processing and liquids-handling infrastructure. NGL transportation and fractionation facilities continue to experience capacity constraints, and processing facilities, including ours, are also experiencing capacity constraints due to the very high NGL content of gas from these plays. Generally, to the extent that the NGL content of natural gas delivered for processing exceeds a processing plant’s design specifications, the plant’s overall NGL recoveries, or its recoveries of individual NGL products, are likely to be lower.

Transportation costs for heavier NGL products (butanes and gasolines) in Texas remain higher due to limited broad pipeline infrastructure and trucking capacity. In addition, we believe a lack of infrastructure is contributing to the wide 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.

Generally, capacity constraints result in higher processing, NGL transportation and fractionation costs for parties that do not have contractually fixed costs. In addition, midstream companies experiencing operational difficulties often curtail volumes, which typically has an immediate impact on cash flow and operating results for both the midstream company and the producers it serves. In the near term, these effects could limit the benefits producers receive from rich gas production and could affect the level of producer activity. A lack of downstream infrastructure over the longer term could eventually limit producers’ ability to continue drilling and production activity.

First-Quarter 2012 Drilling and Production Activity.

• Drilling. Drilling activity in the first 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 and Twin Rivers systems in Oklahoma and the north Barnett Shale Combo play behind our Saint Jo plant in Texas was consistent with late 2011 but began to decline in the Woodford Shale late in the quarter. Drilling activity in the Mississippi Lime area in northern 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 first quarter of 2012 increased 12% compared to the fourth quarter of 2011. Texas volume increases reflect a 30% increase in wholly owned Eagle Ford Shale volumes, a 104% increase in Eagle Ford Gathering volumes we received at our Houston Central complex and an 88% increase in volumes at our Lake Charles Plant, offset primarily by decreases in volumes received from Kinder Morgan. Volumes in Oklahoma were consistent with fourth-quarter 2011 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 34% as producers shifted volumes from other pipelines to Fort Union to take advantage of a more favorable pricing environment at markets downstream of Fort Union. Volumes on Bighorn declined 7% due to limited drilling activity in the Powder River Basin.

Factors Affecting Operating Results and Financial Condition

Our results for the first quarter of 2012 reflect reduced operating performance and intermittent downtime for repairs following a mechanical failure of the new 200 MMcf/d cryogenic facility at our Houston Central complex. In addition, operating performance at Houston Central was negatively affected by a substantial increase in the NGL content of gas deliveries due to rich Eagle Ford Shale volume growth coupled with a decline in third-party, lean gas volumes. The NGL content of natural gas deliveries exceeded the design specifications of the cryogenic facility and, to a greater degree, the lean oil facility. We estimate that these factors affecting the Houston Central complex reduced our first-quarter 2012 Texas segment gross margin by approximately $5.0 million as compared to the fourth quarter of 2011.

Our first-quarter results also reflect declines in natural gas and NGL prices in Texas and Oklahoma, which offset the benefits of natural gas volume growth due to strong drilling activity, particularly in the Eagle Ford Shale. In addition, we recorded $148.7 million in non-cash impairments relating to our Rocky Mountains assets, primarily based on the low natural gas price environment and our expectation of lower drilling activity in the Powder River Basin.

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Our cash flow from commodity hedge settlements increased during the first quarter of 2012, due in part to the expirations of swaps under which we paid cash settlements in the fourth quarter of 2011.

Outlook

Drilling Activity. So long as NGL and crude prices generally remain strong, we anticipate continued drilling activity in rich gas areas such as the Eagle Ford Shale, the north Barnett Shale Combo and the Hunton de-watering 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 we are installing pipeline and compression facilities in order to expand into the play from our existing assets in the area.

Natural gas prices have remained below the level at which producers have sufficient incentives to increase drilling in the Powder River Basin and many conventional drilling areas. Drilling and related activity in shale plays have consumed significant capital and other resources, which may effectively raise barriers to entry in other areas. In addition, natural gas prices have reached 10-year lows, due largely to a mild winter, limited storage space and growth in supplies from shale play activity. We expect that many producers who rely on conventional drilling, produce mainly lean gas, or both, will not resume significant drilling activity in the current natural gas price environment. In addition, activity in the Eagle Ford Shale over the long term could be impacted if low natural gas prices continue and NGL prices also decline.

Volume Growth and Infrastructure. A consequence of the increasing volumes from shale plays is the continuing need for investment in new infrastructure. Our ability to benefit from the strong NGL pricing environment and associated drilling activity is dependent on the successful completion of capital projects that we and some of our service providers have undertaken, which includes having facilities perform as we expect. The NGL content of gas we have been receiving at Houston Central (both overall NGL content and relative percentage of ethane) exceeds the design specifications of both our new cryogenic facility and, to a greater degree, our lean oil facility. This effectively reduces our overall processing capacity at Houston Central and subjects us to other operating risks, such as lower NGL recoveries and NGL-handling capacity constraints.

As discussed above, our first-quarter operating results were impacted by underperformance of, and downtime for repairs to, the new cryogenic processing facility at our Houston Central complex. With additional repairs and modifications that we completed in April, the new facility has since been meeting our performance expectations. We plan to install two additional 400 MMcf/d cryogenic trains in 2013 and 2014, which ultimately should enable us to relegate the lean oil facility to providing overflow or interruptible volume services. Until the new facilities are complete, we expect that the high NGL content of Eagle Ford Shale gas will continue to impact our operating performance at the Houston Central complex.

We expect that over the next two years, the wide basis differential affecting Texas and Oklahoma NGL prices in recent months will be moderated by new fractionation facilities and NGL transportation infrastructure, including new NGL pipelines linking the Mid-Continent to the Gulf Coast.

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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.

For additional discussion about these non-GAAP measures and our other financial and operating performance measures, please read “—How We Evaluate Our Operations” under Item 7 in our 2011 10-K.

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. As described in “—How We Evaluate Our Operations” under Item 7 in our 2011 10-K, we revised our calculations of adjusted EBITDA and total distributable cash flow beginning in the second quarter of 2011. To allow for direct comparisons to 2012 activity, the reconciliations of adjusted EBITDA and total distributable cash flow for the three months ended March 31, 2011 have been recast to conform with the revised calculations.

	Three Months Ended March 31,
	2012			2011
	(In thousands)
Reconciliation of total segment gross margin to operating (loss) income:
Operating (loss) income	$	(132,684	)	$	16,352
Add: Operations and maintenance expenses		18,642			15,099
Depreciation and amortization		19,088			16,869
Impairment		28,744			—
General and administrative expenses		14,944			12,598
Taxes other than income		1,366			1,130
Equity in loss (earnings) from unconsolidated affiliates		114,728			(1,702	)
Total segment gross margin	$	64,828		$	60,346
Reconciliation of EBITDA, adjusted EBITDA and total distributable cash flow to net (loss) income:
Net (loss) income	$	(147,671	)	$	3,532
Add: Depreciation and amortization		19,088			16,869
Interest and other financing costs		14,424			11,916
Provision for income taxes		601			911
EBITDA		(113,558	)		33,228
Add: Amortization of commodity derivative options		5,039			7,270
Distributions from unconsolidated affiliates		10,329			6,473
Equity-based compensation		3,231			2,982
Equity in loss (earnings) from unconsolidated affiliates		114,728			(1,702	)
Unrealized loss (gain) from commodity risk management activities		579			(543	)
Impairment		28,744			—
Other non-cash operating items		1,233			(275	)
Adjusted EBITDA		50,325			47,433
Less: Interest expense		(14,233	)		(11,607	)
Current income tax expense and other		(329	)		(331	)
Maintenance capital expenditures		(2,443	)		(2,046	)
Total distributable cash flow	$	33,320		$	33,449

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How We Manage Our Operations

Our management team uses a variety of tools to manage our business. These tools include: (i) our economic models, (ii) flow and transaction monitoring systems, (iii) producer activity evaluation and reporting, (iv) imbalance monitoring and control and (v) measurement and loss reports. For a further discussion, please read “—How We Manage Our Operations” under Item 7 in our 2011 10-K.

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Our Results of Operations

	Three Months Ended March 31,
	2012			2011
	($ In thousands)
Total segment gross margin(1)	$	64,828		$	60,346
Operations and maintenance expenses		18,642			15,099
Depreciation and amortization		19,088			16,869
Impairment		28,744			—
General and administrative expenses		14,944			12,598
Taxes other than income		1,366			1,130
Equity in loss (earnings) from unconsolidated affiliates(2)(3)		114,728			(1,702	)
Operating (loss) income		(132,684	)		16,352
Interest and other financing costs, net		(14,386	)		(11,909	)
Provision for income taxes		(601	)		(911	)
Net (loss) income		(147,671	)		3,532
Preferred unit distributions		(8,698	)		(7,880	)
Net loss to common units	$	(156,369	)	$	(4,348	)
Basic and diluted net loss per common unit	$	(2.20	)	$	(0.07	)
Weighted average number of common units		70,960			65,985
Total segment gross margin:
Texas	$	45,341		$	45,011
Oklahoma		24,199			23,082
Rocky Mountains(4)		358			1,042
Segment gross margin		69,898			69,135
Corporate and other(5)		(5,070	)		(8,789	)
Total segment gross margin(1)	$	64,828		$	60,346
Segment gross margin per unit:
Texas:
Service throughput ($/MMBtu)	$	0.53		$	0.76
Oklahoma:
Service throughput ($/MMBtu)	$	0.84		$	0.95
Volumes:
Texas: (6)
Service throughput (MMBtu/d)(7)		944,033			654,996
Pipeline throughput (MMBtu/d)		565,508			399,033
Plant inlet volumes (MMBtu/d)		833,163			560,903
NGLs produced (Bbls/d)		35,344			23,228
Oklahoma:(8)
Service throughput (MMBtu/d)(7)		318,285			269,550
Plant inlet volumes (MMBtu/d)		157,052			147,710
NGLs produced (Bbls/d)		16,961			16,037
Capital Expenditures:
Maintenance capital expenditures	$	2,443		$	2,046
Expansion capital expenditures		48,363			51,520
Total capital expenditures	$	50,806		$	53,566
Operations and maintenance expenses:
Texas	$	10,618		$	8,825
Oklahoma		7,981			6,219
Rocky Mountains		43			55
Total operations and maintenance expenses	$	18,642		$	15,099

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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) During the three months ended March 31, 2012, we recorded a $120 million non-cash impairment charge relating to our investments in Bighorn and Fort Union.

(3) Includes results and volumes associated with our unconsolidated affiliates. The following table summarizes the throughput for the periods indicated:

		Three Months Ended March 31,
		2012		2011
Bighorn and Fort Union(a)	(MMBtu/d)		787,366		581,051
Southern Dome:
Plant inlet	(MMBtu/d)		10,017		11,182
NGLs produced	(Bbls/d)		363		393
Webb Duval(b)	(MMBtu/d)		61,935		49,450
Eagle Ford Gathering	(MMBtu/d)		207,498		—
Liberty Pipeline Group	(Bbls/d)		13,000		—

(a) Fort Union volumes do not reflect an additional 127,503 MMBtu/d and 288,966 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 for the three months ended March 31, 2012 and 2011, respectively.

(b) Net of intercompany volumes.

(4) 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.

(5) Corporate and other includes results attributable to our commodity risk management activities.

(6) 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.

(7) “Service throughput” means the volume of natural gas delivered to our 100%-owned processing plants by third-party pipelines plus our “pipeline throughput,” which is the volume of natural gas transported or gathered through our pipelines.

(8) 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 March 31, 2012 Compared To Three Months Ended March 31, 2011

Texas Segment Gross Margin. Texas segment gross margin was $45.3 million for the three months ended March 31, 2012 compared to $45.0 million for the three months ended March 31, 2011, an increase of $0.3 million, or 1%, reflecting a 3% increase in NGL prices. The Texas segment gross margin also benefited from increases in gathering, NGL production and processed volumes of 42%, 52% and 49%, respectively, during the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. 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. Also, the Lake Charles processing plant contributed $1.7 million to Texas gross margin during the three months ended March 31, 2012 as compared to the three months ended March 31, 2011. The impact of the Lake Charles plant and volume increases were offset by lower NGL recoveries at Houston Central due to underperformance and downtime of the cryogenic facility and gas with NGL content in excess of plant specifications. Despite these volume increases, Texas segment gross margin per unit of service throughput decreased $0.23 per MMBtu to $0.53 per MMBtu for the three months ended March 31, 2012 compared to $0.76 per MMBtu for the three months ended March 31, 2011 mainly due to lower prices and operating performance at the Houston Central complex.

Oklahoma Segment Gross Margin. Oklahoma segment gross margin was $24.2 million for the three months ended March 31, 2012 compared to $23.1 million for the three months ended March 31, 2011, an increase of $1.1 million, or 5%. The increase in segment gross margin is primarily due to a period-over-period increase in service throughput, NGL production and plant inlet volumes of 18%, 6% and 6%, respectively, resulting from Woodford Shale volume growth and the April 1, 2011 acquisition of the Harrah plant. The Harrah plant acquisition added $1.3 million of gross margin during the three months ended March 31, 2012. Commodity price declines offset the impact of volume growth, as NGL prices declined 15% and average natural gas prices declined 34%. As a result of these price declines coupled with an increase in lower-margin lean gas, our Oklahoma segment gross margin per unit of service throughput decreased $0.11 per MMBtu to $0.84 per MMBtu for the three months ended March 31, 2012 compared to $0.95 per MMBtu for the three months ended March 31, 2011.

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Rocky Mountains Segment Gross Margin. Rocky Mountains segment gross margin was $0.4 million for the three months ended March 31, 2012 compared to $1.0 million for the three months ended March 31, 2011, a decrease of $0.6 million, or 60%. This decrease is primarily the result of our inability to resell all of our demand capacity under our firm gathering agreement with Fort Union because of production declines in the area and increased demand fees under the agreement.

Corporate and Other. Corporate and other includes our commodity risk management activities and was a loss of $5.1 million for the three months ended March 31, 2012 compared to a loss of $8.8 million for the three months ended March 31, 2011. The loss for the three months ended March 31, 2012 included $5.0 million of non-cash amortization expense relating to the option component of our commodity derivative instruments and $0.6 million of unrealized losses on our commodity derivative instruments offset by $0.5 million of net cash settlements received for expired commodity derivative instruments. The loss for the three months ended March 31, 2011 included $7.3 million of non-cash amortization expense relating to the option component of our commodity derivative instruments and $2.1 million of net cash settlements paid on expired commodity derivative instruments offset by $0.6 million of unrealized gain on our commodity derivative instruments.

Operations and Maintenance Expenses. Operations and maintenance expenses totaled $18.6 million for the three months ended March 31, 2012 compared to $15.1 million for the three months ended March 31, 2011. The 23% increase is attributable primarily to (i) increased payroll, utilities, chemicals and repair and maintenance expenses in our Texas segment of $1.8 million, including expenses for expanded operations related to new Eagle Ford Shale assets, and (ii) increased payroll, operating costs for new compressors, fuel, utilities and supplies expenses in our Oklahoma segment of $1.7 million, including expenses for the operations of the Harrah plant acquired in April 2011.

Depreciation and Amortization. Depreciation and amortization totaled $19.1 million for the three months ended March 31, 2012 compared with $16.9 million for the three months ended March 31, 2011, an increase of 13%. This increase relates primarily to additional depreciation and amortization resulting from capital expenditures made after March 31, 2011, including expenditures relating to the fractionation expansion at our Houston Central complex, our DK pipeline extension and the acquisition of the Harrah plant.

Impairment. Impairment expense for the three months ended March 31, 2012 related to a $28.7 million non-cash impairment charge on a contract under which we provide services to Rocky Mountains producers. This impairment is primarily based on the low natural gas price environment and our expectations for a lower level of drilling by producers in the Powder River Basin.

General and Administrative Expenses. General and administrative expenses totaled $14.9 million for the three months ended March 31, 2012 compared to $12.6 million for the three months ended March 31, 2011. The 18% increase consists primarily of (i) increases in personnel, compensation and benefits costs of $2.4 million and (ii) an increase of $0.9 million in non-cash compensation expense related to amortization of the fair value of equity awards issued under our Long-Term Incentive Plan, partially offset by (i) a $0.6 million reduction in tax and other professional services and (ii) a reduction in expenses for acquisition initiatives that were not consummated of $0.4 million.

Equity in Loss/Earnings from Unconsolidated Affiliates. Equity in loss from unconsolidated affiliates totaled $114.7 million for the three months ended March 31, 2012 compared to earnings of $1.7 million for the three months ended March 31, 2011, a decrease of $116.4 million. The loss for the three months ended March 31, 2012 consists of a $120 million non-cash impairment charge on our investments in Bighorn and Fort Union, primarily based on the low natural gas price environment and our expectations for a lower level of drilling by producers in the Powder River Basin, partially offset by $2.1 million equity earnings from Eagle Ford Gathering and $3.2 million of equity earnings from our other unconsolidated affiliates for the three months ended March 31, 2012. Equity in earnings from unconsolidated affiliates for the three months ended March 31, 2011 consisted of $2.2 million of equity earnings from Fort Union and $0.7 million of equity earnings from Southern Dome offset by $1.2 million of equity loss from Bighorn and our other unconsolidated affiliates.

Interest and Other Financing Costs. Interest and other financing costs totaled $14.4 million for the three months ended March 31, 2012 compared to $11.9 million for the three months ended March 31, 2011, an increase of $2.5 million, or 21%. The increase in interest and other financing costs resulted from a $2.6 million increase in interest expense on our secured revolving credit facility and senior unsecured notes offset by a $0.1 million decrease in unrealized mark-to-market gains on undesignated interest rate swaps. Average borrowings under our credit arrangements for the three months ended March 31, 2012 and 2011 were $887.7 million and $624.3 million, respectively, with average interest rates of 7.2% and 8.7%, respectively. Please read “— Liquidity and Capital Resources — Our Indebtedness.”

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Cash Flows

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

	Three Months Ended March 31,
	2012			2011
	(In thousands)
Net cash provided by operating activities	$	22,114		$	28,531
Net cash used in investing activities	$	(67,480	)	$	(67,170	)
Net cash provided by financing activities	$	46,741		$	48,097

Operating Cash Flows. Net cash provided by operating activities was $22.1 million for the three months ended March 31, 2012 compared to $28.5 million for the three months ended March 31, 2011. The decrease in cash provided by operating activities of $6.4 million was attributable to the following changes:

• a $20.9 million decrease in cash flow provided by operating activities for the three months ended March 31, 2012 compared with the same period in 2011;

partially offset by:

• a $10.9 million decrease in interest payments in 2012 compared to the same period in 2011 as a result of the timing of our interest payments;

• a $3.0 million decrease in cash flow used for risk management activities for 2012 as compared to 2011; and

• a $0.6 million increase in distributions received from our unconsolidated affiliates in 2012 compared to the same period in 2011.

Investing Cash Flows. Net cash used in investing activities was $67.5 million and $67.2 million for the three months ended March 31, 2012 and 2011, respectively. Investing activities for the three months ended March 31, 2012 included (i) $52.3 million of capital expenditures related to our Eagle Ford Shale growth strategy and well connections attaching volumes in new areas (please read “—Liquidity and Capital Resources — Capital Expenditures” for additional details) and (ii) $19.4 million of investments in Eagle Ford Gathering, Double Eagle Pipeline and Bighorn, offset by $4.2 million of distributions from Eagle Ford Gathering, Bighorn and Southern Dome in excess of equity earnings. Investing activities for the three months ended March 31, 2011 included (i) $41.3 million of capital expenditures related to our Eagle Ford Shale growth strategy and well connections attaching volumes in new areas and (ii) $26.8 million of investments in Eagle Ford Gathering, Liberty Pipeline Group and Bighorn, offset by (i) $0.9 million of distributions from Bighorn in excess of equity earnings.

Financing Cash Flows. Net cash provided by financing activities totaled $46.7 million during the three months ended March 31, 2012 and included (i) net proceeds from our issuance of common units of $187.7 million, (ii) issuance of our senior unsecured notes due 2021 of $153.4 million, (iii) proceeds from borrowings on our revolving credit facility of $67.0 million and (iv) proceeds from the exercise of common unit options of $0.7 million offset by (i) repayment of our revolving credit facility of $317.0 million, (ii) distributions to our unitholders of $41.7 million and (iii) deferred financing costs of $3.4 million. Net cash provided by financing activities totaled $48.1 million during the three months ended March 31, 2011 and included (i) borrowings under our revolving credit facility of $85 million and (ii) proceeds from the exercise of common unit options of $1.1 million offset by (i) distributions to our unitholders of $37.9 million and (iii) deferred financing costs of $0.1 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. We expect to fund short-term cash requirements, such as operating expenses, capital expenditures to sustain existing operations and quarterly distributions to our unitholders through operating cash flows. We expect to fund long-term cash requirements for expansion projects and acquisitions through 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.

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For additional discussion, please read “—Our Long-Term Growth Strategy” under Item 7 in our 2011 10-K.

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 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 three months ended March 31, 2012, our capital expenditures totaled $50.8 million, consisting of $2.4 million of maintenance capital and $48.4 million of expansion capital. We used funds from operations and borrowings under our revolving credit facility to fund our capital expenditures. Our expansion capital expenditures related mainly to (i) the cryogenic processing upgrade at our Houston Central complex, (ii) extension of our DK pipeline to the Houston Central complex, (iii) the initial 400 MMcf/d cryogenic expansion at our Houston Central complex, (iv) construction of lateral pipelines and well connections to attach volumes from the Eagle Ford Shale and the north Barnett Shale Combo plays, (v) addition of an amine treater to the Saint Jo complex and (vi) the southwest extension of our DK pipeline. We anticipate incurring approximately an additional $240 million in expansion capital expenditures in 2012 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.

Investment in Unconsolidated Affiliates. During the three months ended March 31, 2012, our capital contributions to our unconsolidated affiliates totaled $19.4 million and consisted primarily of contributions to Eagle Ford Gathering for construction of gathering pipelines and the related crossover project, and to Double Eagle Pipeline for its construction of its condensate/crude gathering system. We anticipate making additional cash contributions of approximately $58.5 million to Double Eagle Pipeline for the construction of its gathering system, $12.1 million to Eagle Ford Gathering for completion of its gathering pipelines, the crossover project and related facilities and $1.0 million to Liberty Pipeline Group for completion of facilities related to its NGL pipeline.

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 ongoing projects related to this strategy; please refer to the description of our Texas segment under Item 1., “Business,” in our 2011 10-K for summaries of completed projects.

Eagle Ford Shale Expansion Projects
Project	Miles		Diameter		Change in Capacity(1)			Total Capacity(1)			Estimated Capital			Expected In-Service Date
			(range)		(expansions only)						($ in millions)
Ongoing
100%-Owned
Houston Central cryogenic upgrade		—		—		—	(2)		700,000	(2)(3)	$	21		Second Quarter 2012(2)
Houston Central processing expansion		—		—		400,000			1,100,000	(3)	$	145		First Quarter 2013
Houston Central additional cryogenic capacity		—		—		—			1,000,000	(4)	$	190		First Half 2014
Goebel conversion(5)		46		12”-14”		—			—	(6)	$	17		Fourth Quarter 2012
DK pipeline southwest extension		65		24”		195,000			—	(7)	$	120		Second Quarter 2013
Joint Ventures
Double Eagle Pipeline		142		12”-16”		—			100,000	(8)	$	150	(9)	Second Quarter 2013

(1) Natural gas capacity and volumes are presented in Mcf/d. NGL and condensate capacity and volumes are presented in Bbls/d.

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(2) Consists of upgrading our existing processing facility with a more efficient cryogenic tower to allow for processing of very rich natural gas from the Eagle Ford Shale. With additional repairs and modifications completed in April 2012, the new tower has been meeting performance expectations.

(3) Reflects the facility’s overall nameplate capacity, but processing capacity will be lower to the extent that the NGL content of inlet gas exceeds the design specifications of one or more of the facility’s components.

(4) Consists of installing new, more efficient cryogenic processing capacity designed to process gas with higher NGL content, which ultimately should enable us to relegate the 500,000 MMcf/d lean oil processing facility to providing overflow and interruptible volume services.

(5) We are converting our Goebel pipeline from natural gas to condensate service and will lease the pipeline to Double Eagle Pipeline for condensate transportation service.

(6) The Double Eagle Pipeline system and the Goebel pipeline together will provide 100,000 Bbls/d of condensate transportation capacity from the Eagle Ford Shale to the Texas Gulf Coast.

(7) The DK pipeline with the southwest extension will have 350,000 Mcf/d of capacity.

(8) Includes lateral pipelines and equipment for interconnections between the crossover pipeline and Williams Partners, LP’s and Formosa Hydrocarbons Company’s processing plants.

(9) Joint venture project costs presented are gross amounts; our share of such costs is 50%.

Cash Distributions. The amount of cash on hand 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)	$	42,113		$	168,454

(1) Includes distributions on restricted common units and phantom units issued under our LTIP. Distributions made on restricted units and phantom units issued to date are subject to the same vesting provisions as the restricted units and phantom units. As of April 30, 2012, we had 43,600 outstanding restricted units and 960,179 outstanding phantom units.

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

Recent commodity prices and financial market conditions have supported significant opportunities for volume growth from shale resource plays. Our ability to benefit from growth projects to accommodate strong drilling activity is subject to operational risks and uncertainties such as the uncertainty inherent in some of the assumptions underlying design specifications for new, modified or expanded facilities. When one or more of these assumptions proves to be incorrect, our facilities may not perform as we expect, and our ability to generate cash from operations and to comply with our obligations, including the covenants under our debt instruments, may be adversely affected. Conversely, actual production delivered may fall below volume estimates on which we relied in deciding to pursue an acquisition or other growth project. 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 cash flow and ability to comply with our debt covenants would likewise be adversely affected if we experienced declining volumes in combination with unfavorable commodity prices over a sustained period.

We believe that our cash from operations, cash on hand and our revolving credit facility will provide sufficient liquidity to meet our short-term capital requirements and to fund our committed capital expenditures for at least the remainder of 2012. 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.

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 throughout 2011 and in the first quarter of 2012 to hedge against potential future declines in commodity prices.

Our Indebtedness

As of March 31, 2012, our aggregate outstanding indebtedness totaled $897.9 million and we were in compliance with the financial covenants under our senior secured revolving credit facility and our incurrence covenants under the indentures governing our senior unsecured notes.

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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.

Revolving Credit Facility. As of March 31, 2012, we had $135.0 million of indebtedness and no letters of credit outstanding under our senior secured revolving credit facility with Bank of America, N.A., which matures June 10, 2016. 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 March 31, 2012, our consolidated leverage ratio was 3.85 to 1.0.

• The maximum senior secured leverage ratio (total senior secured debt to Consolidated EBITDA as defined in the amended credit agreement) permitted under the agreement is 4.0 to 1.0. Up to 15% of our Consolidated EBITDA for purposes of calculating this ratio may consist of Material Project EBITDA. At March 31, 2012, our senior secured leverage ratio was 0.59 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 March 31, 2012, our consolidated interest coverage ratio was 3.85 to 1.00.

Based on our trailing four-quarter Consolidated EBITDA, as defined under the amended credit agreement, at March 31, 2012, we could borrow an additional $326.6 million before reaching our maximum leverage ratio of 5.25 to 1.0.

Please read “— How We Evaluate Our Operations” under Item 7 in our 2011 10-K 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 March 31, 2012, our ratio of consolidated cash flow to fixed charges was 3.39 to 1.0.

For additional information on our indebtedness, please read Note 5, “Long-Term Debt,” included in Item 1 of this report.

Off-Balance Sheet Arrangements

We had no off-balance sheet arrangements as of March 31, 2012.

Recent Accounting Pronouncements

For information on new accounting pronouncements, please read Note 2, “New Accounting Pronouncements,” 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 “—Critical Accounting Policies and Estimates” under Item 7 in our 2011 10-K.

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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 these risks. In general, we attempt to hedge risks related to the variability of our future cash flow and profitability resulting from changes in applicable commodity prices or interest rates so that we can maintain cash flows sufficient to meet debt service, required capital expenditures, distribution objectives and similar requirements. Our risk management policy prohibits the use of derivative instruments for speculative purposes.

Commodity Price Risk

NGL and natural gas prices can be volatile and are impacted by changes in fundamental supply and demand, as well as market uncertainty and a variety of additional factors that are beyond our control. Our profitability is directly affected by prevailing commodity prices primarily as a result of: (i) processing at our processing plants or third-party processing plants, (ii) purchasing and selling or gathering and transporting volumes of natural gas at index-related prices and (iii) transporting and fractionating NGLs at index-related prices. To the extent that they influence the level of drilling activity, commodity prices also affect all of our segments indirectly.

Our Contracts

Our contract mix reflects a variety of pricing terms typical for the midstream industry, with varying levels of commodity price sensitivity, including fee-based, percent-of-proceeds, percent-of-index and keep-whole terms. Please refer to “Business – Industry Overview– Midstream Contracts” under Item 1 in our 2011 10-K for detailed descriptions of these arrangements. 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. Generally:

• our margins from fee-based pricing are directly related to the volumes of natural gas or NGLs that flow through our systems and are not directly affected by commodity prices;

• our margins from percent-of-proceeds (including percent-of-liquids) pricing and percent-of-index pricing for lean gas that does not require processing are generally directly related to the prices for natural gas, NGLs or both; in other words, our margins increase or decrease as prices increase or decrease; and

• our margins from keep-whole pricing and percent-of-index pricing involving gas that we process are related not only to natural gas and NGL prices but also to the spread between natural gas and NGL prices. As NGL prices increase relative to natural gas prices, our margins increase, and if NGL prices decrease relative to natural gas prices, our margins decrease. Our keep-whole contracts sometimes include terms that help us avoid incurring losses that would result if NGL prices fell near or below natural gas prices, such as allowing us to charge fees and reduce the volume of NGLs we recover during unfavorable pricing environments. Also, to the extent our contract entitles us to keep extracted NGLs, we may share a portion of our processing margin with the counterparty when processing margins are favorable.

In addition, some of our fee-based and percent-of-proceeds contracts include “fixed recovery” provisions, which operate in conjunction with the contract’s main pricing terms. Under fixed recovery terms, we determine the amount payable, or the volumes of residue gas and NGLs deliverable, to the counterparty based on contractual NGL recovery factors. Fixed recovery terms can affect our margins to the extent that our actual recoveries vary from the agreed NGL recovery factor. If we exceed fixed recoveries when processing margins are favorable, our margins will benefit to the extent of the difference. However, our margins will decrease to the extent we do not meet the NGL recovery factor in a favorable processing margin environment, and we could incur losses. If NGL prices are unfavorable relative to natural gas prices, we would be able to increase our margins by reducing our recoveries.

The table below illustrates the commodity sensitivity affecting our gross margin, as a percentage of our quarterly total segment gross margin and our share of the gross margin from each of our unconsolidated affiliates. The contract types presented indicate what portion of our gross margin was generated under each of the pricing terms listed, rather than under categories of contracts. As noted above, many of our contracts use a combination of pricing terms to help reduce our commodity price risk; therefore, a single contract will likely contribute to multiple categories in the table below.

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Contract Pricing(1)	Q1 2011			Q2 2011			Q3 2011			Q4 2011			Q1 2012(5)
Fee-based		41	%		41	%		43	%		47	%		58	%
Percentage-of-proceeds(2)		32	%		33	%		31	%		27	%		26	%
Keep-whole and other(3)		39	%		40	%		36	%		41	%		22	%
Net hedging(4)		(12	)%		(14	)%		(10	)%		(15	)%		(6	)%

(1) Gross margin attributable to percent-of-index arrangements for lean gas is immaterial and has not been set forth separately.

(2) Gross margin attributable to percentage-of proceeds pricing increases as commodity prices increase.

(3) 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. “Other” consists of percent-of-index arrangements involving rich gas and the effects of variations from agreed fixed recoveries.

(4) Net impact of our commodity derivative instruments to total segment gross margin.

(5) Higher fee-based and lower keep-whole percentages reflect a combination of factors, primarily: growth in fee-based Eagle Ford Shale volumes; conversion of a temporary, keep-whole processing arrangement into a fee-based arrangement; and effects of losses we incurred under contracts with fixed recovery terms because of Houston Central complex operating performance. Please read “Management’s Discussion and Analysis—Trends and Uncertainties.”

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 three months ended March 31, 2012. We also calculated that a $0.10 per MMBtu increase in the price of natural gas would have resulted in a $0.1 million increase to our total segment gross margin, and vice versa, for the three months ended March 31, 2012. 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. Strike prices exceeded commodity prices during the first three months of 2012, partially reducing our commodity price sensitivity for the period.

Our Hedge Portfolio

Commodity Hedges. As of March 31, 2012, our commodity hedge portfolio assets totaled $9.0 million. For additional information, please read Note 11, “Financial Instruments,” included in Item 1 of this report.

		xxxxxxxx.xx		xxxxxxxx.xx
	Put
	Strike		Volumes
	(Per gallon)		(Bbls/d)
Mont Belvieu Purity Ethane
2012	$	0.5900		1,000
2012	$	0.5900		500
2012	$	0.6700		400
Mont Belvieu TET Propane
2012(1)	$	1.1500		700
2012	$	1.0700		600
2012	$	1.1700		600
2012(1)	$	1.3200		400
2013	$	1.2400		600
2013	$	1.2750		350
2013	$	1.2200		300
2013	$	1.2800		300
2013	$	1.3300		250
(1)    Instrument not designated as a cash flow hedge under hedge accounting
Mont Belvieu Non-TET Isobutane
2012	$	1.3900		165
2012(1)	$	1.3900		285
2013	$	1.6000		200
2013	$	1.6800		100
2013	$	1.9000		50

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	Put
	Strike		Volumes
	(Per gallon)		(Bbls/d)
Mont Belvieu Non-TET Normal Butane
2012	$	1.3500		250
2012	$	1.3600		125
2012(1)	$	1.3600		225
2012(1)	$	1.4600		150
2013	$	1.5800		300
2013	$	1.6500		100
2013	$	1.8000		100
WTI Crude Oil
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
2013	$	95.00		100
2013(1)	$	95.00		250
(1)    Instrument not designated as a cash flow hedge under hedge accounting

Interest Rate Swaps. As of March 31, 2012, the fair value of our interest rate swaps liability totaled $2.7 million. For additional information on our interest rate swaps, please read Note 11, “Financial Instruments,” 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 three months ended March 31, 2012, Dow Hydrocarbon and Resources LLC, (16%), ONEOK Hydrocarbons, L.P. (14%), Enterprise Products Operating, L.P. (8%), Formosa Hydrocarbons Company, Inc. (8%), and ONEOK Energy Services, L.P. (7%) collectively accounted for approximately 53% of our revenue. As of March 31, 2012, all of these companies or their respective parent companies were rated investment grade by Moody’s Investors Service and Standard & Poor’s Ratings Services, except for Formosa Hydrocarbons Company. Formosa Hydrocarbons Company’s parent, Formosa Plastics Corporation, U.S.A., is affiliated with the Taiwan-based Formosa Plastics Group, which is rated investment grade by Standard & Poor’s Ratings Services. Companies accounting for another approximately 32% of our revenue have an investment grade parent, are themselves investment grade, have provided us with credit support in the form of a letter of credit issued by an investment grade financial institution or have provided prepayment for our services.

We also diligently review the creditworthiness of other counterparties to which we may have credit exposure, including hedge counterparties. Our risk management policy requires that we review and report the credit ratings of our hedging counterparties on a monthly basis. As of March 31, 2012, the value of our commodity net hedge positions by counterparty consisted of assets with JP Morgan (35%), Credit Suisse (14%), BBVA (11%), Scotia Bank (11%), Barclays Bank PLC (11%), Goldman Sachs (10%), Wells Fargo (5%) and Bank of America (3%). As of March 31, 2012, 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.

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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 March 31, 2012 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 March 31, 2012 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 11, “Commitments and Contingencies,” included in Part II, Item 8 in our 2011 10-K. There have been no material updates to the legal proceedings reported in our 2011 10-K.

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 2011 10-K. These risks and uncertainties could materially adversely affect our business, financial condition and results of operations. If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be materially adversely affected.

Recently approved final rules regulating air emissions from natural gas processing operations could cause us to incur increased capital expenditures and operating costs, which may be significant.

On April 17, 2012, the EPA approved final rules that establish new air emission controls for natural gas and natural gas liquids production, processing and transportation activities, including New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds, and a separate set of emission standards to address hazardous air pollutants frequently associated with production and processing activities. Among other things, the rules establish specific requirements regarding emissions from compressors and controllers at natural gas gathering and boosting stations and processing plants together with dehydrators and storage tanks at natural gas processing plants, compressor stations and gathering and boosting stations. In addition, the rules establish new requirements for leak detection and repair of leaks at natural gas processing plants that exceed 500 parts per million in concentration. Although we believe this rule will not have a material impact on our current operations, it may increase our capital expenditures and operating costs associated with facilities we construct or acquire in the future. For example, we may be required to install new equipment to control emissions from compressors that could result in significant costs.

Constructing new assets subjects us to risks of project delays, cost overruns and lower- or higher-than-anticipated volumes of natural gas, NGLs or condensate once a project is completed. Our operating cash flows from our capital projects may not be immediate or meet our expectations.

One of the ways we grow our business is by constructing additions or modifications to our existing facilities. We also construct new facilities, either near our existing operations or in new areas. Construction projects require significant amounts of capital and involve numerous regulatory, environmental, political, legal, operational and geological uncertainties, many of which are beyond our control. These projects also involve numerous economic uncertainties, including the impact of inflation on project costs and the availability of required resources.

We may be unable to complete construction projects on schedule, at the budgeted cost, or at all, which could have a material adverse effect on our business and results of operations. Moreover, we may not receive any material increase in operating cash flow from a project for some time. For instance, if we expand a pipeline or processing facility, the construction expenditures may occur over an extended period of time, yet we will not receive any material increases in cash flow until the project is completed and fully operational.

Our cash flow from a project may be delayed or may not meet our expectations. Our project specifications and expectations regarding project cost, timing, asset performance, investment returns and other matters usually rely in part on the expertise of third parties such as producers whose gas we gather, engineers, technical experts and construction contractors. These estimates may prove to be inaccurate because of numerous operational, technological, geologic, economic and other uncertainties. Recently, we experienced an extended period of reduced operating performance of and intermittent downtime for repairs to a new cryogenic processing facility at our Houston Central complex, which negatively impacted our operating performance for the first quarter of 2012. In April, we completed additional repairs and modifications to enhance the new facility’s performance, and we expect the associated downtime will negatively impact our second-quarter 2012 performance. We also rely in part on estimates from producers regarding the timing, volume and composition of anticipated oil, gas or condensate production to determine the capacity and operating specifications of new facilities. Production and gas composition estimates are subject to numerous uncertainties beyond our control and may prove to be inaccurate. When the composition of actual production differs significantly from estimates on which we rely, as has occurred recently at our Houston Central complex, newly constructed, modified or expanded facilities may be unable to perform at the levels we expect. Conversely, actual production delivered may fall below volume estimates on which we rely. In either case, we may be unable to achieve our expected cash flow and investment returns. Please read “Management’s Discussion and Analysis—Trends and Uncertainties—Outlook.”

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We also construct assets in reliance on firm capacity commitments for third-party processing or fractionation downstream of our facilities. For example, we made processing commitments at our Houston Central complex and constructed the Liberty NGL pipeline through our joint venture with Energy Transfer in reliance on Formosa’s capacity commitment to us, which requires Formosa to expand its facilities. If Formosa is unable to meet its commitment to us, or if other third-party facilities are not available when we expect them, our cash flows and results of operations would be adversely affected.

Item 6. Exhibits.

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) or double asterisk (**) and are filed or furnished 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).
4.8	Form of Global Note representing 7.125% Senior Notes due 2021 (included in Exhibit A to Exhibit 4.5 above).
10.1	First Amendment to Second Amended and Restated Credit Agreement, dated as of January 4, 2012, among Copano Energy, L.L.C., as the Borrower, Bank of America, N.A., as Administrative Agent, Swing Line Lender and L/C Issuer, and the lender party thereto (incorporated by reference to Exhibit 10.1 to the Current Report on Form 8-K filed January 10, 2012).
10.2	2012 Administrative Guidelines for Copano Energy, L.L.C. Management Incentive Compensation Plan (incorporated by reference to Exhibit 10.2 to the Current Report on Form 8-K filed February 21, 2012).

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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 May 10, 2012.

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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