UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

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

For the quarterly period ended June 30, 2012

OR

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

Commission file number:  001-32329

Copano Energy, L.L.C.

(Exact Name of Registrant as Specified in Its Charter)

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

1200 Smith Street, Suite 2300

Houston, Texas 77002

(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  o

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company.  See 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 o
Non-accelerated filer o	Smaller reporting company o

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

There were 72,396,381 common units of Copano Energy, L.L.C. outstanding on August 6, 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 June 30, 2012 and December 31, 2011	3
	Unaudited Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2012 and 2011	4
	Unaudited Consolidated Statements of Comprehensive Income (Loss) for the Three and Six Months Ended June 30, 2012 and 2011	5
	Unaudited Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2012 and 2011	6
	Unaudited Consolidated Statements of Members’ Capital for the Six Months Ended June 30, 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	35
Item 3.	Quantitative and Qualitative Disclosures About Market Risk	53
Item 4.	Controls and Procedures	57
	PART II — OTHER INFORMATION
Item 1.	Legal Proceedings	58
Item 1A.	Risk Factors	58
Item 6.	Exhibits	58

2

Item 1.  Financial Statements.

COPANO ENERGY, L.L.C. AND SUBSIDIARIES

UNAUDITED CONSOLIDATED BALANCE SHEETS

	June 30,			December 31,
	2012			2011
	(In thousands, except unit information)
ASSETS
Current assets:
Cash and cash equivalents	$	50,996		$	56,962
Accounts receivable, net (1)	95,105			119,193
Risk management assets	21,995			4,322
Prepayments and other current assets	2,381			5,114
Total current assets	170,477			185,591
Property, plant and equipment, net	1,238,893			1,103,699
Intangible assets, net	160,391			192,425
Investments in unconsolidated affiliates	453,380			544,687
Escrow cash	1,848			1,848
Risk management assets	10,445			6,452
Other assets, net	27,851			29,895
Total assets	$	2,063,285		$	2,064,597
LIABILITIES AND MEMBERS’ CAPITAL
Current liabilities:
Accounts payable (1)	$	120,632		$	155,921
Accrued capital expenditures	19,712			7,033
Accrued interest	10,951			8,686
Accrued tax liability	729			1,182
Risk management liabilities	1,833			3,565
Other current liabilities	15,953			15,007
Total current liabilities	169,810			191,394
Long term debt (includes $3,263 and $0 bond premium as of June 30, 2012 and December 31, 2011, respectively)	1,007,788			994,525
Deferred tax liability	2,385			2,199
Other noncurrent liabilities	5,105			4,581
Commitments and contingencies (Note 9)
Members’ capital:
Series A convertible preferred units, no par value, 12,275,579 units and 11,684,074 units issued and outstanding as of June 30, 2012 and December 31, 2011, respectively	285,168			285,168
Common units, no par value, 72,365,674 units and 66,341,458 units issued and outstanding as of June 30, 2012 and December 31, 2011, respectively	1,353,504			1,164,853
Paid in capital	67,034			62,277
Accumulated deficit	(834,712		)	(624,121		)
Accumulated other comprehensive income (loss)	7,203			(16,279		)
	878,197			871,898
Total liabilities and members’ capital	$	2,063,285		$	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 EndedJune 30,						Six Months EndedJune 30,
	2012			2011			2012			2011
	(In thousands, except per unit information)
Revenue:
Natural gas sales (1)	$	69,993		$	123,928		$	156,205		$	227,723
Natural gas liquids sales	188,780			180,758			383,967			329,759
Transportation, compression and processing fees (1)(2)	43,241			27,898			83,080			52,369
Condensate and other (1)	15,289			13,472			31,279			26,130
Total revenue	317,303			346,056			654,531			635,981
Costs and expenses:
Cost of natural gas and natural gas liquids (1)(2)(3)	238,482			274,398			504,433			498,128
Transportation (1)(2)(3)	5,971			6,362			12,420			12,211
Operations and maintenance	18,287			15,763			36,929			30,862
Depreciation and amortization	19,062			17,363			38,150			34,232
Impairment	—			—			28,744			—
General and administrative (1)	10,298			11,901			25,242			24,499
Taxes other than income	2,110			1,397			3,476			2,527
Equity in (earnings) loss from unconsolidated affiliates	(12,437		)	(1,306		)	102,291			(3,008		)
Total costs and expenses	281,773			325,878			751,685			599,451
Operating income (loss)	35,530			20,178			(97,154		)	36,530
Other income (expense):
Interest and other income	521			8			559			15
Loss on refinancing of unsecured debt	—			(18,233		)	—			(18,233		)
Interest and other financing costs	(14,602		)	(11,454		)	(29,026		)	(23,370		)
Income (loss) before income taxes	21,449			(9,501		)	(125,621		)	(5,058		)
Provision for income taxes	(331		)	140			(932		)	(771		)
Net income (loss)	21,118			(9,361		)	(126,553		)	(5,829		)
Preferred unit distributions	(8,915		)	(8,076		)	(17,613		)	(15,956		)
Net income (loss) to common units	$	12,203		$	(17,437	)	$	(144,166	)	$	(21,785	)
Basic net income (loss) per common unit:
Net income (loss) per common unit	$	0.17		$	(0.26	)	$	(2.01	)	$	(0.33	)
Weighted average number of common units	72,300			66,143			71,630			66,065
Diluted net income (loss) per common unit:
Net income (loss) per common unit	$	0.14		$	(0.26	)	$	(2.01	)	$	(0.33	)
Weighted average number of common units	85,176			66,143			71,630			66,065
Distributions declared per common unit	$	0.575		$	0.575		$	1.150		$	1.150

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

(2) Inclusive of the following affiliate transactions:

Transportation, compression and processing fees	$	3,656	$	1		$	5,658	$	3
Cost of natural gas and natural gas liquids	32,729		(286		)	57,758		(281		)
Transportation	2,311		1,480			4,503		2,811

(3) 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 EndedJune 30,					Six Months EndedJune 30,
	2012		2011			2012			2011
	(In thousands)
Net income (loss)	$	21,118	$	(9,361	)	$	(126,553	)	$	(5,829	)
Other comprehensive income (loss):
Derivative settlements reclassified to income	2,295		9,942			6,312			18,324
Unrealized income (loss)-change in fair value of derivatives	21,232		(8		)	17,170			(15,657		)
Total other comprehensive income	23,527		9,934			23,482			2,667
Comprehensive income (loss)	$	44,645	$	573		$	(103,071	)	$	(3,162	)

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

	Six Months Ended June 30,
	2012			2011
	(In thousands)
Cash Flows From Operating Activities:
Net loss	$	(126,553	)	$	(5,829	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation and amortization	38,150			34,232
Impairment	28,744			—
Amortization of debt issue costs	1,978			1,949
Equity in loss (income) from unconsolidated affiliates	102,291			(3,008		)
Distributions from unconsolidated affiliates	20,618			12,323
Loss on refinancing of unsecured debt	—			18,233
Non-cash gain on risk management activities, net	(6,021		)	(1,536		)
Equity-based compensation	2,314			5,340
Deferred tax provision	185			168
Other non-cash items	346			(10		)
Changes in assets and liabilities, net of acquisitions:
Accounts receivable	24,756			(15,637		)
Prepayments and other current assets	2,733			2,110
Risk management activities	6,105			5,455
Accounts payable	(45,705		)	21,498
Other current liabilities	3,621			718
Net cash provided by operating activities	53,562			76,006
Cash Flows From Investing Activities:
Additions to property, plant and equipment	(142,465		)	(98,289		)
Additions to intangible assets	(2,740		)	(4,140		)
Acquisitions	—			(16,084		)
Investments in unconsolidated affiliates	(34,165		)	(65,027		)
Distributions from unconsolidated affiliates	1,896			1,249
Escrow cash	—			6
Proceeds from sale of assets	178			141
Other	3,366			(185		)
Net cash used in investing activities	(173,930		)	(182,329		)
Cash Flows From Financing Activities:
Proceeds from long-term debt	330,375			605,000
Repayment of long-term debt	(317,000		)	(392,665		)
Payments of premiums and expenses on redemption of unsecured debt	—			(14,572		)
Deferred financing costs	(3,434		)	(15,670		)
Distributions to unitholders	(84,150		)	(76,571		)
Proceeds from public offering of common units, net of underwriting discounts and commissions of $7,590	188,083			—
Equity offering costs	(360		)	(4		)
Proceeds from option exercises	888			2,431
Net cash provided by financing activities	114,402			107,949
Net (decrease) increase in cash and cash equivalents	(5,966		)	1,626
Cash and cash equivalents, beginning of year	56,962			59,930
Cash and cash equivalents, end of period	$	50,996		$	61,556

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)	592	17,183			—	—			—		—			—			17,183
Accrued in-kind units	—	430			—	—			—		—			—			430
In-kind distributions	—	(17,613		)	—	—			—		—			—			(17,613		)
Cash distributions to common unitholders	—	—			—	—			—		(84,038		)	—			(84,038		)
Issuance of common units	—	—			5,750	188,083			—		—			—			188,083
Equity offering costs	—	—			—	(320		)	—		—			—			(320		)
Equity-based compensation	—	—			275	888			4,757		—			—			5,645
Net loss	—	—			—	—			—		(126,553		)	—			(126,553		)
Derivative settlements reclassified to income	—	—			—	—			—		—			6,312			6,312
Unrealized income-change in fair value of derivatives	—	—			—	—			—		—			17,170			17,170
Balance, June 30, 2012	12,276	$	285,168		72,366	$	1,353,504		$	67,034	$	(834,712	)	$	7,203		$	878,197
	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)	536	15,567			—	—			—		—			—			15,567
Accrued in-kind units	—	389			—	—			—		—			—			389
In-kind distributions	—	(15,956		)	—	—			—		—			—			(15,956		)
Cash distributions to common unitholders	—	—			—	—			—		(76,970		)	—			(76,970		)
Equity offering costs	—	(4		)	—	—			—		—			—			(4		)
Equity-based compensation	—	—			311	2,431			5,569		—			—			8,000
Net loss	—	—			—	—			—		(5,829		)	—			(5,829		)
Derivative settlements reclassified to income	—	—			—	—			—		—			18,324			18,324
Unrealized loss-change in fair value of derivatives	—	—			—	—			—		—			(15,657		)	(15,657		)
Balance, June 30, 2011	11,121	$	285,168		66,226	$	1,164,083		$	57,312	$	(396,253	)	$	(27,689	)	$	1,082,621

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.  As of June 30, 2012 and December 31, 2011, we changed our presentation for other current liabilities on our consolidated balance sheet to present separately accrued capital expenditures.

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.

8

Note 2 — Recent Accounting Pronouncements (continued)

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.

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.

Note 3 — Intangible Assets

Our intangible assets consisted of the following as of the dates indicated:

	June 30, 2012
	Weighted Average Remaining Amortization Period	Gross Carrying Amount		Accumulated Amortization			Net
	(In years)	(In thousands)
Rights-of-way and easements	19	$	148,339	$	(32,091	)	$	116,248
Contracts	10	68,717		(27,665		)	41,052
Customer relationships	10	4,864		(1,773		)	3,091
Total	16	$	221,920	$	(61,529	)	$	160,391

	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 and six months ended June 30, 2012 and 2011, we did not place in service any intangible assets with future renewals or extension costs.  Amortization expense was $2,850,000 and $2,956,000 for the three months ended June 30, 2012 and 2011, respectively.  Amortization expense was $6,030,000 and $5,854,000 for the six months ended June 30, 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 — $6,085,000; 2013 — $11,307,000; 2014 — $11,145,000; 2015 — $11,109,000; 2016 — $11,087,000 and 2017 — $10,847,000.

9

Note 4 — Investments in Unconsolidated Affiliates

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

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 June 30, 2012, Fort Union is in compliance with this financial covenant.

Eagle Ford Gathering.  Our investment in Eagle Ford Gathering totaled $141,848,000 and $120,910,000 as of June 30, 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 Six Months Ended June 30,
	2012			2011
	(In thousands)
Operating revenue	$	166,442		$	—
Operating expenses	(136,403		)	(157		)
Depreciation and amortization	(6,086		)	—
Other	(318		)	—
Net income (loss)	23,635			(157		)
Ownership %	50		%	50		%
	11,818			(79		)
Copano’s share of management fees charged	131			40
Amortization of difference between the carried investment and the underlying equity in net assets	(41		)	—
Equity in earnings (loss) from Eagle Ford Gathering	$	11,908		$	(39	)
Distributions	$	10,324		$	—
Contributions	$	19,485		$	41,914
Current assets	$	32,576		$	1,434
Noncurrent assets	260,078			155,842
Current liabilities	(15,685		)	(12,905		)
Noncurrent liabilities	(377		)	(834		)
Net assets	$	276,592		$	143,537

10

Note 4 — Investments in Unconsolidated Affiliates (continued)

Bighorn and Fort Union.  Our investments in Bighorn and Fort Union totaled $94,601,000 and $162,244,000, respectively, as of June 30, 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 in the region 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.

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 Six Months Ended June 30,
	2012						2011
	Bighorn			Fort Union			Bighorn			Fort Union
	(In thousands)
Operating revenue	$	12,184		$	28,035		$	13,903		$	27,104
Operating expenses	(5,617		)	(3,284		)	(4,589		)	(3,455		)
Depreciation and amortization	(2,724		)	(3,995		)	(2,587		)	(3,996		)
Interest income (expense) and other	53			(805		)	42			(1,228		)
Net income	3,896			19,951			6,769			18,425
Ownership %	51		%	37.04		%	51		%	37.04		%
	1,987			7,390			3,452			6,825
Priority allocation of earnings and other	263			—			254			—
Copano’s share of management fees charged	98			48			98			46
Amortization of difference between the carried investment and the underlying equity in net assets and impairment	(117,200		)	(7,297		)	(5,629		)	(3,212		)
Equity in (loss) earnings from Bighorn and Fort Union	$	(114,852	)	$	141		$	(1,825	)	$	3,659
Distributions	$	4,005		$	7,704		$	4,956		$	7,408
Contributions	$	1,485		$	—		$	432		$	—
Current assets	$	3,892		$	9,548		$	5,912		$	9,721
Noncurrent assets	86,224			192,099			86,667			200,270
Current liabilities	(1,316		)	(69,995		)	(1,084		)	(18,782		)
Noncurrent liabilities	(324		)	(138		)	(282		)	(66,779		)
Net assets	$	88,476		$	131,514		$	91,213		$	124,430

11

Note 4 — Investments in Unconsolidated Affiliates (continued)

Other.  Our investments in our other unconsolidated affiliates (Webb Duval, Double Eagle Pipeline, Liberty Pipeline Group and Southern Dome) totaled $54,687,000 and $41,850,000 as of June 30, 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
	Six months ended June 30,
	2012			2011
	(In thousands)
Operating revenue	$	9,711		$	14,029
Operating expenses	(6,867		)	(11,726		)
Depreciation and amortization	(2,040		)	(756		)
Other	(10		)	3
Net income	$	794		$	1,550
Equity in earnings from unconsolidated affiliates	$	512		$	1,213
Distributions	$	481		$	1,208
Contributions(1)	$	13,195		$	20,598
Current assets	$	5,671		$	9,294
Noncurrent assets	115,873			59,417
Current liabilities	(19,436		)	(12,206		)
Noncurrent liabilities	(180		)	(64		)
Net assets	$	101,928		$	56,441

(1) Contributions for the six months ended June 30, 2012 and 2011 were primarily made to Double Eagle Pipeline and Liberty Pipeline Group, respectively.

Note 5 — Long-Term Debt

	June 30,		December 31,
	2012		2011
	(In thousands)
Revolving credit facility	$	245,000	$	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	3,263		—
Total Senior Notes	762,788		609,525
Total long-term debt	$	1,007,788	$	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 June 30, 2012.

12

Note 5 — Long-Term Debt (continued)

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 six months ended June 30, 2012 and 2011 was 2.7% and 2.4%, respectively, and the quarterly commitment fee was 0.375% on the unused portion of the revolving credit facility as of the end of each of those periods.  Interest and other financing costs related to the revolving credit facility totaled $4,831,000 and $2,767,000 for the six months ended June 30, 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 June 30, 2012, the unamortized portion of debt issue costs totaled $9,057,000.

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 $17,537,000 and $6,326,000 for the six months ended June 30, 2012 and 2011, respectively.  Costs of issuing the 2021 Notes are being amortized over the term of the 2021 Notes and, as of June 30, 2012, the unamortized portion of debt issue costs totaled $10,181,000.

7.75% Senior Notes due 2018.  Interest on the 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 $9,941,000 for each of the six months ended June 30, 2012 and 2011.  Costs of issuing the 2018 Notes are being amortized over the term of the 2018 Notes and, as of June 30, 2012, the unamortized portion of debt issue costs totaled $3,219,000.

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 $7,664,000 for the six months ended June 30, 2011.

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

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

	June 30, 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	$	36,454		$	—		$	14,542		$	—		$	—		$	50,996		$	9,064		$	—		$	47,898		$	—		$	—		$	56,962
Accounts receivable, net	1			—			95,104			—			—			95,105			2,374			—			116,819			—			—			119,193
Intercompany receivable	224,416			(2		)	(224,414		)	—			—			—			153,059			(1		)	(153,058		)	—			—			—
Risk management assets	—			—			21,995			—			—			21,995			—			—			4,322			—			—			4,322
Prepayments and other current assets	1,530			—			851			—			—			2,381			3,975			—			1,139			—			—			5,114
Total current assets	262,401			(2		)	(91,922		)	—			—			170,477			168,472			(1		)	17,120			—			—			185,591
Property, plant and equipment, net	—			—			1,238,893			—			—			1,238,893			16			—			1,103,683			—			—			1,103,699
Intangible assets, net	—			—			160,391			—			—			160,391			—			—			192,425			—			—			192,425
Investments in unconsolidated affiliates	—			—			453,380			453,380			(453,380		)	453,380			—			—			544,687			544,687			(544,687		)	544,687
Investments in consolidated subsidiaries	1,623,909			—			—			—			(1,623,909		)	—			1,698,260			—			—			—			(1,698,260		)	—
Escrow cash	—			—			1,848			—			—			1,848			—			—			1,848			—			—			1,848
Risk management assets	—			—			10,445			—			—			10,445			—			—			6,452			—			—			6,452
Other assets, net	22,459			—			5,392			—			—			27,851			21,136			—			8,759			—			—			29,895
Total assets	$	1,908,769		$	(2	)	$	1,778,427		$	453,380		$	(2,077,289	)	$	2,063,285		$	1,887,884		$	(1	)	$	1,874,974		$	544,687		$	(2,242,947	)	$	2,064,597
LIABILITIES AND MEMBERS’/PARTNERS’ CAPITAL
Current liabilities:
Accounts payable	$	66		$	—		$	120,566		$	—		$	—		$	120,632		$	31		$	—		$	155,890		$	—		$	—		$	155,921
Accrued capital expenditures	—						19,712			—			—			19,712			—			—			7,033			—			—			7,033
Accrued interest	10,951			—			—			—			—			10,951			8,686			—			—			—			—			8,686
Accrued tax liability	729			—			—			—			—			729			1,182			—			—			—			—			1,182
Risk management liabilities	—			—			1,833			—			—			1,833			—			—			3,565			—			—			3,565
Other current liabilities	5,555			—			10,398			—			—			15,953			6,809			—			8,198			—			—			15,007
Total current liabilities	17,301			—			152,509			—			—			169,810			16,708			—			174,686			—			—			191,394
Long-term debt	1,007,788			—			—			—			—			1,007,788			994,525			—			—			—			—			994,525
Deferred tax liability	2,281			—			104			—			—			2,385			2,119			—			80			—			—			2,199
Other noncurrent liabilities	3,202			—			1,903			—			—			5,105			2,634			—			1,947			—			—			4,581
Members’/Partners’ capital:
Series A convertible preferred units	285,168			—			—			—			—			285,168			285,168			—			—			—			—			285,168
Common units	1,353,504			—			—			—			—			1,353,504			1,164,853			—			—			—			—			1,164,853
Paid in capital	67,034			1			1,194,295			698,747			(1,893,043		)	67,034			62,277			1			1,208,051			687,763			(1,895,815		)	62,277
Accumulated (deficit) earnings	(834,712		)	(3		)	422,413			(245,367		)	(177,043		)	(834,712		)	(624,121		)	(2		)	506,489			(143,076		)	(363,411		)	(624,121		)
Accumulated other comprehensive income (loss)	7,203			—			7,203			—			(7,203		)	7,203			(16,279		)	—			(16,279		)	—			16,279			(16,279		)
	878,197			(2		)	1,623,911			453,380			(2,077,289		)	878,197			871,898			(1		)	1,698,261			544,687			(2,242,947		)	871,898
Total liabilities and members’/partners’ capital	$	1,908,769		$	(2	)	$	1,778,427		$	453,380		$	(2,077,289	)	$	2,063,285		$	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 June 30, 2012																	Three Months Ended June 30, 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	$	—		$	—	$	69,993		$	—		$	—		$	69,993		$	—		$	—	$	123,928		$	—		$	—		$	123,928
Natural gas liquids sales	—			—		188,780			—			—			188,780			—			—		180,758			—			—			180,758
Transportation, compression and processing fees	—			—		43,241			—			—			43,241			—			—		27,898			—			—			27,898
Condensate and other	—			—		15,289			—			—			15,289			—			—		13,472			—			—			13,472
Total revenue	—			—		317,303			—			—			317,303			—			—		346,056			—			—			346,056
Costs and expenses:
Cost of natural gas and natural gas liquids	—			—		238,482			—			—			238,482			—			—		274,398			—			—			274,398
Transportation	—			—		5,971			—			—			5,971			—			—		6,362			—			—			6,362
Operations and maintenance	—			—		18,287			—			—			18,287			—			—		15,763			—			—			15,763
Depreciation and amortization	6			—		19,056			—			—			19,062			10			—		17,353			—			—			17,363
General and administrative	5,271			—		5,027			—			—			10,298			5,893			—		6,008			—			—			11,901
Taxes other than income	—			—		2,110			—			—			2,110			—			—		1,397			—			—			1,397
Equity in (earnings) loss from unconsolidated affiliates	—			—		(12,437		)	(12,437		)	12,437			(12,437		)	—			—		(1,306		)	(1,306		)	1,306			(1,306		)
Total costs and expenses	5,277			—		276,496			(12,437		)	12,437			281,773			5,903			—		319,975			(1,306		)	1,306			325,878
Operating (loss) income	(5,277		)	—		40,807			12,437			(12,437		)	35,530			(5,903		)	—		26,081			1,306			(1,306		)	20,178
Other income (expense):
Interest and other income	—			—		521			—			—			521			—			—		8			—			—			8
Loss of refinancing of unsecured debt	—			—		—			—			—			—			(18,233		)			—			—			—			(18,233		)
Interest and other financing costs	(14,569		)	—		(33		)	—			—			(14,602		)	(10,989		)	—		(465		)	—			—			(11,454		)
(Loss) income before income taxes and equity in earnings (loss) from consolidated subsidiaries	(19,846		)	—		41,295			12,437			(12,437		)	21,449			(35,125		)	—		25,624			1,306			(1,306		)	(9,501		)
Provision for income taxes	(327		)	—		(4		)	—			—			(331		)	150			—		(10		)	—			—			140
(Loss) income before equity in earnings (loss) from consolidated subsidiaries	(20,173		)	—		41,291			12,437			(12,437		)	21,118			(34,975		)	—		25,614			1,306			(1,306		)	(9,361		)
Equity in earnings (loss) from consolidated subsidiaries	41,291			—		—			—			(41,291		)	—			25,614			—		—			—			(25,614		)	—
Net income (loss)	21,118			—		41,291			12,437			(53,728		)	21,118			(9,361		)	—		25,614			1,306			(26,920		)	(9,361		)
Preferred unit distributions	(8,915		)	—		—			—			—			(8,915		)	(8,076		)	—		—			—			—			(8,076		)
Net income (loss) to common units	$	12,203		$	—	$	41,291		$	12,437		$	(53,728	)	$	12,203		$	(17,437	)	$	—	$	25,614		$	1,306		$	(26,920	)	$	(17,437	)
Net income (loss)	$	21,118		$	—	$	41,291		$	12,437		$	(53,728	)	$	21,118		$	(9,361	)	$	—	$	25,614		$	1,306		$	(26,920	)	$	(9,361	)
Other comprehensive income (loss):
Derivative settlements reclassified to income	2,295			—		2,295			—			(2,295		)	2,295			9,942			—		9,942			—			(9,942		)	9,942
Unrealized gain (loss)-change in fair value of derivatives	21,232			—		21,232			—			(21,232		)	21,232			(8		)	—		(8		)	—			8			(8		)
Total other comprehensive income (loss)	23,527			—		23,527			—			(23,527		)	23,527			9,934			—		9,934			—			(9,934		)	9,934
Comprehensive income (loss)	$	44,645		$	—	$	64,818		$	12,437		$	(77,255	)	$	44,645		$	573		$	—	$	35,548		$	1,306		$	(36,854	)	$	573

15

Note 5 — Long-Term Debt (continued)

	Six Months Ended June 30, 2012																	Six Months Ended June 30, 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	$	—		$	—	$	156,205		$	—		$	—		$	156,205		$	—		$	—	$	227,723		$	—		$	—		$	227,723
Natural gas liquids sales	—			—		383,967			—			—			383,967			—			—		329,759			—			—			329,759
Transportation, compression and processing fees	—			—		83,080			—			—			83,080			—			—		52,369			—			—			52,369
Condensate and other	—			—		31,279			—			—			31,279			—			—		26,130			—			—			26,130
Total revenue	—			—		654,531			—			—			654,531			—			—		635,981			—			—			635,981
Costs and expenses:
Cost of natural gas and natural gas liquids	—			—		504,433			—			—			504,433			—			—		498,128			—			—			498,128
Transportation	—			—		12,420			—			—			12,420			—			—		12,211			—			—			12,211
Operations and maintenance	—			—		36,929			—			—			36,929			—			—		30,862			—			—			30,862
Depreciation and amortization	16			—		38,134			—			—			38,150			20			—		34,212			—			—			34,232
Impairment	—			—		28,744			—			—			28,744			—			—		—			—			—			—
General and administrative	12,726			—		12,516			—			—			25,242			13,416			—		11,083			—			—			24,499
Taxes other than income	—			—		3,476			—			—			3,476			—			—		2,527			—			—			2,527
Equity in loss (earnings) from unconsolidated affiliates	—			—		102,291			102,291			(102,291		)	102,291			—			—		(3,008		)	(3,008		)	3,008			(3,008		)
Total costs and expenses	12,742			—		738,943			102,291			(102,291		)	751,685			13,436			—		586,015			(3,008		)	3,008			599,451
Operating (loss) income	(12,742		)	—		(84,412		)	(102,291		)	102,291			(97,154		)	(13,436		)	—		49,966			3,008			(3,008		)	36,530
Other income (expense):
Interest and other income	—			—		559			—			—			559			—			—		15			—			—			15
Loss of refinancing of unsecured debt	—			—		—			—			—			—			(18,233		)			—			—			—			(18,233		)
Interest and other financing costs	(28,824		)	—		(202		)	—			—			(29,026		)	(22,627		)	—		(743		)	—			—			(23,370		)
(Loss) income before income taxes and equity in (loss) earnings from consolidated subsidiaries	(41,566		)	—		(84,055		)	(102,291		)	102,291			(125,621		)	(54,296		)	—		49,238			3,008			(3,008		)	(5,058		)
Provision for income taxes	(909		)	—		(23		)	—			—			(932		)	(740		)	—		(31		)	—			—			(771		)
(Loss) income before equity in (loss) earnings from consolidated subsidiaries	(42,475		)	—		(84,078		)	(102,291		)	102,291			(126,553		)	(55,036		)	—		49,207			3,008			(3,008		)	(5,829		)
Equity in (loss) earnings from consolidated subsidiaries	(84,078		)	—		—			—			84,078			—			49,207			—		—			—			(49,207		)	—
Net (loss) income	(126,553		)	—		(84,078		)	(102,291		)	186,369			(126,553		)	(5,829		)	—		49,207			3,008			(52,215		)	(5,829		)
Preferred unit distributions	(17,613		)	—		—			—			—			(17,613		)	(15,956		)	—		—			—			—			(15,956		)
Net (loss) income to common units	$	(144,166	)	$	—	$	(84,078	)	$	(102,291	)	$	186,369		$	(144,166	)	$	(21,785	)	$	—	$	49,207		$	3,008		$	(52,215	)	$	(21,785	)
Net (loss) income	$	(126,553	)	$	—	$	(84,078	)	$	(102,291	)	$	186,369		$	(126,553	)	$	(5,829	)	$	—	$	49,207		$	3,008		$	(52,215	)	$	(5,829	)
Other comprehensive income (loss):
Derivative settlements reclassified to income	6,312			—		6,312			—			(6,312		)	6,312			18,324			—		18,324			—			(18,324		)	18,324
Unrealized gain (loss)-change in fair value of derivatives	17,170			—		17,170			—			(17,170		)	17,170			(15,657		)	—		(15,657		)	—			15,657			(15,657		)
Total other comprehensive income (loss)	23,482			—		23,482			—			(23,482		)	23,482			2,667			—		2,667			—			(2,667		)	2,667
Comprehensive (loss) income	$	(103,071	)	$	—	$	(60,596	)	$	(102,291	)	$	162,887		$	(103,071	)	$	(3,162	)	$	—	$	51,874		$	3,008		$	(54,882	)	$	(3,162	)

16

Note 5 — Long-Term Debt (continued)

	Six Months Ended June 30, 2012																	Six Months Ended June 30, 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	$	(100,768	)	$	—	$	154,330		$	20,618		$	(20,618	)	$	53,562		$	(83,120	)	$	—	$	159,126		$	12,323		$	(12,323	)	$	76,006
Cash Flows From Investing Activities:
Additions to property, plant and equipment and intangibles	—			—		(145,205		)	—			—			(145,205		)	—			—		(102,429		)	—			—			(102,429		)
Acquisitions	—			—		—			—			—			—			—			—		(16,084		)	—			—			(16,084		)
Investments in unconsolidated affiliates	—			—		(34,165		)	(34,165		)	34,165			(34,165		)	—			—		(65,027		)	(65,027		)	65,027			(65,027		)
Distributions from unconsolidated affiliates	—			—		1,896			1,896			(1,896		)	1,896			—			—		1,249			1,249			(1,249		)	1,249
Investments in consolidated subsidiaries	(32,568		)	—		—			—			32,568			—			(80,319		)	—		—			—			80,319			—
Distributions from consolidated subsidiaries	46,324			—		—			—			(46,324		)	—			56,703			—		—			—			(56,703		)	—
Proceeds from sale of assets	—			—		178			—			—			178			—			—		141			—			—			141
Other	—			—		3,366			—			—			3,366			—			—		(179		)	—			—			(179		)
Net cash provided by (used in) investing activities	13,756			—		(173,930		)	(32,269		)	18,513			(173,930		)	(23,616		)	—		(182,329		)	(63,778		)	87,394			(182,329		)
Cash Flows From Financing Activities:
Proceeds from long-term debt	330,375			—		—			—			—			330,375			605,000			—		—			—			—			605,000
Repayment of long-term debt	(317,000		)	—		—			—			—			(317,000		)	(392,665		)	—		—			—			—			(392,665		)
Deferred financing costs	(3,434		)	—		—			—			—			(3,434		)	(15,670		)	—		—			—			—			(15,670		)
Payments of premiums and expenses on redemption of unsecured debt	—			—		—			—			—			—			(14,572		)	—		—			—			—			(14,572		)
Distributions to unitholders	(84,150		)	—		—			—			—			(84,150		)	(76,571		)	—		—			—			—			(76,571		)
Proceeds from public offering of common units	188,083			—		—			—			—			188,083			—			—		—			—			—			—
Equity offering costs	(360		)	—		—			—			—			(360		)	(4		)	—		—			—			—			(4		)
Contributions from parent	—			—		32,568			—			(32,568		)	—			—			—		80,319			65,027			(145,346		)	—
Distributions to parent	—			—		(46,324		)	—			46,324			—			—			—		(56,703		)	—			56,703			—
Other	888			—		—			34,165			(34,165		)	888			2,431			—		—			—			—			2,431
Net cash provided by (used in) financing activities	114,402			—		(13,756		)	34,165			(20,409		)	114,402			107,949			—		23,616			65,027			(88,643		)	107,949
Net increase (decrease) in cash and cash equivalents	27,390			—		(33,356		)	22,514			(22,514		)	(5,966		)	1,213			—		413			13,572			(13,572		)	1,626
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	$	36,454		$	—	$	14,542		$	143,836		$	(143,836	)	$	50,996		$	10,863		$	—	$	50,693		$	99,423		$	(99,423	)	$	61,556

17

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.

	Series A Convertible
	Preferred Units Issued
Quarter Ending	As In-Kind Distributions	Issue Date	Amount
December 31, 2011	292,101	February 9, 2012	$	8,486,000
March 31, 2012	299,404	May 10, 2012	$	8,698,000
June 30, 2012	306,889	August 2012(1)	$	8,915,000

(1) Units will be issued on or about August 9, 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.

	Distribution
Quarter Ending	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
June 30, 2012	$	0.575	July 11, 2012	July 31, 2012	August 9, 2012	$	42,336,000

Accounting for Equity-Based Compensation

We use ASC 718, “Stock Compensation,” to account for equity-based compensation expense related to awards issued under our long-term incentive plan (“LTIP”).  As of June 30, 2012, the number of units available for grant under our LTIP totaled 1,866,623 of which up to 1,335,520 units were eligible to be issued as restricted common units, phantom units or unit awards.

Equity Awards.  We recognized non-cash compensation expense of $4,220,000 and $5,266,000 related to the amortization of equity-based compensation under our LTIP during the six months ended June 30, 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.

18

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

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

Because we had a net loss to common units for the three months ended June 30, 2011 and the six months ended June 30, 2012 and 2011, the weighted average units outstanding are the same for basic and diluted net loss per common unit.

	Three Months Ended June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
	(In thousands)
Basic weighted average units	72,300	66,143	71,630	66,065
Potentially dilutive common equity:
Options	153	—	—	—
Unit appreciation rights	80	—	—	—
Restricted units	11	—	—	—
Phantom units	356	—	—	—
Series A preferred units	12,276	—	—	—
Dilutive weighted average units(1)	85,176	66,143	71,630	66,065

(1)The following potentially dilutive common equity was excluded from the dilutive net income (loss) per unit calculation because to include these equity securities would have been anti-dilutive:

	Three Months Ended June 30,		Six Months Ended June 30,
	2012	2011	2012	2011
	(In thousands)
Options	529	820	682	820
Unit appreciation rights	345	365	425	365
Restricted units	32	59	43	59
Phantom units	723	988	1,079	988
Contingent incentive plan unit awards	—	39	—	56
Series A preferred units	—	10,996	12,276	11,121

19

Note 8 — Related Party Transactions

Summary of Transactions With Affiliated Entities (in thousands).

	Financial Statement Classification - Three Months Ended June 30, 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)
Webb Duval	$	—	$	—	$	—	$	(97	)	$	268	$	57	$	132
Eagle Ford Gathering	—		3,656		—		32,826			—		160		177
Liberty Pipeline Group	—		—		—		—			346		57		117
Double Eagle Pipeline	—		—		—		—			—		175		4,010
Southern Dome	—		—		—		—			—		62		107
Bighorn	—		—		290		—			—		97		552
Fort Union	—		—		—		—			1,697		65		650
Other	—		—		—		—			—		—		—
Total related party transactions	$	—	$	3,656	$	290	$	32,729		$	2,311	$	673	$	5,745

	Financial Statement Classification - Three Months Ended June 30, 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)
Affiliates of Mr. Lawing(1)	$	—	$	1	$	—	$	22		$	—	$	—	$	57
Webb Duval	39		—		—		(308		)	119		56		224
Eagle Ford Gathering	—		—		—		—			—		301		3,482
Liberty Pipeline Group	—		—		—		—			—		—		12,011
Southern Dome	—		—		—		—			—		62		105
Bighorn	—		—		398		—			—		97		579
Fort Union	—		—		—		—			1,361		61		59
Other	—		—		—		—			—		—		—
Total related party transactions	$	39	$	1	$	398	$	(286	)	$	1,480	$	577	$	16,517

20

Note 8 — Related Party Transactions (continued)

	Financial Statement Classification - Six Months Ended June 30, 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	$	—	$	—	$	—	$	(41	)	$	552	$	114	$	334	$	57	$	53
Eagle Ford Gathering	—		5,658		—		57,799			—		339		316		6,159		153
Liberty Pipeline Group	—		—		—		—			661		114		181		117		37
Double Eagle Pipeline	—		—		—		—			—		350		5,854		24		243
Southern Dome	—		—		—		—			—		125		215		—		44
Bighorn	—		—		602		—			—		193		1,202		—		6
Fort Union	—		—		—		—			3,290		130		778		—		11
Other	—		—		—		—			—		—		—		—		17
Total related party transactions	$	—	$	5,658	$	602	$	57,758		$	4,503	$	1,365	$	8,880	$	6,357	$	564

	Financial Statement Classification - Six Months Ended June 30, 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	)	$	3	$	—	$	82		$	—	$	—	$	114	$	—	$	—
Webb Duval	39			—		—		(369		)	170		112		337		45		275
Eagle Ford Gathering	—			—		—		—			—		630		13,595		57		22
Liberty Pipeline Group	—			—		—		—			—		—		15,505		—		30
Southern Dome	—			—		—		—			—		125		201		—		52
Bighorn	—			—		815		—			—		193		1,162		—		245
Fort Union	—			—		—		6			2,641		123		776		—		16
Other	—			—		—		—			—		—		—		—		6
Total related party transactions	$	38		$	3	$	815	$	(281	)	$	2,811	$	1,183	$	31,690	$	102	$	646

(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.

21

Note 8 — Related Party Transactions (continued)

Other Transactions

Certain of our operating subsidiaries incurred costs payable to affiliates of Valerus Compression Services, L.P. for compression equipment and related services totaling $1,024,000 and $21,000 for the three months ended June 30, 2012 and 2011, respectively and $1,187,000 and $55,000 for the six months ended June 30, 2012 and 2011, respectively.  TPG Copenhagen, L.P., an affiliate of TPG Capital, L.P., (together with its affiliates, “TPG”) own a controlling interest in Valerus Compression Services, L.P., and Michael G. MacDougall, a partner with TPG, is a member of our Board of Directors.

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 June 30, 2012 and 2011, rental expense for leased office space, vehicles, compressors and related field equipment used in our operations totaled $1,724,000 and $1,133,000, respectively.  For the six months ended June 30, 2012 and 2011, rental expense for leased office space, vehicles, compressors and related field equipment used in our operations totaled $3,496,000 and $2,057,000, 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 $8,793,000 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 volume dedication dispute.  As of June 30, 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 June 30, 2012, we have accrued $418,000 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

	Six Months Ended June 30,
	2012		2011
	(In thousands)
Cash payments for interest, net of $3,486,000 and $4,072,000 capitalized in 2012 and 2011, respectively	$	29,122	$	23,727
Cash payments for federal and state income taxes	$	1,200	$	925
In-kind distributions of Series A convertible preferred units	$	17,613	$	15,956

22

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

We incurred a change in liabilities of $24,961,000 and $10,763,000 for investing activities that had not been paid as of June 30, 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 of cash flows.  As of June 30, 2012 and 2011, we accrued $51,154,000 and $18,762,000, 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 commodity 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.  Except for two option counterparties, all of our hedge counterparties are also lenders under our revolving credit facility, and any payment obligations in connection with our hedge transactions with a lender-counterparty 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.

23

Note 11 — Financial Instruments (continued)

As of June 30, 2012, we estimated that $3,823,000 of OCI will be reclassified as an increase to earnings in the next 12 months as a result of monthly settlements of instruments hedging NGLs and crude oil.

At June 30, 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 June 30, 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 June 30, 2012, our interest rate swaps were not designated as cash flow hedges.

As of June 30, 2012, we estimate that $59,000 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, sets forth 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 third-party pricing and data service providers.  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 for Mont Belvieu NGL prices and Mont Belvieu prices 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.

24

Note 11 — Financial Instruments (continued)

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 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 on 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 June 30, 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.

	Fair Value Measurements on Hedging Instruments(a)
	June 30, 2012
	Level 1		Level 2			Level 3		Total
	(In thousands)
Assets:
Natural Gas Liquids:
Short-term — Designated(b)	$	—	$	—		$	14,631	$	14,631
Short-term — Not designated(b)	—		—			3,675		3,675
Long-term — Designated(c)	—		—			7,484		7,484
Crude Oil:
Short-term — Designated(b)	—		—			2,873		2,873
Short-term — Not designated(b)	—		—			816		816
Long-term — Designated(c)	—		—			2,276		2,276
Long-term — Not designated(c)	—		—			685		685
Total	$	—	$	—		$	32,440	$	32,440
Liabilities:
Interest Rate:
Short-term — Not designated(d)	$	—	$	1,833		$	—	$	1,833
Total	$	—	$	1,833		$	—	$	1,833
Total designated assets	$	—	$	—		$	27,264	$	27,264
Total not designated (liabilities)/assets	$	—	$	(1,833	)	$	5,176	$	3,343

(a)Instruments re-measured on a recurring basis.

(b)Included on the consolidated balance sheets as a current asset under the heading of “Risk management assets.”

(c)Included on the consolidated balance sheets as a noncurrent asset under the heading of “Risk management assets.”

(d)Included on the consolidated balance sheets as a current liability under the heading of “Risk management liabilities.”

25

Note 11 — Financial Instruments (continued)

	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
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, capital expenditures and a terminal value.

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.”

26

Note 11 — Financial Instruments (continued)

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:

Quantitative Information about Level 3 Fair Value Measurements

	Fair Value as of June 30, 2012		Valuation Technique	Unobservable Inputs	Range
	(In thousands)
Natural gas liquids options:
Ethane	$	4,152	Asian Option	Volatility	43.63%-48.13%
				Forward Price Curve	$0.357-$0.36(1)
Propane	16,182		Asian Option	Volatility	19.86%-24.36%
				Forward Price Curve	$0.87-$0.92(1)
Iso-butane	2,033		Asian Option	Volatility	26.89%-31.39%
				Forward Price Curve	$1.39-$1.44(1)
Normal butane	3,423		Asian Option	Volatility	24.10%-28.60%
				Forward Price Curve	$1.32-$1.34(1)
Total natural gas liquid options	$	25,790
Crude oil options	$	6,650	Option Model	Volatility	27.92%-32.42%

(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 June 30, 2012
	Natural Gas		Natural Gas Liquids			Crude Oil			Total
	(In thousands)
Assets balance, beginning of period	$	—	$	5,727		$	3,284		$	9,011
Total gains or losses:
Non-cash amortization of option premium	—		(3,446		)	(1,592		)	(5,038		)
Other amounts included in earnings	—		7,433			996			8,429
Included in accumulated other comprehensive loss	—		19,441			4,046			23,487
Settlements	—		(3,365		)	(84		)	(3,449		)
Asset balance, end of period	$	—	$	25,790		$	6,650		$	32,440
Change in unrealized loss included in earnings related to instruments still held as of the end of the period	$	—	$	(3,210	)	$	(877	)	$	(4,087	)

27

Note 11 — Financial Instruments (continued)

	Six Months Ended June 30, 2012
	Natural Gas		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	—		(6,891		)	(3,187		)	(10,078		)
Other amounts included in earnings	—		7,862			537			8,399
Included in accumulated other comprehensive loss	—		20,845			2,547			23,392
Purchases	—		2,418			1,533			3,951
Settlements	—		(3,914		)	(84		)	(3,998		)
Asset balance, end of period	$	—	$	25,790		$	6,650		$	32,440
Change in unrealized (income) loss included in earnings related to instruments still held as of the end of the period	$	—	$	(2,708	)	$	(170	)	$	(2,878	)

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

28

Note 11 — Financial Instruments (continued)

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

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 June 30, 2012.

29

Note 11 — Financial Instruments (continued)

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

The Effect of Derivative Instruments on the Statements of Operations

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 June 30, 2012
Natural gas liquids	$	18,408		$	(1,033	)	$	172		Natural gas liquids sales
Crude oil	2,824			(1,222		)	(120		)	Condensate and other
Interest rate swaps	—			(40		)	—			Interest and other financing costs
Total	$	21,232		$	(2,295	)	$	52
Six Months Ended June 30, 2012
Natural gas liquids	$	17,174		$	(3,670	)	$	277		Natural gas liquids sales
Crude oil	(4		)	(2,552		)	(71		)	Condensate and other
Interest rate swaps	—			(90		)	—			Interest and other financing costs
Total	$	17,170		$	(6,312	)	$	206
Three Months Ended June 30, 2011
Natural gas	$	(26	)	$	(1,470	)	$	—		Natural gas sales
Natural gas liquids	(463		)	(6,816		)	(177		)	Natural gas liquids sales
Crude oil	482			(1,573		)	(93		)	Condensate and other
Interest rate swaps	—			(83		)	—			Interest and other financing costs
Total	$	(7	)	$	(9,942	)	$	(270	)
Six Months Ended June 30, 2011
Natural gas	$	(83	)	$	(2,924	)	$	—		Natural gas sales
Natural gas liquids	(12,599		)	(12,088		)	(317		)	Natural gas liquids sales
Crude oil	(2,975		)	(3,132		)	40			Condensate and other
Interest rate swaps	—			(180		)	—			Interest and other financing costs
Total	$	(15,657	)	$	(18,324	)	$	(277	)

30

Note 11 — Financial Instruments (continued)

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

The Effect of Derivative Instruments on the Statements of Operations

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 June 30, 2012
Natural gas liquids	$	3,451		Natural gas liquids sales
Crude oil	537			Condensate and other
Interest rate swaps	5			Interest and other financing costs
Total	$	3,993
Six Months Ended June 30, 2012
Natural gas liquids	$	1,788		Natural gas liquids sales
Crude oil	(468		)	Condensate and other
Interest rate swaps	(113		)	Interest and other financing costs
Total	$	1,207
Three Months Ended June 30, 2011
Natural gas	$	(65	)	Natural gas sales
Natural gas liquids	(281		)	Natural gas liquids sales
Crude oil	396			Condensate and other
Interest rate swaps	(381		)	Interest and other financing costs
Total	$	(331	)
Six Months Ended June 30, 2011
Natural gas	$	(128	)	Natural gas sales
Natural gas liquids	(84		)	Natural gas liquids sales
Crude oil	749			Condensate and other
Interest rate swaps	(563		)	Interest and other financing costs
Total	$	(26	)

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 June 30, 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.

	June 30, 2012				December 31, 2011
	Carrying Value		Estimated Fair Value		Carrying Value		Estimated Fair Value
	(In thousands)
Cash and cash equivalents	$	50,996	$	50,996	$	56,962	$	56,962
Revolving credit facility	$	245,000	$	247,103	$	385,000	$	385,000
2018 Notes	$	249,525	$	257,011	$	249,525	$	267,566
2021 Notes	$	510,000	$	524,025	$	360,000	$	366,300

31

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.

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

32

Note 13 — Segment Information (continued)

	Texas			Oklahoma			Rocky Mountains			Total Segments			Corporate and Other			Consolidated
	(In thousands)
Three Months Ended June 30, 2012:
Total segment gross margin	$	49,101		$	20,171		$	187		$	69,459		$	3,391		$	72,850
Operations and maintenance expenses	11,275			6,962			50			18,287			—			18,287
Depreciation and amortization	9,384			8,674			434			18,492			570			19,062
General and administrative expenses	2,632			2,026			351			5,009			5,289			10,298
Taxes other than income	1,389			715			5			2,109			1			2,110
Equity in (earnings) loss from unconsolidated affiliates	(9,851		)	(13		)	(2,573		)	(12,437		)	—			(12,437		)
Operating income (loss)	$	34,272		$	1,807		$	1,920		$	37,999		$	(2,469	)	$	35,530
Natural gas sales	$	45,517		$	24,449		$	27		$	69,993		$	—		$	69,993
Natural gas liquids sales	138,437			46,354			—			184,791			3,989			188,780
Transportation, compression and processing fees	34,263			4,917			4,061			43,241			—			43,241
Condensate and other	2,797			12,800			290			15,887			(598		)	15,289
Sales to external customers	$	221,014		$	88,520		$	4,378		$	313,912		$	3,391		$	317,303
Interest and other financing costs	$	—		$	—		$	—		$	—		$	14,602		$	14,602
Capital expenditures	$	107,172		$	8,704		$	—		$	115,876		$	3,484		$	119,360
Three Months Ended June 30, 2011:
Total segment gross margin	$	46,134		$	28,665		$	771		$	75,570		$	(10,274	)	$	65,296
Operations and maintenance expenses	8,908			6,794			61			15,763			—			15,763
Depreciation and amortization	6,861			9,358			766			16,985			378			17,363
General and administrative expenses	2,955			2,389			296			5,640			6,261			11,901
Taxes other than income	685			712			—			1,397			—			1,397
Equity in (earnings) loss from unconsolidated affiliates	(23		)	(669		)	(614		)	(1,306		)	—			(1,306		)
Operating income (loss)	$	26,748		$	10,081		$	262		$	37,091		$	(16,913	)	$	20,178
Natural gas sales	$	76,684		$	48,651		$	128		$	125,463		$	(1,535	)	$	123,928
Natural gas liquids sales	108,919			78,898			—			187,817			(7,059		)	180,758
Transportation, compression and processing fees	20,906			2,778			4,214			27,898			—			27,898
Condensate and other	4,629			10,124			398			15,151			(1,679		)	13,472
Sales to external customers	$	211,138		$	140,451		$	4,740		$	356,329		$	(10,273	)	$	346,056
Interest and other financing costs	$	—		$	—		$	—		$	—		$	11,454		$	11,454
Capital expenditures	$	52,396		$	22,005		$	—		$	74,401		$	536		$	74,937

33

Note 13 — Segment Information (continued)

	Texas			Oklahoma			Rocky Mountains			Total Segments			Corporate and Other			Consolidated
	(In thousands)
Six Months Ended June 30, 2012:
Total segment gross margin	$	94,442		$	44,370		$	545		$	139,357		$	(1,679	)	$	137,678
Operations and maintenance expenses	21,893			14,943			93			36,929			—			36,929
Depreciation and amortization	18,733			17,328			1,199			37,260			890			38,150
Impairment	—			—			28,744			28,744			—			28,744
General and administrative expenses	6,674			4,514			1,206			12,394			12,848			25,242
Taxes other than income	2,061			1,401			7			3,469			7			3,476
Equity in (earnings) loss from unconsolidated affiliates	(12,019		)	(401		)	114,711			102,291			—			102,291
Operating income (loss)	$	57,100		$	6,585		$	(145,415	)	$	(81,730	)	$	(15,424	)	$	(97,154	)
Natural gas sales	$	102,656		$	53,470		$	79		$	156,205		$	—		$	156,205
Natural gas liquids sales	275,443			107,552			—			382,995			972			383,967
Transportation, compression and processing fees	65,570			9,347			8,163			83,080			—			83,080
Condensate and other	6,452			26,876			602			33,930			(2,651		)	31,279
Sales to external customers	$	450,121		$	197,245		$	8,844		$	656,210		$	(1,679	)	$	654,531
Interest and other financing costs	$	—		$	—		$	—		$	—		$	29,026		$	29,026
Capital expenditures	$	149,165		$	15,301		$	—		$	164,466		$	5,700		$	170,166
Segment assets	$	946,395		$	618,034		$	296,999		$	1,861,428		$	201,857		$	2,063,285
Six Months Ended June 30, 2011:
Total segment gross margin	$	91,145		$	51,747		$	1,813		$	144,705		$	(19,063	)	$	125,642
Operations and maintenance expenses	17,733			13,013			116			30,862			—			30,862
Depreciation and amortization	13,530			18,401			1,531			33,462			770			34,232
General and administrative expenses	5,721			4,567			664			10,952			13,547			24,499
Taxes other than income	1,227			1,282			1			2,510			17			2,527
Equity in loss (earnings) from unconsolidated affiliates	196			(1,371		)	(1,833		)	(3,008		)	—			(3,008		)
Operating income (loss)	$	52,738		$	15,855		$	1,334		$	69,927		$	(33,397	)	$	36,530
Natural gas sales	$	136,785		$	93,736		$	253		$	230,774		$	(3,051	)	$	227,723
Natural gas liquids sales	197,599			145,020			—			342,619			(12,860		)	329,759
Transportation, compression and processing fees	38,582			5,200			8,587			52,369			—			52,369
Condensate and other	9,492			18,975			815			29,282			(3,152		)	26,130
Sales to external customers	$	382,458		$	262,931		$	9,655		$	655,044		$	(19,063	)	$	635,981
Interest and other financing costs	$	—		$	—		$	—		$	—		$	23,370		$	23,370
Capital expenditures	$	102,616		$	25,101		$	—		$	127,717		$	785		$	128,502

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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
Condensate:	Hydrocarbons that are produced from natural gas reservoirs but remain liquid at normal temperature and pressure
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 connect new natural gas 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 and 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 (and the ability of our third-party service providers) 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 events 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.

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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 operating segments.

Recent Developments

Additions to Senior Management.  On July 16, 2012, we announced that we had expanded our senior management team with the appointments of Bryan W. Neskora, as Chief Operating Officer, and Susan B. Ortenstone, as Chief Administrative Officer.  Mr. Neskora and Ms. Ortenstone report to R. Bruce Northcutt, our President, and Chief Executive Officer.

Declaration of Common Unit Distribution.  On July 11, 2012, our Board of Directors declared a cash distribution of $0.575 per common unit for the second quarter of 2012.  This distribution will be paid on August 9, 2012 to all common unitholders of record at the close of business on July 31, 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 commodity prices and by the volumes of natural gas, NGLs and condensate that flow through our assets.  Generally, commodity 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, commodity prices affect all of our segments indirectly because they influence exploration and production activity, which underlies the demand for our services and the long-term growth and sustainability of our business.

Commodity prices are influenced by various factors that affect supply and demand.  These factors include regional drilling activity and completion technology, natural gas, NGL and crude oil storage levels, competing supplies (such as crude oil or liquefied natural gas imports or exports), and the availability, proximity and capacity of downstream infrastructure 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 reduce or suspend 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 many cases, producers of rich gas can benefit from NGL prices under their contracts; for these producers, strong NGL prices may 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 operating costs and financial resources (both access to capital and cost of capital), the availability of necessary drilling equipment and services, the expected composition of wellhead production and the availability, proximity and capacity of downstream infrastructure, services and market outlets.  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.

The impact of changes in drilling and well completion activity on our throughput volumes may be gradual because of the time required to complete and connect new wells (or at times when drilling is declining, because of continuing production from existing wells).  Delays can range from a few days, in areas with minimal time required to complete and connect wells, to as long as 18 months if extensive dewatering or completion of downstream facilities is required.

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Some of our producer contracts entitle us to deficiency fees, which help to mitigate the impact of lower drilling activity; however, we may be subject to increased credit risk over periods 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, such as annually.  In the case of deficiency fees payable to one of our unconsolidated affiliates, the payment is reflected in our cash flow only after the unconsolidated affiliate has made a cash distribution, which may occur in a subsequent quarter.

Second-Quarter 2012 Commodity Prices Overall.  Natural gas prices, which have declined steadily across indices since August 2011, hovered at or near ten-year lows in April and May 2012, then began to show improvement in June 2012, which has continued into July.  Average NYMEX crude oil prices declined from $106.21 per Bbl for March 2012 to $82.41 per Bbl for June before improving to $87.90 per Bbl for July.  Average NGL prices on the Mont Belvieu and Conway indices declined sharply during the second quarter, and while the average spread between the two indices narrowed during the quarter, reaching $8.80 per Bbl for June 2012, it widened to $10.75 per Bbl for July.

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.

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	Quarterly Data for Texas
	Q1 2011		Q2 2011		Q3 2011		Q4 2011		Q1 2012		Q2 2012
Houston Ship Channel ($/MMBtu)	$	4.06	$	4.29	$	4.23	$	3.49	$	2.65	$	2.17
Mont Belvieu ($/Bbl)	$	51.22	$	58.57	$	59.43	$	57.76	$	52.64	$	38.71
NYMEX crude oil ($/Bbl)	$	94.10	$	102.56	$	89.76	$	94.06	$	102.93	$	93.49
100%-Owned
Service throughput (MMBtu/d)	654,996		665,040		765,744		844,469		944,033		924,465
Plant inlet (MMBtu/d)	560,903		588,533		686,398		803,282		833,163		834,846
NGLs produced (Bbls/d)	23,228		26,913		30,904		33,951		35,344		50,146
Segment gross margin (in thousands)	$	45,011	$	46,134	$	44,540	$	48,752	$	45,341	$	49,101
Joint Ventures(1)
Pipeline throughput (MMBtu/d)	49,450		48,045		106,923		206,962		269,433		316,111
NGL produced (Bbls/d) (2)	—		—		—		6,735		9,912		10,169
Gross margin (in thousands)	$	422	720		6,706		23,347		$	9,815	$	26,964

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

(2)Net of NGLs produced at our Houston Central complex

The first-of-the-month price for natural gas on the Houston Ship Channel index for July 2012 was $2.77 per MMBtu, and the spot price on August 6, 2012 was $2.94 per MMBtu.   The weighted-average daily price for NGLs at Mont Belvieu for July 2012, based on our second-quarter 2012 product mix, was $34.59 per Bbl.

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.

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	Quarterly Data for Oklahoma
	Q1 2011		Q2 2011		Q3 2011		Q4 2011		Q1 2012		Q2 2012
CenterPoint East ($/MMBtu)	$	3.93	$	4.14	$	4.05	$	3.38	$	2.60	$	2.11
Conway ($/Bbl)	$	46.36	$	50.17	$	49.21	$	43.49	$	39.18	$	30.23
NYMEX crude oil ($/Bbl)	$	94.10	$	102.56	$	89.76	$	94.06	$	102.93	$	93.49
100%-Owned
Service throughput (MMBtu/d)	269,550		283,870		288,440		307,346		318,285		324,915
Plant inlet (MMBtu/d)	147,710		157,424		158,070		159,344		157,052		158,106
NGLs produced (Bbls/d)	16,037		17,331		17,453		17,471		16,961		17,028
Segment gross margin (in thousands)	$	23,082	$	28,665	$	27,876	$	25,457	$	24,199	$	20,171
Joint Ventures(1)
Plant inlet (MMBtu/d)	11,182		11,730		11,970		10,287		10,017		7,352
NGLs produced (Bbls/d)	393		432		429		358		363		249
Gross margin (in thousands)	$	1,421	$	1,364	$	1,331	$	980	$	1,003	$	491

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

The first-of-the-month price for natural gas on the CenterPoint East index for July 2012 was $2.61 per MMBtu, and the spot price on August 6, 2012 was $2.87 per MMBtu.  The weighted-average daily price for NGLs at Conway for July 2012, based on our second-quarter 2012 product mix, was $24.73 per Bbl.

Basis Trends.  Basis risk continues to affect our hedges relating to Oklahoma NGL volumes.  We use Mont Belvieu-priced hedge instruments for our Oklahoma NGL volumes because the forward market for Conway-based hedge instruments is limited.

The monthly average basis differential between Mont Belvieu and Conway reached $12.34 per Bbl in April 2012 before narrowing in May and June, ending the quarter at $8.80 per Bbl.  The basis differential for July 2012 averaged $10.75 per Bbl.  The average basis differential between Houston Ship Channel and CenterPoint East natural gas index prices for the second quarter of 2012 was immaterial.

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.

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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		Q2 2012
Colorado Interstate Gas ($/MMBtu)	$	3.83	$	3.98	$	3.91	$	3.43	$	2.62	$	1.95
100%-Owned
Segment gross margin (in thousands)	$	1,042	$	771	$	432	$	396	$	358	$	187
Joint Ventures(1)
Pipeline throughput (MMBtu/d)	581,051		533,329		670,543		630,843		787,366		747,009
Gross margin (in thousands)	$	21,524	$	19,407	$	20,488	$	24,332	$	21,462	$	18,741

(1)Includes 100% of Bighorn and Fort Union volumes.  Changes in pipeline throughput at Fort Union did not have a material impact on gross margin because Fort Union received payments for additional volumes under long-term contractual commitments in each of the periods indicated.

The first-of-the-month price for natural gas on the Colorado Interstate Gas index for July 2012 was $2.44 per MMBtu, and the spot price on August 6, 2012 was $2.77 per MMBtu.

Other Industry Trends.  Continued growth in rich natural gas volumes from rich gas shale plays, such as the Eagle Ford Shale, has placed additional pressure on existing processing and liquids-handling infrastructure.  NGL transportation and fractionation facilities continue to experience capacity constraints, and processing facilities are subject to reduced operating performance 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 crude oil, condensate and heavier NGL products in Texas remain higher due to limited pipeline infrastructure and trucking capacity.  In addition, we believe that limited fractionation capacity at Mont Belvieu and a lack of available NGL pipeline capacity in the Mid-Continent are contributing to the wide basis spread between Mont Belvieu and Conway.  Mont Belvieu prices, particularly for ethane, have been supported by continued demand from the petrochemical market along the Gulf Coast.

Generally, capacity constraints result in higher processing fees, NGL transportation and fractionation costs for parties that do not have contractually fixed costs.  In addition, midstream companies experiencing capacity constraints or related outages may curtail volumes, which typically has an immediate impact on cash flow and operating results for both the

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midstream company and the producers it serves.  While these effects could limit the benefits producers receive from rich gas production and therefore affect the level of producer activity, we anticipate that the impact of capacity constraints will be relieved as new processing and fractionation facilities and pipeline infrastructure linking the Mid-Continent and Gulf Coast regions come online.

Second-Quarter 2012 Drilling and Production Activity.

·Drilling.  Drilling activity remained steady in the Eagle Ford Shale and north Barnett Shale Combo plays in Texas and the Hunton de-watering play in Oklahoma.  Drilling activity in the lean portion of the Woodford Shale behind our Mountains system in Oklahoma has been suspended due to low gas prices, while activity in the richer portion of the Woodford Shale continues.  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 second quarter of 2012 were down slightly compared to the first quarter of 2012 but increased 43% compared to the second quarter of 2011.  Texas volumes decreased from the first to the second quarter of 2012 because leaner third-party volumes that historically were delivered to the Houston Central complex by Kinder Morgan were displaced to accommodate rich Eagle Ford Shale volumes.  Texas volume increases compared to the second quarter of 2011 reflect new volumes attributable to Eagle Ford Gathering, an 82% increase in wholly owned Eagle Ford Shale volumes, a 70% increase in volumes on our Saint Jo system and resumption of operations at our Lake Charles plant, offset primarily by a substantial decrease in third-party volumes from Kinder Morgan.  Second-quarter 2012 gathering volumes in Oklahoma were slightly higher compared to first-quarter volumes, and 14% higher compared to the second quarter of 2011, primarily due to growth in lean Woodford Shale volumes.  In the Rocky Mountains, Fort Union and Bighorn volumes were down 5% and 6%, respectively, compared to the first quarter of 2012 due to limited drilling activity in the Powder River Basin.  A 60% increase in Fort Union volumes compared to the second quarter of 2011 reflects producers shifting volumes from other pipelines to Fort Union in the third quarter of 2011 to access markets downstream of Fort Union.  Volumes on Bighorn declined 15% over the same period due to limited drilling activity.

Factors Affecting Operating Results and Financial Condition

Lower NGL prices in the second quarter of 2012 reduced our gross margins compared to the first quarter, particularly in Oklahoma, where we have mainly percent-of-proceeds contracts.  Lower NGL prices reduced our margins in Texas as well, but the impact was mitigated by lower commodity-price sensitivity due to our shift toward more fee-based contracts.  Over the first half of 2012, the majority of our Texas volumes that historically were processed under keep-whole contracts have been replaced with volumes under fee-based contracts.

Our results for the second quarter of 2012 as compared to the first quarter also reflect stabilized operating performance at our Houston Central complex. With repairs and modifications we completed in April 2012, the new 200 MMcf/d cryogenic facility has been exceeding our original performance expectations.  We also made operating adjustments to the lean oil facility at Houston Central to optimize its efficiency for higher-NGL-content gas from the Eagle Ford Shale.

As compared to the second quarter of 2011, our second-quarter 2012 results also reflect declines in natural gas and NGL prices in Texas and Oklahoma, which partly offset the benefits of year-over-year volume growth due to strong drilling activity.  Cash received from our commodity hedge settlements increased compared to the first quarter of 2012 and the second quarter of 2011 due to lower NGL prices.

Our year-to-date results also reflect $148.7 million in non-cash impairments of our Rocky Mountains assets, which we recorded for the first quarter of 2012 primarily based on the low natural gas price environment in the region and our expectation of lower drilling activity in the Powder River Basin.

Outlook

Prices and Drilling Activity.  We believe that the recent decline in NGL prices is attributable to a series of events resulting in an overabundance of NGLs and compounded by infrastructure limitations.  Propane prices have been under pressure due to a mild winter, and ethane and other NGL prices have been lower due to a combination of NGL-industry-related outages and planned shutdowns, which effectively reduced fractionation and ethane-cracking capacity in the first half of 2012.  NGL prices have begun to show improvement as fractionation and petrochemical facilities have come back online and storage levels have begun to decline.

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As long as NGL prices remain above levels that are economic for producers, we anticipate continued rich gas drilling activity.  While the level at which prices are economic will vary depending upon the play and the producer, we believe that the Eagle Ford Shale, the north Barnett Shale Combo, the rich portion of the Woodford Shale, and the Hunton de-watering plays remain attractive to producers because they offer rich gas, low geologic risk, nearby infrastructure and market access relative to other plays, 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.  We have completed gathering and compression facilities extending into the play from our existing assets in the area, and have begun work to interconnect our Paden plant, which will enable us to provide processing and nitrogen rejection services.

Natural gas prices have improved slightly from recent 10-year lows, we believe mainly due to increased power-generation demands relating to summer weather.  Because natural gas prices have been low, gas has been an attractive alternative to coal for power generation.  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, shifting capital and resources away from conventional areas.  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.

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.  As we discussed in our first-quarter 2012 Form 10-Q, the Houston Central complex has been receiving gas with NGL content that exceeded our original expectations and is unprecedented compared to historical levels in the region.  This could reduce our operating performance at Houston Central and subjects us to other operating risks such as NGL-handling capacity constraints.

We are installing a 400 MMcf/d cryogenic processing facility at Houston Central, which is scheduled for completion in early 2013, and an additional 400 MMcf/d cryogenic facility in 2014.  These new facilities ultimately should enable us to relegate the lean oil facility to providing overflow and interruptible volume services.  Until the new facilities are complete, we expect that the high NGL content of Eagle Ford Shale gas may impact our operating performance at the Houston Central complex.

We anticipate that the wide basis differential affecting Texas and Oklahoma NGL prices in 2012 will begin to moderate as new fractionation facilities and NGL transportation infrastructure, including new third-party NGL pipelines linking the Mid-Continent to the Gulf Coast, come online over the next two years.

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 because it allows them to independently evaluate our performance with the same information used by management.  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.

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

	Three Months Ended June 30,						Six Months Ended June 30,
	2012			2011			2012			2011
	(In thousands)
Reconciliation of total segment gross margin to operating income (loss):
Operating income (loss)	$	35,530		$	20,178		$	(97,154	)	$	36,530
Add: Operations and maintenance expenses	18,287			15,763			36,929			30,862
Depreciation and amortization	19,062			17,363			38,150			34,232
Impairment	—			—			28,744			—
General and administrative expenses	10,298			11,901			25,242			24,499
Taxes other than income	2,110			1,397			3,476			2,527
Equity in (earnings) loss from unconsolidated affiliates	(12,437		)	(1,306		)	102,291			(3,008		)
Total segment gross margin	$	72,850		$	65,296		$	137,678		$	125,642
Reconciliation of EBITDA, adjusted EBITDA and total distributablecash flow to net income (loss):
Net income (loss)	$	21,118		$	(9,361	)	$	(126,553	)	$	(5,829	)
Add: Depreciation and amortization	19,062			17,363			38,150			34,232
Interest and other financing costs	14,602			11,454			29,026			23,370
Provision for income taxes	331			(140		)	932			771
EBITDA	55,113			19,316			(58,445		)	52,544
Add: Amortization of commodity derivative options	5,039			7,357			10,078			14,627
Distributions from unconsolidated affiliates	12,185			7,099			22,514			13,572
Loss on refinancing of unsecured debt	—			18,233			—			18,233
Equity-based compensation	1,121			4,109			4,352			7,091
Equity in (earnings) loss from unconsolidated affiliates	(12,437		)	(1,306		)	102,291			(3,008		)
Unrealized (gain) loss from commodity risk management activities	(4,980		)	180			(4,401		)	(363		)
Impairment	—			—			28,744			—
Other non-cash operating items	2,252			(572		)	3,485			(848		)
Adjusted EBITDA	58,293			54,416			108,618			101,848
Less: Interest expense	(14,548		)	(10,988		)	(28,781		)	(22,594		)
Current income tax expense and other	(418		)	(293		)	(747		)	(624		)
Maintenance capital expenditures	(3,798		)	(5,555		)	(6,241		)	(7,601		)
Total distributable cash flow	$	39,529		$	37,580		$	72,849		$	71,029

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 June  30,						Six Months Ended June 30,
	2012			2011			2012			2011
	($ In thousands)
Total segment gross margin(1)	$	72,850		$	65,296		$	137,678		$	125,642
Operations and maintenance expenses	18,287			15,763			36,929			30,862
Depreciation and amortization	19,062			17,363			38,150			34,232
Impairment	—			—			28,744			—
General and administrative expenses	10,298			11,901			25,242			24,499
Taxes other than income	2,110			1,397			3,476			2,527
Equity in (earnings) loss from unconsolidated affiliates(2)(3)	(12,437		)	(1,306		)	102,291			(3,008		)
Operating income (loss)	35,530			20,178			(97,154		)	36,530
Loss on refinancing of unsecured debt	—			(18,233		)	—			(18,233		)
Interest and other financing costs, net	(14,081		)	(11,446		)	(28,467		)	(23,355		)
Provision for income taxes	(331		)	140			(932		)	(771		)
Net income (loss)	21,118			(9,361		)	(126,553		)	(5,829		)
Preferred unit distributions	(8,915		)	(8,076		)	(17,613		)	(15,956		)
Net income (loss) to common units	$	12,203		$	(17,437	)	$	(144,166	)	$	(21,785	)
Basic net income (loss) per common unit	$	0.17		$	(0.26	)	$	(2.01	)	$	(0.33	)
Weighted average number of common units - basic	72,300			66,143			71,630			66,065
Diluted net income (loss) per common unit	$	0.14		$	(0.26	)	$	(2.01	)	$	(0.33	)
Weighted average number of common units - diluted	85,176			66,143			71,630			66,065
Total segment gross margin:
Texas	$	49,101		$	46,134		$	94,442		$	91,145
Oklahoma	20,171			28,665			44,370			51,747
Rocky Mountains(4)	187			771			545			1,813
Segment gross margin	69,459			75,570			139,357			144,705
Corporate and other(5)	3,391			(10,274		)	(1,679		)	(19,063		)
Total segment gross margin(1)	$	72,850		$	65,296		$	137,678		$	125,642
Segment gross margin per unit:
Texas:
Service throughput ($/MMBtu)	$	0.58		$	0.76		$	0.56		$	0.76
Oklahoma:
Service throughput ($/MMBtu)	$	0.68		$	1.11		$	0.76		$	1.03
Volumes:
Texas: (6)
Service throughput (MMBtu/d)(7)	924,465			665,040			934,257			660,741
Pipeline throughput (MMBtu/d)	566,388			444,186			565,949			422,429
Plant inlet volumes (MMBtu/d)	834,846			588,533			834,004			574,794
NGLs produced (Bbls/d)	50,146			26,913			42,745			25,080
Oklahoma:(8)
Service throughput (MMBtu/d)(7)	324,915			283,870			321,600			280,293
Plant inlet volumes (MMBtu/d)	158,106			157,424			157,579			156,856
NGLs produced (Bbls/d)	17,028			17,331			16,994			17,067
Capital Expenditures:
Maintenance capital expenditures	$	3,798		$	5,555		$	6,241		$	7,601
Expansion capital expenditures	115,562			69,382			163,925			120,901
Total capital expenditures	$	119,360		$	74,937		$	170,166		$	128,502
Operations and maintenance expenses:
Texas	$	11,275		$	8,908		$	21,893		$	17,733
Oklahoma	6,962			6,794			14,943			13,013
Rocky Mountains	50			61			93			116
Total operations and maintenance expenses	$	18,287		$	15,763		$	36,929		$	30,862

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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)The following table summarizes the results and volumes associated with our unconsolidated affiliates ($ in thousands):

		Three Months Ended June 30,
		2012				2011
		Volume	Equity (Earnings)/Loss			Volume	Equity (Earnings)/Loss
Eagle Ford Gathering			$	(9,846	)		$	8
Pipeline throughput	(MMBtu/d)	252,912				—
NGLs produced(a)	(Bbls/d)	10,169				—
Liberty Pipeline Group	(Bbls/d)	22,379	139			—	1
Webb Duval(b)	(MMBtu/d)	63,199	(47		)	48,045	(18		)
Southern Dome			(13		)		(669		)
Plant inlet	(MMBtu/d)	7,352				11,730
NGLs produced	(Bbls/d)	249				432
Bighorn and Fort Union(c)	(MMBtu/d)	747,009	(2,574		)	533,329	(615		)

		Six Months Ended June 30,
		2012				2011
		Volume	Equity (Earnings)/Loss			Volume	Equity (Earnings)/Loss
Eagle Ford Gathering			$	(11,908	)		$	38
Pipeline throughput	(MMBtu/d)	229,991				—
NGLs produced(a)	(Bbls/d)	10,040				—
Liberty Pipeline Group	(Bbls/d)	17,690	274			—	1
Webb Duval(b)	(MMBtu/d)	62,567	(190		)	48,744	184
Southern Dome			(401		)		(1,371		)
Plant inlet	(MMBtu/d)	8,684				11,457
NGLs produced	(Bbls/d)	306				413
Bighorn and Fort Union(c)	(MMBtu/d)	767,188	114,711			557,059	(1,834		)

(a)Net of NGLs produced at our Houston Central complex.

(b)Net of intercompany volumes.

(c)Changes in pipeline throughput at Fort Union did not have a material impact on gross margin because Fort Union received payments for additional volumes under long-term contractual commitments in each of the periods indicated.

(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 June 30, 2012 Compared To Three Months Ended June 30, 2011

Texas Segment Gross Margin.  Texas segment gross margin was $49.1 million for the three months ended June 30, 2012 compared to $46.1 million for the three months ended June 30, 2011, an increase of $3.0 million, or 6%.  The impact of lower NGL prices, which declined 34%, was offset by higher volumes.  Volumes gathered, volumes processed and NGLs produced increased 28%, 42% and 86%, respectively, for the three months ended June 30, 2012 as compared to the three months ended June 30, 2011.  Our gathering and processing volume growth was due primarily to the Eagle Ford Shale and north Barnett Shale Combo plays, and was offset by a decline in leaner gas volumes at the Houston Central complex, which were displaced to accommodate rich gas volumes.  Higher NGL production reflects overall volume growth at our Saint Jo plant and a substantial increase in the NGL content of gas processed at our Houston Central complex.  Also, our Lake Charles

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processing plant contributed $2.5 million to Texas gross margin during the three months ended June 30, 2012 but did not operate during the same period in 2011.  Despite these volume increases, Texas segment gross margin per unit of service throughput decreased $0.18 per MMBtu to $0.58 per MMBtu for the three months ended June 30, 2012 compared to $0.76 per MMBtu for the three months ended June 30, 2011, mainly due to the 34% decline in NGL prices.

Oklahoma Segment Gross Margin.  Oklahoma segment gross margin was $20.2 million for the three months ended June 30, 2012 compared to $28.7 million for the three months ended June 30, 2011, a decrease of $8.5 million, or 30%.  Service throughput increased 14% period over period, while plant inlet volumes were flat.  The increase in service throughput only partly offset the impact of lower commodity prices, as NGL prices declined 40% and average natural gas prices declined 49%.  NGL production declined 2% as the higher service throughput consisted mainly of lean gas from the Woodford Shale.  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 $0.43 per MMBtu to $0.68 per MMBtu for the three months ended June 30, 2012 compared to $1.11 per MMBtu for the three months ended June 30, 2011.

Rocky Mountains Segment Gross Margin.  Rocky Mountains segment gross margin was $0.2 million for the three months ended June 30, 2012 compared to $0.8 million for the three months ended June 30, 2011, a decrease of $0.6 million, or 75%.  This decrease is primarily the result of our inability to resell all of the 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 gain of $3.4 million for the three months ended June 30, 2012 compared to a loss of $10.3 million for the three months ended June 30, 2011.  The gain for the three months ended June 30, 2012 included $3.4 million of net cash settlements received on expired commodity derivative instruments and $5.0 million of unrealized gains on commodity derivative instruments, offset by $5.0 million of non-cash amortization expense relating to the option component of our commodity derivative instruments.  The loss for the three months ended June 30, 2011 included $7.4 million of non-cash amortization expense relating to the option component of our commodity derivative instruments, $2.7 million of net cash settlements paid on expired commodity derivative instruments and $0.2 million of unrealized loss on commodity derivative instruments.

Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $18.3 million for the three months ended June 30, 2012 compared to $15.8 million for the three months ended June 30, 2011.  The 16% increase consisted primarily of higher payroll, utility, compression and equipment rental expenses in Texas relating to expanded operations at our Houston Central complex and volume increases at our Saint Jo plant in Texas.  In addition, we operated the Lake Charles plant (which resumed operations in November 2011) for the full three months ended June 30, 2012 but incurred minimal operating expenses associated with the plant during the same period in 2011.

Depreciation and Amortization.  Depreciation and amortization totaled $19.1 million for the three months ended June 30, 2012 compared with $17.4 million for the three months ended June 30, 2011, an increase of 10%.  This increase relates primarily to additional depreciation and amortization resulting from assets placed in service after June 30, 2011, including the fractionation expansion at our Houston Central complex in November 2011, our DK pipeline extension in December 2011 and our new 200 MMcf/d cryogenic facility at our Houston Central complex in March 2012.

General and Administrative Expenses.  General and administrative expenses totaled $10.3 million for the three months ended June 30, 2012 compared to $11.9 million for the three months ended June 30, 2011.  The 13% decrease consists primarily of a decrease of $2.1 million in non-cash compensation expense related to amortization of the fair value of equity awards issued under our Long-Term Incentive Plan, or LTIP, and a $0.7 million decrease in expense due to the collection of a receivable previously written off as uncollectible, partially offset by increases in personnel, compensation and benefits costs of $1.0 million.

Equity in Earnings from Unconsolidated Affiliates.  Equity in earnings from unconsolidated affiliates totaled $12.4 million for the three months ended June 30, 2012 compared to earnings of $1.3 million for the three months ended June 30, 2011, an increase of $11.1 million.  Equity in earnings from unconsolidated affiliates for the three months ended June 30, 2012 consisted primarily of $9.8 million from Eagle Ford Gathering (which began operations in the latter half of 2011), $0.5 million from Bighorn and $2.1 million from Fort Union.  Equity in earnings from unconsolidated affiliates for the three months ended June 30, 2011 consisted of $1.4 million of equity earnings from Fort Union and $0.7 million of equity earnings from Southern Dome offset by $0.8 million of equity loss from Bighorn and our other unconsolidated affiliates.

Interest and Other Financing Costs.  Interest and other financing costs totaled $14.6 million for the three months ended June 30, 2012 compared to $11.5 million for the three months ended June 30, 2011, an increase of $3.1 million, or 27%.  The increase consisted primarily of $2.9 million in additional interest expense relating to higher indebtedness outstanding

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under our revolving credit facility and senior notes.  Average borrowings under our credit arrangements for the three months ended June 30, 2012 and 2011 were $931.4 million and $773.0 million, respectively, with weighted-average interest rates of 7.3% and 7.4%, respectively.  Please read “— Liquidity and Capital Resources — Our Indebtedness.”

Six Months Ended June 30, 2012 Compared To Six Months Ended June 30, 2011

Texas Segment Gross Margin.  Texas segment gross margin was $94.4 million for the six months ended June 30, 2012 compared to $91.1 million for the six months ended June 30, 2011, an increase of $3.3 million, or 4%.  Gathering, processing and NGL production volumes in Texas increased 34%, 45% and 70%, respectively, for the six months ended June 30, 2012 compared to the six months ended June 30, 2011.  Our gathering and processing volume growth was due primarily to the Eagle Ford Shale and north Barnett Shale Combo plays, and was offset by a decline in leaner gas volumes at the Houston Central complex, which were displaced to accommodate rich volumes.  Higher NGL production reflects overall volume growth at our Saint Jo plant and a substantial increase in the NGL content of gas processed at our Houston Central complex.  Also, our Lake Charles processing plant contributed $4.2 million to Texas segment gross margin during the six months ended June 30, 2012 but did not operate during the same period in 2011.  The impact of the Lake Charles plant and volume increases was offset by NGL prices, which on average declined 20%, and reduced operating performance that we experienced at Houston Central early in the period.  Texas segment gross margin per unit of service throughput decreased $0.20 per MMBtu to $0.56 per MMBtu for the six months ended June 30, 2012 compared to $0.76 per MMBtu for the six months ended June 30, 2011, mainly due to lower NGL prices and reduced operating performance at Houston Central.

Oklahoma Segment Gross Margin.  Oklahoma segment gross margin was $44.4 million for the six months ended June 30, 2012 compared to $51.7 million for the six months ended June 30, 2011, a decrease of $7.3 million, or 14%.  The decrease in segment gross margin was primarily due to period-over-period decreases in average NGL and natural gas prices of 28% and 41%, respectively.  An increase in service throughput of 15% was due primarily to lean gas volume growth from the Woodford Shale.  Oklahoma segment gross margin per unit of service throughput decreased $0.27 per MMBtu to $0.76 per MMBtu for the six months ended June 30, 2012 compared to $1.03 per MMBtu for the six months ended June 30, 2011.

Rocky Mountains Segment Gross Margin.  Rocky Mountains segment gross margin was $0.5 million for the six months ended June 30, 2012 compared to $1.8 million for the six months ended June 30, 2011, a decrease of $1.3 million, or 72%.  This decrease is primarily the result of our inability to resell all of the 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 $1.7 million for the six months ended June 30, 2012 compared to a loss of $19.1 million for the six months ended June 30, 2011.  The loss for the six months ended June 30, 2012 included $10.1 million of non-cash amortization expense relating to the option component of our commodity derivative instruments, partially offset by $4.0 million of net cash settlements received on expired commodity derivative instruments and $4.4 million of unrealized gain on our commodity derivative instruments.  The loss for the six months ended June 30, 2011 included $14.6 million of non-cash amortization expense relating to the option component of our commodity derivative instruments and $4.8 million of net cash settlements paid on expired commodity derivative instruments offset by $0.3 million of unrealized mark-to-market gains on our commodity derivative instruments.

Operations and Maintenance Expenses.  Operations and maintenance expenses totaled $36.9 million for the six months ended June 30, 2012 compared to $30.9 million for the six months ended June 30, 2011.  The 19% increase consisted primarily of higher payroll, utilities, compression and equipment rental expenses in Texas relating to expanded operations at our Houston Central complex and volume increases at our Saint Jo plant.  In addition, we operated our Lake Charles and Harrah processing plants for the full six months ended June 30, 2012 but for the same period in 2011, we incurred minimal operating expenses at the Lake Charles plant (which did not operate during the period) and three months of operating expenses at the Harrah plant (which we acquired in April 2011).

Depreciation and, Amortization.  Depreciation and amortization totaled $38.2 million for the six months ended June 30, 2012 compared with $34.2 million for the six months ended June 30, 2011, an increase of 12%.  This increase relates primarily to additional depreciation and amortization resulting from assets placed in service after June 30, 2011, including expenditures relating to the fractionation expansion at our Houston Central complex in November 2011, our DK pipeline extension in December 2011 and our new 200 MMcf/d cryogenic facility at our Houston Central complex in March 2012.

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Impairment.  Impairment expense for the six months ended June 30, 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 was based primarily on the low natural gas price environment in the region 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 $25.2 million for the six months ended June 30, 2012 compared to $24.5 million for the six months ended June 30, 2011.  The 3% increase consists primarily of increases in personnel, compensation and benefits costs of $3.4 million, offset by a decrease of $1.2 million in non-cash compensation expense related to amortization of the fair value of equity awards issued under our LTIP, a $0.7 million decrease in expense due to the collection of a receivable previously written off as uncollectible and a $0.5 million decrease in expenses for acquisition initiatives that were not consummated.

Equity in Loss/Earnings from Unconsolidated Affiliates.  Equity in loss from unconsolidated affiliates totaled $102.3 million for the six months ended June 30, 2012 compared to earnings of $3.0 million for the six months ended June 30, 2011, a decrease of $105.3 million.  Equity in loss from unconsolidated affiliates for the six months ended June 30, 2012 consisted of a $114.9 million loss from Bighorn (including the $115 million impairment during the first quarter of 2012), partially offset by $11.9 million in earnings from Eagle Ford Gathering (which began operations in the latter half of 2011).  Equity in earnings from unconsolidated affiliates for the six months ended June 30, 2011 consisted of $3.7 million of equity earnings from Fort Union and $1.4 million of equity earnings from Southern Dome offset by $2.1 million of equity loss from Bighorn and our other unconsolidated affiliates.

Interest and Other Financing Costs.  Interest and other financing costs totaled $29.0 million for the six months ended June 30, 2012 compared to $23.4 million for the six months ended June 30, 2011, an increase of $5.6 million, or 24%.  The increase consisted primarily of additional interest expense relating to higher indebtedness outstanding under our revolving credit facility and senior notes, slightly offset by lower interest rates.  Average borrowings under our credit arrangements for the six months ended June 30, 2012 and 2011 were $909.6 million and $699.1 million, respectively, with average interest rates of 7.25% and 8.0%, respectively.  Please read “— Liquidity and Capital Resources — Our Indebtedness.”

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.

	Six Months Ended June 30,
	2012			2011
	(In thousands)
Net cash provided by operating activities	$	53,562		$	76,006
Net cash used in investing activities	$	(173,930	)	$	(182,329	)
Net cash provided by financing activities	$	114,402		$	107,949

Operating Cash Flows.  Net cash provided by operating activities was $53.6 million for the six months ended June 30, 2012 compared to $76.0 million for the six months ended June 30, 2011.  The decrease in cash provided by operating activities of $22.4 million was attributable to the following changes:

·   a $26.0 million decrease in cash flow provided by operating activities for the six months ended June 30, 2012 compared with the same period in 2011;

partially offset by:

·a $5.4 million increase in interest payments in 2012 compared to the same period in 2011 as a result of increased borrowings;

·a $0.7 million increase in cash flow used for risk management activities for 2012 as compared to 2011; and

·a $8.3 million increase in distributions received from our unconsolidated affiliates in 2012 compared to the same period in 2011.

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Investing Cash Flows.  Net cash used in investing activities was $173.9 million and $182.3 million for the six months ended June 30, 2012 and 2011, respectively.  Investing activities for the six months ended June 30, 2012 included (i) $145 million, including $100.6 million in capital expenditures related to our Eagle Ford Shale growth strategy and well connections attaching volumes in new areas, $23.9 million related to activities around our Saint Jo plant and $13.6 million related to our activities in Oklahoma; and (ii) $34.2 million of investments in Eagle Ford Gathering, Double Eagle Pipeline and Bighorn, offset by $1.9 million in distributions from Eagle Ford Gathering, Bighorn and Southern Dome in excess of equity earnings.  Investing activities for the six months ended June 30, 2011 included $118.5 million, including (i) $84.7 million in capital expenditures related to our Eagle Ford Shale growth strategy and well connections attaching volumes in new areas, (ii) $16.1 million for acquisition of the Harrah plant in Oklahoma and (iii) $65.0 million of investments in Eagle Ford Gathering, Liberty Pipeline Group and Bighorn, offset by $1.2 million in distributions from Bighorn in excess of equity earnings.

Financing Cash Flows.  Net cash provided by financing activities totaled $114.4 million during the six months ended June 30, 2012 and included (i) net proceeds from our issuance of common units of $187.7 million, (ii) proceeds from our issuance of senior unsecured notes due 2021 of $153.4 million, (iii) proceeds from borrowings under our revolving credit facility of $177.0 million and (iv) proceeds from the exercise of common unit options of $0.9 million, offset by (i) repayment of our revolving credit facility of $317.0 million, (ii) distributions to our unitholders of $84.2 million and (iii) deferred financing costs of $3.4 million.  Net cash provided by financing activities totaled $107.9 million during the six months ended June 30, 2011 and included (i) net borrowings under our revolving credit facility of $185.0 million, (ii) proceeds from our issuance of senior unsecured notes due 2021 of $360.0 million and (iii) proceeds from the exercise of common unit options of $2.4 million, offset by (i) distributions to our unitholders of $76.6 million, (ii) costs to repurchase and redeem our senior unsecured notes due 2016 of $332.6 million, (iii) bond tender and consent premiums of $14.6 million and (iv) deferred financing costs of $15.7 million.

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, primarily through operating cash flows.  We expect to fund long-term cash requirements such as for expansion projects, acquisitions and risk management assets 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.

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 six months ended June 30, 2012, our capital expenditures totaled $170.2 million, consisting of $6.2 million of maintenance capital and $164.0 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 initial 400 MMcf/d cryogenic expansion at our Houston Central complex, (ii) the southwest extension of our DK pipeline, (iii) the southeast extension of our Saint Jo gathering system, (iv) conversion of our Goebel pipeline to condensate service and (v) other pipeline infrastructure in Texas.

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For the second half of 2012, we expect to incur approximately $178 million in additional expansion capital expenditures to complete these projects and to enhance the capabilities and capacities of our current asset base.  Based on our current scope of operations, we expect to incur approximately $7 million to $9 million in maintenance capital expenditures for the second half of 2012.

Investment in Unconsolidated Affiliates.  During the six months ended June 30, 2012, our capital contributions to our unconsolidated affiliates totaled $34.2 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 that we will make approximately $46 million in additional contributions to our unconsolidated affiliates for these projects in the second half of 2012, most of which will relate to Double Eagle 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	Total Capacity(1)		Estimated Capital			Expected In-Service Date
		(range)			($ in millions)
100%-Owned
Houston Central cryogenic upgrade	—	—	700,000	(2)(3)	$	21		Second Quarter 2012(2)
Houston Central 400,000 Mcf/d processing expansion	—	—	1,100,000	(3)	$	165	(4)	First Quarter 2013
Houston Central additional cryogenic capacity	—	—	1,000,000	(5)	$	190		First Half 2014
Goebel conversion(6)	46	12”-14”	—	(7)	$	17		Fourth Quarter 2012
DK pipeline southwest extension	65	24”	—	(8)	$	120		Second Quarter 2013
Joint Ventures
Double Eagle Pipeline	142	12”-16”	100,000		$	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.
(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 exceeding our original performance expectations.
(3)	Reflects the facility’s overall nameplate capacity, but operating performance may be reduced to the extent that the NGL content of inlet gas exceeds the original design specifications of one or more of the facility’s components.
(4)	The $20 million increase in estimated capital, as compared to $145 million previously disclosed, is due primarily to scope changes to accommodate the second 400,000 Mcf/d cryogenic expansion.
(5)	Consists of installing 400,000 Mcf/d of new, more efficient cryogenic processing capacity designed to process gas with higher NGL content, which ultimately should enable us to relegate the 500,000 Mcf/d lean oil processing facility to providing overflow and interruptible volume services.
(6)	We are converting our Goebel pipeline from natural gas to condensate/crude service and will lease its capacity to Double Eagle Pipeline for gathering service.
(7)	The Double Eagle Pipeline system and the Goebel pipeline together will provide 100,000 Bbls/d of condensate gathering capacity from the Eagle Ford Shale to the Texas Gulf Coast.
(8)	The DK pipeline with the southwest extension will increase the total system capacity from 195,000 Mcf/d to 350,000 Mcf/d.
(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)	$	42,336	$	169,345

(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 July 31, 2012, we had 42,300 outstanding restricted units and 1,211,501 outstanding phantom units.

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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 overall 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 the remainder of 2012, and we expect to raise additional capital to fund 2013 expansion capital expenditures.  Our historical financing strategy for funding long-term capital expenditures has been to target a roughly equal mix of debt and equity financing and a consolidated leverage ratio of 4.0 to 1.0 or less.  If we exceed our target leverage ratio, as we expect we will from time to time for significant capital projects, acquisitions or other investments, we anticipate reducing leverage through growth in our cash flow or issuance of additional equity.

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.

Our Indebtedness

As of June 30, 2012, our aggregate outstanding indebtedness totaled $1.0 billion, 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.

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.  On July 30, 2012, Standard & Poor’s Ratings Services reduced our Corporate Credit Rating from BB- to B+ with a stable outlook and reduced the rating for our senior unsecured notes from B+ to B.  We do not expect that these changes will have a material impact on our financing strategy or access to capital.

Revolving Credit Facility.  As of June 30, 2012, we had $245 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

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amended credit agreement, up to 15% of our Consolidated EBITDA for purposes of calculating this ratio may consist of projected EBITDA attributable to material capital projects (generally, capital projects expected to exceed $20 million) then under construction, including our net share of projected EBITDA attributable to capital projects pursued by joint ventures in which we own interests (“Material Project EBITDA”).  At June 30, 2012, our consolidated leverage ratio was 4.26 to 1.0.

·The maximum senior secured leverage ratio (total senior secured debt to Consolidated EBITDA as defined in the amended credit agreement) permitted under the agreement is 4.0 to 1.0.  Up to 15% of our Consolidated EBITDA for purposes of calculating this ratio may consist of Material Project EBITDA.  At June 30, 2012, our senior secured leverage ratio was 1.04 to 1.0.

·The minimum consolidated interest coverage ratio (Consolidated EBITDA to interest as defined in the amended credit agreement) as of the end of any fiscal quarter may not be less than 2.50 to 1.00.  At June 30, 2012, our consolidated interest coverage ratio was 3.75 to 1.00.

Based on our trailing four-quarter Consolidated EBITDA, as defined under the amended credit agreement, at June 30, 2012, we could borrow an additional $233.2 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 June 30, 2012, our ratio of consolidated cash flow to fixed charges was 3.41 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 June 30, 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.

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,

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(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.

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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.

Contract Pricing(1)	Q1 2011		Q2 2011		Q3 2011		Q4 2011		Q1 2012(5)		Q2 2012
Fee-based	43	%	45	%	48	%	48	%	61	%	62	%
Percentage-of-proceeds(2)	32	%	36	%	33	%	26	%	26	%	18	%
Keep-whole and other(3)	37	%	33	%	29	%	41	%	19	%	16	%
Net hedging(4)	(12	)%	(14	)%	(10	)%	(15	)%	(6	)%	4	%

(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 and vice versa.

(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” includes 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 $0.3 million to our total segment gross margin for the six months ended June 30, 2012.  We also calculated that a $0.10 per MMBtu increase or decrease in the price of natural gas would not change our total segment gross margin for the six months ended June 30, 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 half of 2012, partially reducing our commodity price sensitivity for the period.

Our Hedge Portfolio

Commodity Hedges.  As of June 30, 2012, our commodity hedge portfolio totaled $32.4 million.  For additional information, please read Note 11, “Financial Instruments,” included in Item 1 of this report.

	Put
	Strike		Volumes
	(Per gallon)		(Bbls/d)
Mont Belvieu Purity Ethane
2012	$	0.5900	1,500
2012 (July through September) (1)(2)	$	0.5900	(1,500	)
2012	$	0.6700	400
2012 (July through September) (1) (2)	$	0.6700	(400	)
2012 (July through September) (1) (2)	$	0.3725	1,900
Mont Belvieu TET Propane
2012(1)	$	1.1500	700
2012 (July through September) (1) (2)	$	1.1500	(700	)
2012	$	1.0700	600
2012 (July through September) (1) (2)	$	1.0700	(600	)
2012	$	1.1700	600
2012 (July through September) (1) (2)	$	1.1700	(600	)

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	Put
	Strike		Volumes
	(Per gallon)		(Bbls/d)
2012(1)	$	1.3200	400
2012 (July through September) (1) (2)	$	1.3200	(400	)
2012 (July through September) (1) (2)	$	0.9000	1,700
2012 (July through September) (1) (2)	$	0.9163	600
2013	$	1.2400	600
2013	$	1.2750	350
2013	$	1.2200	300
2013	$	1.2800	300
2013	$	1.3300	250
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
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.

(2) Instrument was executed in July 2012.

Interest Rate Swaps.  As of June 30, 2012, the fair value of our interest rate swaps liability totaled $1.8 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 purchases of natural gas and sales of the residue gas and NGLs expose us to significant credit risk, as our margin on any sale is generally a very small percentage of the total sale price.  Therefore, a credit loss could be very large relative to our overall profitability.  For the six months ended June 30, 2012, Dow Hydrocarbon and Resources LLC, (17%), ONEOK Hydrocarbons, L.P. (14%), Formosa Hydrocarbons Company, Inc. (10%), Enterprise Products Operating, L.P. (8%), and

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ONEOK Energy Services, L.P. (7%) collectively accounted for approximately 56% of our revenue.  As of June 30, 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 30% of our revenue have an investment grade parent, are themselves investment grade, have provided us with credit support in the form of a letter of credit issued by an investment grade financial institution or have provided prepayment for our services.

We also diligently review the creditworthiness of other counterparties to which we may have credit exposure, including hedge counterparties.  Our risk management policy requires that we review and report the credit ratings of our hedging counterparties on a monthly basis.  As of June 30, 2012, the value of our commodity net hedge positions by counterparty consisted of assets with JP Morgan (25%), Barclays Bank PLC (20%), Goldman Sachs (18%), Wells Fargo (12%), Credit Suisse (8%), Scotia Bank (6%), Bank of America (6%) and BBVA (5%).  As of June 30, 2012, all of our counterparties were rated Baa3 and BBB+ or better by Moody’s Investors Service and Standard & Poor’s Ratings Services, respectively.  Our hedge counterparties have not posted collateral to secure their obligations to us.

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

Item 4.  Controls and Procedures.

As required by Rule 13a-15(b) of the Exchange Act, we have evaluated, under the direction of our Chief Executive Officer and Chief Financial Officer, the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) as of the end of the period covered by this report.  Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by us in reports that we file under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC.  Based upon the evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that our disclosure controls and procedures were effective at June 30, 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 June 30, 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 and under Part II, Item 1A of our 10-Q for the quarter ended March 31, 2012.  These risks and uncertainties could materially adversely affect our business, financial condition and results of operations.  If any of these risks or uncertainties were to occur, our business, financial condition or results of operation could be materially adversely affected.

Item 6.  Exhibits.

Exhibits not incorporated by reference to a prior filing are designated by an asterisk (*) 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,

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	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	Form of Phantom Unit Award Agreement (incorporated by reference to Exhibit 99.1 to the Current Report on Form 8-K filed May 21, 2012).
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 August 9, 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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