Crestwood Midstream Partners 10Q/A 2011 Q3 Quarterly report (amended)

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q/A

(Amendment No. 1)


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

For the quarterly period ended September 30, 2011


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

For the transition period from to

Commission file number: 001-33631

Crestwood Midstream Partners LP

(Exact name of registrant as specified in its charter)


Delaware (State or other jurisdiction of incorporation or organization)		56-2639586 (I.R.S. Employer Identification No.)


717 Texas Avenue, Suite 3150, Houston, Texas (Address of principal executive offices)		77002 (Zip Code)

(832) 519-2200
(Registrant’s telephone number, including area code)

None
(Former name, former address and former fiscal year, if changed since last report)

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. Yesþ Noo

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). Yesþ Noo

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


Large accelerated filero	Accelerated filerþ	Non-accelerated filero	Smaller reporting companyo
		(Do not check if a smaller reporting company)

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yeso Noþ

Indicate the number of shares outstanding of the issuer’s common units and Class C units, as of the latest practicable date:


Title of Class		Outstanding as of October 28, 2011

Common Units		32,992,696
Class C Units		6,452,233

DEFINITIONS

As used in this report, unless the context otherwise requires:

“Bbl(s)”means barrel or barrels

“EBITDA”means earnings before interest, taxes, depreciation, amortization and accretion

“hp”means horsepower

“LIBOR”means London Interbank Offered Rate

“Management”means management of Crestwood Midstream Partners LP’s General Partner

“Mcf”means thousand cubic feet

“MMcf”means million cubic feet

“MMcfd”means million cubic feet per day

“MMcfe”means MMcf of natural gas equivalents, calculated as one Bbl of oil or NGLs equaling six Mcf of gas

“MMcfed”means MMcfe per day

“NGL(s)”means natural gas liquids

“Oil”includes crude oil and condensate

COMMONLY USED TERMS

Other commonly used terms and their definitions follow:

“Alliance Midstream Assets”means gathering and treating assets purchased from Quicksilver in January 2010 in the Alliance Airport area of Tarrant and Denton Counties, Texas

“Alliance System”means the Alliance Midstream Assets and subsequent additions

“Barnett Shale”means our Cowtown System, Lake Arlington System and Alliance System

“CMLP”means Crestwood Midstream Partners LP and our wholly owned subsidiaries, which trades under the ticker symbol “CMLP”

“Credit Facility”means our senior secured credit facility, as amended, dated effective October 1, 2010

“Crestwood”means Crestwood Holdings Partners, LLC and its affiliates

“Crestwood Holdings”means Crestwood Holdings LLC and its affiliates

“Crestwood Transaction”means the sale to Crestwood by Quicksilver of all its interests in CMLP that was completed on October 1, 2010

“Exchange Act”means the Securities Exchange Act of 1934, as amended

“Fayetteville Shale System”means the pipeline, compression and treating assets located in Arkansas that were acquired in the Frontier Gas Acquisition and subsequent additions

“Frontier”means Frontier Gas Services, LLC, a Delaware limited liability company

“Frontier Gas Acquisition”means the purchase of midstream assets in the Fayetteville Shale and Granite Wash from Frontier that was completed on April 1, 2011

“GAAP”means generally accepted accounting principles in the United States

“General Partner”means Crestwood Gas Services GP LLC

“Granite Wash System”means the pipeline, compression and processing assets and subsequent additions located in Roberts County, Texas, that were acquired in the Frontier Gas Acquisition

“Joinder Agreement”means the additional commitments received from certain lenders under our Credit Facility, dated April 1, 2011, which expanded the total borrowing capacity under our Credit Facility to $500 million

“Lake Arlington System”means gathering and compression assets purchased from Quicksilver in 2008 located in eastern Tarrant County, Texas

“Las Animas System”means the gathering assets acquired in February 2011, located in Eddy County, New Mexico and subsequent additions

“Omnibus Agreement”means the Omnibus Agreement, dated October 8, 2010, among our General Partner and Crestwood

“Partnership Agreement”means the Second Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP, dated February 19, 2008, as amended

“Tristate”means Tristate Sabine, LLC

“Sabine System”means the gathering and treating assets located in Sabine Parish, Louisiana, acquired on November 1, 2011

“Senior Notes”means the $200 million aggregate principal amount of 7.75% Senior Notes due 2019 issued by CMLP on April 1, 2011

“Quicksilver”means Quicksilver Resources Inc. and its affiliates

“SEC”means the U.S. Securities and Exchange Commission

Explanatory Note

Crestwood Midstream Partners LP is filing this Amendment No. 1 on Form 10-Q/A (this “Amendment”) to amend its Quarterly Report on Form 10-Q for the quarterly period ended September 30, 2011, filed with the Securities and Exchange Commission on November 8, 2011 (the “Original 10-Q”) to correct an error in the pro forma presentation of income table within footnote 3 “Acquisitions.” This Amendment has no impact on our previously reported statements of income, balance sheets, statements of cash flows, statements of changes in partners' capital, results of operations or liquidity and does not affect our Credit Facility.

This Amendment also amends and restates the exhibit list in Part II, Item 6 of the Original 10-Q and re-files certain exhibits specified herein, including currently dated certifications of our chief executive officer and chief financial officer as set forth as Exhibits 31.1, 31.2 and 32.1 hereto, as well as Part I “Item 4. Controls, and Procedures” and Part II “Item IA Risk Factors” to account for the error noted in this Amendment.

Except as described above, we have not modified or updated other disclosures contained in the Original 10-Q. Accordingly, this Amendment, with the exception of the foregoing, does not reflect events occurring after the date of filing of the Original 10-Q, or modify or update those disclosures affected by subsequent events. Consequently, all other information not affected by the corrections described above is unchanged and reflects the disclosures and other information made at the date of the filing of the Original 10-Q and should be read in conjunction with our filings with the SEC subsequent to the filing of the Original 10-Q, including amendments to those filings, if any.

Pursuant to Rule 406T of Regulation S-T, the interactive data files on Exhibit 101 hereto are deemed not filed or part of a registration statement or prospectus for purposes of Sections 11 or 12 of the Securities Act of 1933, as amended, are deemed not filed for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and otherwise are not subject to liability under those sections.

CRESTWOOD MIDSTREAM PARTNERS LP
INDEX TO FORM 10-Q/A
For the Period Ended September 30, 2011


PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)			6

Condensed Consolidated Statements of Income for the three and nine months ended September 30, 2011 and 2010			6

Condensed Consolidated Balance Sheets as of September 30, 2011 and December 31, 2010			7

Condensed Consolidated Statements of Cash Flows for the nine months ended September 30, 2011 and 2010			8

Condensed Consolidated Statements of Changes in Partners’ Capital for the nine months ended September 30, 2011 and 2010			9

Notes to Condensed Consolidated Financial Statements			10

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			25

Item 3. Quantitative and Qualitative Disclosures About Market Risk			36

Item 4. Controls and Procedures			36

PART II. OTHER INFORMATION

Item 1. Legal Proceedings			37

Item 1A. Risk Factors			37

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds			37

Item 3. Defaults Upon Senior Securities			37

Item 4. (Removed and Reserved)			37

Item 5. Other Information			37

Item 6. Exhibits			38

Signatures			39
Certification(s) Pursuant to Section 302
Certification Pursuant to Section 906
EX-31.1
EX-31.2
EX-32.1
EX-101 INSTANCE DOCUMENT
EX-101 SCHEMA DOCUMENT
EX-101 CALCULATION LINKBASE DOCUMENT
EX-101 LABELS LINKBASE DOCUMENT
EX-101 PRESENTATION LINKBASE DOCUMENT
EX-101 DEFINITION LINKBASE DOCUMENT

FORWARD-LOOKING INFORMATION

Certain statements contained in this report and other materials we file with the SEC, or in other written or oral statements made or to be made by us, other than statements of historical fact, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995. Forward-looking statements reflect our current expectations or forecasts of future events. Words such as “may,” “assume,” “forecast,” “predict,” “strategy,” “expect,” “intend,” “plan,” “aim,” “estimate,” “anticipate,” “believe,” “project,” “budget,” “potential,” or “continue,” and similar expressions are used to identify forward-looking statements. Forward-looking statements can be affected by assumptions used or by known or unknown risks or uncertainties. Consequently, no forward-looking statements can be guaranteed. Actual results may vary materially. You are cautioned not to place undue reliance on any forward-looking statements and should also understand that it is not possible to predict or identify all such factors and should not consider the following list to be a complete statement of all potential risks and uncertainties. Factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include:

	•		changes in general economic conditions;

	•		fluctuations in natural gas prices;

	•		failure or delays by our customers in achieving expected production in their natural gas projects;

	•		competitive conditions in our industry;

	•		actions or inactions taken or non-performance by third parties, including suppliers, contractors, operators, processors, transporters and customers;

	•		our ability to consummate acquisitions, successfully integrate acquired business and realize any cost savings and other synergies from any acquisition;

	•		fluctuations in the value of certain of our assets and liabilities;

	•		changes in the availability and cost of capital;

	•		operating hazards, natural disasters, weather-related delays, casualty losses and other matters beyond our control;

	•		construction costs or capital expenditures exceeding estimated or budgeted amounts;

	•		the effects of existing and future laws and governmental regulations, including environmental and climate change requirements;

	•		the effects of existing and future litigation;

	•		risks related to our substantial indebtedness; and

	•		certain factors discussed elsewhere in this Quarterly Report.

The list of factors is not exhaustive, and new factors may emerge or changes to these factors may occur that would impact our business. Additional information regarding these and other factors may be contained in our filings with the SEC, especially on Forms 10-K, 10-Q and 8-K. All such risk factors are difficult to predict and are subject to material uncertainties that may affect actual results and may be beyond our control. The forward-looking statements included in this report are made only as of the date of this report, and we undertake no obligation to update any of these forward-looking statements to reflect subsequent events or circumstances except to the extent required by applicable law.

All forward-looking statements are expressly qualified in their entirety by the foregoing cautionary statements.

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements (Unaudited)

CRESTWOOD MIDSTREAM PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF INCOME
In thousands, except for per unit data — Unaudited


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
Revenue
Gathering revenue — related party	$	27,840	$	20,670	$	75,706	$	55,464
Gathering revenue		8,007		1,710		17,908		4,165
Processing revenue — related party		7,183		7,372		21,723		20,625
Processing revenue		692		614		1,867		2,045
Product sales		14,893		—		29,326		—

Total revenue		58,615		30,366		146,530		82,299


Expenses
Operations and maintenance		10,573		6,564		26,165		19,979
Product purchases		13,482		—		26,010		—
General and administrative		5,566		2,652		17,996		8,112
Depreciation, amortization and accretion		9,595		5,689		23,981		16,696

Total expenses		39,216		14,905		94,152		44,787


Gain from exchange of property, plant and equipment		1,106		—		1,106		—

Operating income		20,505		15,461		53,484		37,512

Interest expense		7,100		3,185		19,925		8,808


Income from continuing operations before income taxes		13,405		12,276		33,559		28,704

Income tax provision		347		45		898		171


Net income	$	13,058	$	12,231	$	32,661	$	28,533


General partner interest in net income	$	2,426	$	743	$	4,942	$	1,777
Limited partners’ interest in net income	$	10,632	$	11,488	$	27,719	$	26,756

Basic income per unit:
Net income per limited partner unit — basic	$	0.27	$	0.40	$	0.76	$	0.94

Diluted income per unit:
Net income per limited partner unit — diluted	$	0.27	$	0.38	$	0.76	$	0.90

Weighted average number of common units outstanding:
Basic		39,388		28,502		36,424		28,502
Diluted		39,504		31,561		36,540		31,783
Distributions declared per unit (attributable to the period ended)	$	0.48	$	0.42	$	1.38	$	1.23

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

CRESTWOOD MIDSTREAM PARTNERS LP

CONDENSED CONSOLIDATED BALANCE SHEETS
In thousands, except for unit data — Unaudited


	September 30,		December 31,
	2011		2010
ASSETS
Current assets
Cash and cash equivalents	$	58	$	2
Accounts receivable		7,373		1,679
Accounts receivable — related party		28,678		23,003
Prepaid expenses and other		2,254		1,052

Total current assets		38,363		25,736

Property, plant and equipment, net		682,000		531,371
Intangible assets, net		112,739		—
Goodwill		93,628		—
Other assets		18,132		13,520

Total assets	$	944,862	$	570,627


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accounts payable and other	$	27,650	$	2,917
Accrued additions to property, plant and equipment		7,873		11,309
Accounts payable — related party		1,918		4,267
Capital leases		2,672		—

Total current liabilities		40,113		18,493

Long-term debt		428,000		283,504
Long-term capital leases		4,610		—
Asset retirement obligations		10,822		9,877
Commitments and contingent liabilities (Note 13)

Partners’ capital
Common unitholders (32,992,696 and 31,187,696,units issued and outstanding at September 30, 2011 and December 31, 2010)		294,756		258,069
Class C unit holders (6,452,233 and 0 units issued and outstanding at September 30, 2011 and December 31, 2010, respectively)		155,795		—
General partner		10,766		684

Total partners’ capital		461,317		258,753

	$	944,862	$	570,627

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

CRESTWOOD MIDSTREAM PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CASH FLOWS
In thousands — Unaudited


	Nine Months Ended September 30,
	2011			2010
Operating activities:
Net income	$	32,661		$	28,533
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization		23,554			16,321
Accretion of asset retirement obligations		427			375
Deferred income taxes		—			171
Equity-based compensation		851			2,001
Non-cash interest expense		2,542			3,323
Gain from exchange of plant, property and equipment		(1,106	)		—
Changes in assets and liabilities:
Accounts receivable		(5,359	)		(620	)
Prepaid expenses and other		(447	)		(923	)
Accounts receivable — related party		(5,675	)		(8,117	)
Accounts payable — related party		(2,349	)		—
Accounts payable and other		23,366			3,809

Net cash provided by operating activities		68,465			44,873


Investing activities:
Capital expenditures		(31,256	)		(52,470	)
Proceeds from exchange of plant, property and equipment		5,943			—
Acquisitions, net of cash acquired		(349,662	)		—
Distribution to Quicksilver for Alliance Midstream Assets		—			(80,276	)

Net cash used in investing activities		(374,975	)		(132,746	)


Financing activities:
Proceeds from senior notes		200,000			—
Proceeds from credit facility		100,200			143,200
Repayments of credit facility		(155,704	)		(30,100	)
Debt issuance costs paid		(6,982	)		—
Proceeds from issuance of Class C units, net		152,671			—
Proceeds from issuance of Common units, net		53,550			11,054
Contributions by partners		8,741			—
Distributions paid		(45,910	)		(35,826	)
Taxes paid for equity-based compensation vesting		—			(1,144	)

Net cash provided by financing activities		306,566			87,184


Net cash increase (decrease)		56			(689	)

Cash and cash equivalents at beginning of period		2			746


Cash and cash equivalents at end of period	$	58		$	57


Cash paid for interest	$	9,380		$	5,485
Non-cash transactions:
Working capital related to capital expenditures		7,873			15,269
PIK value to Class C unitholders		6,050			—

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

CRESTWOOD MIDSTREAM PARTNERS LP

CONDENSED CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL
In thousands – Unaudited


	Limited Partners’
	Common			Subordinated			General Partner			Total
Balance at December 31, 2009	$	281,239		$	3,040		$	558		$	284,837
Equity-based compensation		2,001			—			—			2,001
Distributions paid		(20,387	)		(13,815	)		(1,624	)		(35,826	)
Distributions to Quicksilver		(80,276	)		—			—			(80,276	)
Net income		16,347			10,409			1,777			28,533
Issuance of units, net of offering costs		11,054			—			—			11,054
Taxes paid for equity-based compensation vesting		(1,144	)		—			—			(1,144	)

Balance at September 30, 2010	$	208,834		$	(366	)	$	711		$	209,179


	Limited Partners’
	Common			Class C		General Partner			Total
Balance at December 31, 2010	$	258,069		$	—	$	684		$	258,753
Equity-based compensation		851			—		—			851
Distributions paid		(42,309	)		—		(3,601	)		(45,910	)
Net income		24,595			3,124		4,942			32,661
Issuance of units, net of offering costs		53,550			152,671		—			206,221
Contributions by partners		—			—		8,741			8,741

Balance at September 30, 2011	$	294,756		$	155,795	$	10,766		$	461,317

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

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONDENSED CONSOLIDATED INTERIM FINANCIAL STATEMENTS
UNAUDITED

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization— Crestwood Midstream Partners LP is a publicly traded Delaware limited partnership formed for the purpose of acquiring and operating midstream assets. Our common units are listed on the New York Stock Exchange under the symbol “CMLP.” In this report, unless the context requires otherwise, references to “we,” “us,” “our” or the “Partnership” are intended to mean the business and operations of Crestwood Midstream Partners LP and its subsidiaries.

As of September 30, 2011 our ownership is as follows:


	Ownership Percentage
	Crestwood			Public			Total
General partner interest		1.9	%		—			1.9	%
Limited partner interest:
Common unitholders		48.6	%		33.5	%		82.1	%
Class C unitholders		0.5	%		15.5	%		16.0	%

Total		51.0	%		49.0	%		100.0	%

Description of Business— We are primarily engaged in the gathering, compression, processing and treating of natural gas and the delivery of NGLs produced in the Barnett Shale, Fayetteville Shale, Avalon Shale and Granite Wash areas. We provide these midstream services under long-term contracts, whereby we receive fees for performing gathering, compression, processing and treating services.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation— The accompanying financial statements and related notes present the unaudited condensed consolidated balance sheets as of September 30, 2011 and December 31, 2010. They also include the unaudited condensed consolidated statements of income for the three and nine month periods ended September 30, 2011 and 2010, the unaudited condensed consolidated statements of cash flows and unaudited changes in partners’ capital for the nine month periods ended September 30, 2011 and 2010.

The accompanying condensed consolidated financial statements were prepared in accordance with GAAP for the interim financial information and in accordance with the rules and regulations of the SEC. In management’s opinion, all necessary adjustments to fairly present our results of operations, financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and recurring nature. Certain disclosures normally included in financial statements prepared in accordance with GAAP have been condensed or omitted. Accordingly, these financial statements should be read in conjunction with our consolidated financial statements and notes thereto included in our 2010 Annual Report on Form 10-K.

Changes in Presentation —Certain changes have been made to the 2010 financial statements for presentations adopted in 2011. The amount of the change is approximately $0.6 million and $1.8 million for the three and nine months ended September 30, 2010, respectively, from operations and maintenance expense to general and administrative expense.

Use of Estimates —The preparation of financial statements in accordance with GAAP requires management to make estimates and judgments that affect the reported amount of assets, liabilities, revenue and expenses and disclosure of contingent assets and liabilities that exist at the date of the financial statements. Estimates and judgments are based on information available at the time such estimates and judgments are made. Although management believes the estimates are appropriate, actual results can differ from those estimates.

Fair Value of Financial Instruments —The fair value of cash and cash equivalents, accounts receivable, accounts payable and Credit Facility debt approximate their carrying amounts as of September 30, 2011. The fair value of our Senior Notes was $192 million as of September 30, 2011.

Revenue Recognition— Our primary service offerings are the gathering, compression, processing and treating of natural gas. We have fixed-fee contracts under which we receive revenue based on the volume of natural gas gathered and processed. We also have percent-of-proceeds contracts where we receive revenue based on the value of products sold to third parties which we present as Product Sales. We recognize revenue when all of the following criteria are met:

	•		persuasive evidence of an exchange arrangement exists;

	•		services have been rendered;

	•		the price for its services is fixed or determinable; and

	•		collectability is reasonably assured.

Segment Information— Our operations include three reportable operating segments. These operating segments reflect how we manage our operations. Our business segments reflect the primary geographic areas in which we operate and consist of the Barnett Shale, the Fayetteville Shale and the Granite Wash. Our business segments are engaged in the gathering, compression, processing and treating of natural gas and delivery of NGLs.

Net Income per Limited Partner Unit— The following is a reconciliation of the components of the basic and diluted net income per limited partner unit calculations for the three and nine months ended September 30, 2011 and 2010. There have not been any units excluded due to being anti-dilutive.


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2011		2010		2011		2010
	(In thousands, except per unit data)
Limited partners’ interest in net income	$	10,632	$	11,488	$	27,719	$	26,756
Impact of interest on subordinated note⁽¹⁾		—		647		—		1,860

Income available assuming conversion of convertible debt	$	10,632	$	12,135	$	27,719	$	28,616


Weighted-average common units — basic⁽²⁾		39,388		28,502		36,424		28,502
Effect of unvested phantom units		116		516		116		516
Effect of subordinated note⁽¹⁾		—		2,543		—		2,765

Weighted-average common units — diluted		39,504		31,561		36,540		31,783


Basic earnings per unit:
Net income per limited partner unit — basic	$	0.27	$	0.40	$	0.76	$	0.94

Diluted earnings per unit:
Net income per limited partner unit — diluted	$	0.27	$	0.38	$	0.76	$	0.90
Conversion price⁽¹⁾		N/A	$	22.65		N/A	$	20.84


		⁽¹⁾Assumes that convertible debt is converted using the lesser of average closing price per unit or final closing price on September 30, 2010. See Note 7 to the consolidated financial statements in our Annual Report on Form 10-K for a more complete description of our subordinated note that terminated during the fourth quarter of 2010.

		⁽²⁾ Includes 6,398,418 and 4,253,787 shares of Class C units for the three and nine months ended September 30, 2011, respectively.

Comprehensive Income— Comprehensive income is equal to net income for the periods presented due to the absence of any other comprehensive income.

Recently Issued Accounting Standards

Accounting standard-setting organizations frequently issue new or revised accounting rules. We regularly review all new pronouncements to determine their impact, if any, on our financial statements. No pronouncements materially affecting our financial statements have been issued since the filing of our 2010 Annual Report on Form 10-K.

3. ACQUISITIONS

Las Animas Acquisition

Effective February 1, 2011, we acquired natural gas gathering pipelines near the emerging Avalon Shale and Bone Spring trends in Southeastern New Mexico for $5.1 million. The pipelines, which we refer to as the Las Animas System, are supported by long-term, primarily fixed-fee contracts which include existing Morrow/Atoka production. The Avalon Shale is a liquids-rich oil and gas producing formation that is part of the Permian basin located in West Texas.

Las Animas System

The Las Animas System, located in Eddy County, New Mexico, near the emerging Avalon Shale and Bone Spring trends in Southeastern New Mexico, consists of natural gas gathering pipelines that deliver gas to El Paso Natural Gas and Southern Union Gas Services. The Las Animas System is reflected in the Barnett Shale for segment reporting.

Frontier Gas Acquisition

On April 1, 2011, we completed the Frontier Gas Acquisition including assets in the Fayetteville Shale and the Granite Wash. The Fayetteville Shale is a dry gas formation in the Arkoma basin located in Arkansas. The Granite Wash is a liquids-rich oil and gas producing formation in the Anadarko basin located in the Texas Panhandle.

		Fayetteville Shale System

		The Fayetteville Shale System, located in Arkansas, consists of high pressure and low pressure gathering pipelines with a capacity of approximately 510 MMcfd, treating capacity of approximately 165 MMcfd and approximately 35,000 hp of compression. This system interconnects with multiple interstate pipelines and is supported by long-term, primarily fixed-fee contracts with producers in the core of the Fayetteville Shale, with initial terms through 2020 with five year extensions.

	-		Twin Groves / Prairie Creek / Woolly Hollow System. Located in Conway and Faulkner Counties, Arkansas and consists of a gathering system and a related gas compression facility with a capacity of 350 MMcfd and a dehydration and treating facility with capacity of 165 MMcfd. This system gathers natural gas produced by BHP Billiton Petroleum, a wholly owned subsidiary of BHP Billiton Limited (“BHP”), BP p.l.c. (“BP”) and XTO Energy, Inc., a subsidiary of Exxon Mobil Corporation (“ExxonMobil”) and interconnects with interstate pipelines including Boardwalk Gas Transmission, Ozark Gas Transmission and Fayetteville Express Pipeline.

	-		Rose Bud System. Located in White County, Arkansas and consists of a gathering system and a related gas compression facility with a capacity of 60 MMcfd. This system gathers natural gas produced by BHP / BP and ExxonMobil, and interconnects with Ozark Gas Transmission.

	-		Wilson Creek System. Located in Van Buren County, Arkansas and consists of a gathering system and a related compression facility with a capacity of 100 MMcfd. This system gathers natural gas produced by BHP and SH Exploration and interconnects with Ozark Gas Transmission.

Granite Wash System

The Granite Wash System, located in Roberts County, Texas, consists of a gathering system and NGL pipeline system, approximately 9,000 hp of compression, and the Indian Creek Plant consisting of a 36 MMcfd natural gas processing unit that extracts NGLs from the natural gas stream. This system gathers natural gas produced by Chesapeake Energy Corporation and others and delivers NGLs to the Mid-America Pipeline for ultimate delivery to the Mt. Belvieu or Conway NGL market centers. Residue gas is delivered into ANR Pipeline Company and Northern Natural Gas Company.

The final purchase price allocation is as follows ($ in thousands):


Purchase Price:
Total purchase price	$	344,562


Preliminary Purchase Price Allocation:
Accounts receivable		335
Prepaid expenses and other		750
Capital lease asset		8,587
Property, plant and equipment		135,918
Intangible assets		114,200
Other assets		178

Total assets	$	259,968


Current portion of capital leases		2,576
Other payables		64
Capital leases		6,011
Asset Retirement Obligations		383

Total liabilities	$	9,034



Goodwill	$	93,628

The $338 million purchase price paid at closing was financed through a combination of equity and debt as described in Notes 4 and 7 to our condensed consolidated interim financial statements in this Quarterly Report. The total purchase price paid of $345

million also includes $4 million in capital expenditures and $3 million of inventory purchased. Transaction costs for the nine months ended September 30, 2011 were $5.7 million of which $3.2 million was recorded in general and administrative expense and $2.5 million was recorded in interest expense.

The following table is the presentation of income as if we had owned the Fayetteville and Granite Wash Systems for the three and nine months ended September 30, 2010 and for nine months ended September 30, 2011. Subsequent to the issuance of the financial statements, we determined the amounts previously presented contained errors. The information reflects corrections to expenses, which as previously presented did not include depreciation and general and administration expenses for the three and nine month period ended September 30, 2010 and for the nine months ended September 30, 2011.


	Three Months Ended September 30, 2010									Three Months Ended September 30, 2010
	As Previously Presented									As Restated
	Crestwood									Crestwood
	Midstream			Fayetteville and						Midstream			Fayetteville and
	Partners LP			Granite Wash			Combined			Partners LP			Granite Wash			Combined
	(In thousands)									(In thousands)
Revenue	$	30,366		$	16,702		$	47,068		$	30,366		$	16,702		$	47,068
Expenses		(14,905	)		(11,246	)		(26,151	)		(14,905	)		(14,775	)		(29,680	)

Operating income	$	15,461		$	5,456		$	20,917		$	15,461		$	1,927		$	17,388


Basic earnings per limited partner unit:	$	0.40					$	0.59		$	0.40					$	0.26
Diluted earnings per limited partner unit:	$	0.38					$	0.55		$	0.38					$	0.26


	Nine Months Ended September 30, 2010									Nine Months Ended September 30, 2010
	As Previously Presented									As Restated
	Crestwood									Crestwood
	Midstream			Fayetteville and						Midstream			Fayetteville and
	Partners LP			Granite Wash			Combined			Partners LP			Granite Wash			Combined
	(In thousands)									(In thousands)
Revenue	$	82,299		$	48,432		$	130,731		$	82,299		$	48,432		$	130,731
Expenses		(44,787	)		(32,416	)		(77,203	)		(44,787	)		(43,120	)		(87,907	)

Operating income	$	37,512		$	16,016		$	53,528		$	37,512		$	5,312		$	42,824


Basic earnings per limited partner unit:	$	0.94					$	1.49		$	0.94					$	0.88
Diluted earnings per limited partner unit:	$	0.90					$	1.40		$	0.90					$	0.85


	Nine Months Ended September 30, 2011									Nine Months Ended September 30, 2011
	As Previously Presented									As Restated
	Crestwood									Crestwood
	Midstream			Fayetteville and						Midstream			Fayetteville and
	Partners LP⁽¹⁾			Granite Wash⁽²⁾			Combined			Partners LP⁽¹⁾			Granite Wash⁽²⁾			Combined
	(In thousands)									(In thousands)
Revenue	$	146,530		$	17,002		$	163,532		$	146,530		$	17,002		$	163,532
Expenses		(94,152	)		(12,420	)		(106,572	)		(94,152	)		(16,014	)		(110,166	)
Gain from exchange of property, plant and equipment		1,106			—			1,106			1,106			—			1,106

Operating income	$	53,484		$	4,582		$	58,066		$	53,484		$	988		$	54,472


Basic earnings per limited partner unit:	$	0.76					$	0.90		$	0.76					$	0.64
Diluted earnings per limited partner unit:	$	0.76					$	0.89		$	0.76					$	0.64


⁽¹⁾		Includes six months of operating income for Fayetteville and Granite Wash, from April 1, 2011 to September 30, 2011, subsequent to acquisition.

⁽²⁾		Represents the first quarter of 2011, prior to the acquisition of Fayetteville and Granite Wash.

4. PARTNERS’ CAPITAL AND DISTRIBUTIONS

On April 1, 2011, we issued 6,243,000 Class C units, representing limited partner interests, in a private placement. The negotiated purchase price for the Class C units was $24.50 per unit, resulting in net proceeds to us of approximately $153 million which was used to finance a portion of our Frontier Gas Acquisition. The Class C units are substantially similar in all respects to our existing common units, representing limited partner interests, except that we can elect to pay distributions for our Class C units through the issuance of additional Class C units or cash. The Class C units will convert into common units on a one-for-one basis on the second anniversary of the date of issuance.

In connection with the issuance of the Class C units, our General Partner made an additional capital contribution of $8.7 million to us in exchange for the issuance of an additional 293,948 general partner units, increasing the General Partner interest to 2%.

On May 4, 2011, we completed a public offering of 1,800,000 common units, representing limited partner interests, under an existing shelf registration statement at a price of $30.65 per common unit ($29.75 per common unit, net of underwriting discounts and commissions), providing net proceeds of approximately $53 million. The net proceeds from the offering were used to reduce indebtedness under our Credit Facility and for general partnership purposes. In connection with the issuance of the common units, our General Partner did not make an additional capital contribution resulting in a reduction of the General Partner’s interest to approximately 1.9%.

Our Partnership Agreement requires that we make distributions within 45 days after the end of each quarter to unitholders of record on the applicable record date selected by the General Partner.

The following table presents distributions attributable to quarters ended in 2011 and 2010:


						PIK Value
	Attributable to the	Per Unit		Total Cash		to Class C				Total IDR
Payment Date	Quarter Ended	Distribution		Distribution		unitholders		Total		Distribution
	(In millions, except per unit information)
Pending Distributions
November 10, 2011	September 30, 2011	$	0.48	$	18.1	$	3.5	$	21.6	$	2.2

Completed Distributions
2011
August 12, 2011	June 30, 2011	$	0.46	$	16.8	$	3.1	$	19.9	$	1.5
May 13, 2011	March 31, 2011	$	0.44	$	14.8	$	2.9	$	17.7	$	0.8
February 11, 2011	December 31, 2010	$	0.43	$	14.3	$	—	$	14.3	$	0.7
2010
November 12, 2010	September 30, 2010	$	0.42	$	13.9	$	—	$	13.9	$	0.6
August 13, 2010	June 30, 2010	$	0.42	$	12.7	$	—	$	12.7	$	0.5
May 14, 2010	March 31, 2010	$	0.39	$	11.6	$	—	$	11.6	$	0.3

Cash distributions included amounts paid to common and subordinated unitholders. Beginning with the distributions for the quarter ended December 31, 2010, we no longer have any subordinated units due to the conversion of all subordinated units into common units. See Note 13 to the consolidated financial statements in our 2010 Annual Report on Form 10-K for a more complete description of our conversion of the subordinated units. We have the option to pay distributions to our Class C unitholders with cash or by issuing additional Class C units based upon the volume weighted average price of our common units for the 10 trading days immediately preceding the date the distribution is declared. For the distribution that was paid August 12, 2011, attributable to the quarter ended June 30, 2011, we issued 115,140 additional Class C units. For the distribution that will be paid November 10, 2011, attributable to the quarter ended September 30, 2011, we will issue 144,402 additional Class C units.

5. PROPERTY, PLANT AND EQUIPMENT

Property, plant and equipment consisted of the following:


	September 30,			December 31,
	2011			2010
	(In thousands)
Gathering systems	$	265,722		$	158,975
Processing plants and compression facilities		403,390			365,208
Construction in progress — gathering		37,120			26,385
Rights-of-way and easements		46,966			32,054
Land		4,511			4,251
Buildings and other		5,380			3,494

		763,089			590,367
Accumulated depreciation		(81,089	)		(58,996	)

Net property, plant and equipment	$	682,000		$	531,371

With the Frontier Gas Acquisition we have leased compressors which are accounted for as capital leases for a total of $8.6 million less accumulated amortization of $1.3 million as of September 30, 2011.

During the quarter we had a gain from exchange of property, plant and equipment due to an agreement with PVR Midstream, LLC, on August 18, 2011, to exchange the delivery of certain processing plants that were under contract with Exterran Energy Solutions, L.P. resulting in proceeds of $5.9 million and a gain of $1.1 million.

6. INTANGIBLE ASSETS AND GOODWILL

Intangible assets consist of gas contracts. The following table summarizes the intangibles and goodwill associated with the purchase of the Frontier Gas Acquisition.


			Accumulated		Net Book
	Cost		Amortization		Value
			(In thousands)
Intangibles — subject to amortization:
Gas contracts	$	114,200	$	1,461	$	112,739

Intangibles — not subject to amortization:
Goodwill		93,628		—		93,628


	$	207,828	$	1,461	$	206,367

The intangible assets have useful lives of 6 to 17 years. Amortization expense recorded for the three and nine months ended September 30, 2011 was approximately $0.7 million and $1.5 million, respectively. The expected amortization of the intangible assets is as follows:


Years Ending (in thousands)
2011 (remaining)	$	718
2012		4,295
2013		5,772
2014		7,039
2015		7,896
Thereafter		87,019


Total	$	112,739

7. DEBT

Debt consisted of the following:


	September 30,		December 31,
	2011		2010
	(In thousands)
Credit Facility	$	228,000	$	283,504
Senior Notes		200,000		—

		428,000		283,504
Current maturities of debt		—		—

Total	$	428,000	$	283,504

Credit Facility —At September 30, 2011, we had $228 million outstanding under our $500 million Credit Facility at the weighted-average interest rate of 3.6%. Borrowings under the Credit Facility bear interest at LIBOR plus an applicable margin or a base rate as defined in the Credit Facility. Under the terms of the Credit Facility, the applicable margin under LIBOR borrowings is 3.25%. On April 1, 2011, we entered into a Joinder Agreement with certain lenders of our Credit Facility, which expanded our borrowing capacity from $400 million to $500 million. See Note 7 to the consolidated financial statements in our 2010 Annual Report on Form 10-K for a more complete description of our indebtedness.

The Credit Facility contains provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.

Bridge Loans —In February 2011, in connection with the Frontier Gas Acquisition, we obtained commitments from multiple lenders for senior unsecured bridge loans in an aggregate amount up to $200 million. The commitment was not drawn and was terminated on April 1, 2011 in connection with the issuance of the Senior Notes described below. We recognized $2.5 million of commitment fees in the second quarter of 2011, which is included in interest expense, related to the bridge loans.

Senior Notes— On April 1, 2011, we issued the Senior Notes. Our obligations under the Senior Notes are guaranteed on an unsecured basis by our current and future domestic subsidiaries. The proceeds were used to partially finance the Frontier Gas Acquisition. The Senior Notes accrue interest at a rate of 7.75% per annum, and are payable in cash semi-annually in arrears on April 1 and October 1 of each year, commencing on October 1, 2011, and mature April 2019. Our Senior Notes require us to maintain a ratio of our consolidated trailing 12-month EBITDA (as defined in the senior notes indenture) to fixed charges of at least 1.75 to 1.0.

8. ACCOUNTS PAYABLE AND OTHER

Accounts payable and other consist of the following:


	September 30,		December 31,
	2011		2010
	(In thousands)
Accrued operating expenses	$	2,206	$	1,736
Accrued property taxes		4,134		—
Product purchases payable		3,869		—
Compensation and benefits payable		2,106		—
Tax payable		1,042		280
Interest payable		8,852		726
Accounts payable		5,179		—
Other		262		175

	$	27,650	$	2,917

9. CAPITAL LEASES

With the Frontier Gas Acquisition we acquired compressor leases which are accounted for as capital leases. The total liability outstanding at September 30, 2011 related to these leases is $7.3 million. Future minimum lease payments related to capital leases are as follows (in thousands):


Years Ending
2011 (remaining)	$	716
2012		2,860
2013		2,860
2014		1,161

Total payments		7,597
Imputed interest		(315	)

Present value of future payments	$	7,282

10. ASSET RETIREMENT OBLIGATIONS

Activity for asset retirement obligations is as follows (in thousands):


Asset retirement obligations as of December 31, 2010	$	9,877
Incremental liability		518
Accretion expense		427

Asset retirement obligations as of September 30, 2011	$	10,822

Accretion expense for the three months ended was approximately $0.2 million. As of September 30, 2011, no assets are legally restricted for use in settling asset retirement obligations.

11. EQUITY-BASED COMPENSATION

Awards of phantom units have been granted under our Third Amended and Restated 2007 Equity Plan (the “2007 Equity Plan”). The following table summarizes information regarding 2011 phantom unit activity:


	Payable in cash				Payable in units
			Weighted Average					Weighted
			Grant Date Fair					Average Grant
	Units		Value		Units			Date Fair Value
Unvested phantom units — January 1, 2011		—	$	—		121,526		$	27.11
Vested		—		—		—			—
Issued		11,777		27.56		24,411			27.10
Cancelled		—		—		(20,287	)		27.17

Unvested phantom units — September 30, 2011		11,777	$	27.56		125,650		$	27.10

At January 1, 2011, we had total unvested compensation cost of $2.6 million related to phantom units. We recognized compensation expense of approximately $0.3 million and $0.9 million during the three and nine months ended September 30, 2011. Grants of phantom units during the nine months ended September 30, 2011 had an estimated grant date fair value of $1.0 million. We had unearned compensation expense of $2.6 million at September 30, 2011, which is generally expected to be recognized over the vesting period of three years except for grants to non-employee directors of our General Partner in lieu of cash compensation, which vest after one year. No phantom units vested during the nine months ended September 30, 2011. At September 30, 2011, 636,356 units were available for issuance under the 2007 Equity Plan.

See Note 11 to the consolidated financial statements in our 2010 Annual Report on Form 10-K, for a more complete description of our 2007 Equity Plan.

12. INCOME TAXES

No provision for federal or state income taxes is included in our results of operations as such income is taxable directly to the partners.

However, we are subject to Texas Margin tax and our current tax liability will be assessed based on 0.7% of the gross revenue apportioned to Texas.

See Note 10 to the consolidated financial statements in our 2010 Annual Report on Form 10-K for more information about our income taxes.

13. COMMITMENTS AND CONTINGENT LIABILITIES

Litigation— In May 2011, a class action lawsuit,Ginardi v. Frontier Gas Services, LLC, et al,was filed in the United States District Court of the Eastern District of Arkansas against Frontier Gas Services, LLC; Chesapeake Energy Corporation, BHP Billiton Petroleum, No 4:11-cv-0420 BRW alleging that defendants’, including Crestwood Arkansas Pipeline LLC (“Crestwood Arkansas”) which was served in August 2011, operations pollute the atmosphere, groundwater, and soil with allegedly harmful gases, chemicals, and compounds and the facilities create excessive noise levels constituting trespass, nuisance and annoyance. The plaintiffs seek compensatory and punitive damages of loss of use and enjoyment of property, contamination of soil and ground water, air and atmosphere and seek future monitoring. Crestwood Arkansas has filed an answer in the matter denying liability. This case has not had, and is not expected to have, a material impact on our results of the operation or financial condition. We intend to vigorously defend against the claims.

At September 30, 2011, we are not currently subject to any material lawsuits or other legal proceedings that could have a material effect on our results of operations, cash flows or financial condition or for which disclosure is required by Item 103 of Regulation S-K.

Casualties or Other Risks— We maintain coverage in various insurance programs, which provide us with property damage and other coverages which are customary for the nature and scope of our operations.

Management of our General Partner believes that we have adequate insurance coverage, although insurance will not cover every type of loss that might occur. As a result of insurance market conditions, premiums and deductibles for certain insurance policies have increased substantially and, in some instances, certain insurance may become unavailable, or available for only reduced amounts of coverage. As a result, we may not be able to renew existing insurance policies or procure other desirable insurance on commercially reasonable terms, if at all.

If we were to incur a significant loss for which we were not adequately insured, the loss could have a material impact on our consolidated financial condition and results of operations and cash flows. In addition, the proceeds of any available insurance may not be paid in a timely manner and may be insufficient if such an event were to occur. Any event that interrupts our revenues, or which causes us to make significant expenditures not covered by insurance, could reduce our ability to meet our financial obligations.

Regulatory Compliance— In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of management of our General Partner, compliance with current laws and regulations will not have a material adverse effect on our financial condition or results of operations and cash flows.

Environmental Compliance— Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. As an owner or operator of these facilities, we are subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At September 30, 2011, we had recorded no liabilities for environmental matters.

14. RELATED-PARTY TRANSACTIONS

We routinely conduct business with Quicksilver and its affiliates. Quicksilver remains a related party as Thomas F. Darden, a member of our General Partner’s board of directors until September 6, 2011, is Chairman of the Board of Quicksilver and beneficially holds a greater than 10% interest in Quicksilver. However, Quicksilver does not own any interest in us. For a more complete description of our agreements with Quicksilver, see Note 12 to the consolidated financial statements in our 2010 Annual Report on Form 10-K.

During the quarter and nine months ended September 30, 2011, Quicksilver accounted for 60% and 66%, respectively of our total revenue. Approximately 6% of our revenue for the nine months ended September 30, 2011 are comprised of natural gas purchased by Quicksilver from Eni SpA and gathered under Quicksilver’s Alliance System gathering agreement.

With the purchase of the Alliance Midstream Assets, we also entered into an agreement with Quicksilver to lease pipeline assets attached to the Alliance System that we did not purchase. We have recognized $0.4 million of expense related to this agreement during the nine months ended September 30, 2011.

15. SUBSEQUENT EVENTS

On November 1, 2011, we acquired Tristate from affiliates of Energy Spectrum Capital, Zwolle Pipeline, LLC and the Tristate management for $65 million of cash paid at closing and a deferred payment of approximately $8 million one year following the closing date, subject to customary post-closing adjustments. The final purchase price allocation is pending the finalization of the appraisal valuations.

Tristate owns the Sabine System which consists of approximately 61 miles of high-pressure natural gas gathering pipelines located in Sabine Parish, Louisiana. The Sabine System provides gathering and treating services for Haynesville and Bossier Shale production from the Toledo Bend South field area for redelivery to Gulf South Pipeline and Tennessee Gas Pipeline. We have contracts on the Sabine System with multiple producers with dedications of approximately 20,000 acres under long term, fixed-fee arrangements. The acquisition was financed with borrowings under our Credit Facility.

16. CONDENSED CONSOLIDATED FINANCIAL INFORMATION

On April 1, 2011, we issued the Senior Notes. Our obligations under the Senior Notes are guaranteed on an unsecured basis by our current and future domestic subsidiaries. Condensed consolidated financial information for CMLP is presented below:

Condensed Consolidated Statements of Income


	For the Three Months Ended September 30, 2011
									Crestwood
	Crestwood			Restricted					Midstream
	Midstream			Guarantor					Partners LP
	Partners LP			Subsidiaries		Eliminations			Consolidated
	(in thousands)
Revenue	$	—		$	58,615	$	—		$	58,615
Operating expenses		5,573			33,643		—			39,216
Gain from exchange of plant, property and equipment		1,106			—		—			1,106

Operating income		(4,467	)		24,972		—			20,505

Interest expense		7,040			60		—			7,100

Income before income tax		(11,507	)		24,912		—			13,405
Income tax provision		—			347		—			347

Net income before equity in net earnings of subsidiaries		(11,507	)		24,565		—			13,058
Equity in net earnings of subsidiaries		24,565			—		(24,565	)		—

Net Income	$	13,058		$	24,565	$	(24,565	)	$	13,058


	For the Three Months Ended September 30, 2010
									Crestwood
	Crestwood			Restricted					Midstream
	Midstream			Guarantor					Partners LP
	Partners LP			Subsidiaries		Eliminations			Consolidated

				(in thousands)
Revenue	$	—		$	30,366	$	—		$	30,366
Operating expenses		2,652			12,253		—			14,905

Operating income		(2,652	)		18,113		—			15,461

Interest expense		3,185			—		—			3,185

Income before income tax		(5,837	)		18,113		—			12,276
Income tax provision		—			45		—			45

Net income before equity in net earnings of subsidiaries		(5,837	)		18,068		—			12,231
Equity in net earnings of subsidiaries		18,068			—		(18,068	)		—

Net Income	$	12,231		$	18,068	$	(18,068	)	$	12,231


	For the Nine Months Ended September 30, 2011
									Crestwood
	Crestwood			Restricted					Midstream
	Midstream			Guarantor					Partners LP
	Partners LP			Subsidiaries		Eliminations			Consolidated

				(in thousands)
Revenue	$	—		$	146,530	$	—		$	146,530
Operating expenses		18,014			76,138		—			94,152
Gain from exchange of plant, property and equipment		1,106			—		—			1,106

Operating income		(16,908	)		70,392		—			53,484

Interest expense		19,800			125		—			19,925

Income before income tax		(36,708	)		70,267		—			33,559
Income tax provision		—			898		—			898

Net income before equity in net earnings of subsidiaries		(36,708	)		69,369		—			32,661
Equity in net earnings of subsidiaries		69,369			—		(69,369	)		—

Net Income	$	32,661		$	69,369	$	(69,369	)	$	32,661


	For the Nine Months Ended September 30, 2010
									Crestwood
	Crestwood			Restricted					Midstream
	Midstream			Guarantor					Partners LP
	Partners LP			Subsidiaries		Eliminations			Consolidated

				(in thousands)
Revenue	$	—		$	82,299	$	—		$	82,299
Operating expenses		8,112			36,675		—			44,787

Operating income		(8,112	)		45,624		—			37,512

Interest expense		8,808			—		—			8,808

Income before income tax		(16,920	)		45,624		—			28,704
Income tax provision		—			171		—			171

Net income before equity in net earnings of subsidiaries		(16,920	)		45,453		—			28,533
Equity in net earnings of subsidiaries		45,453			—		(45,453	)		—

Net Income	$	28,533		$	45,453	$	(45,453	)	$	28,533

Condensed Consolidated Balance Sheet


	September 30, 2011
								Crestwood
	Crestwood		Restricted					Midstream
	Midstream		Guarantor					Partners LP
	Partners LP		Subsidiaries		Eliminations			Consolidated

			(in thousands)
ASSETS
Current assets	$	344,132	$	66,620	$	(372,389	)	$	38,363
Properties, plant and equipment, net		7,910		674,090		—			682,000
Intangible assets, net		—		112,739		—			112,739
Goodwill		—		93,628		—			93,628
Investment in subsidiaries		582,763		—		(582,763	)		—
Other assets		17,333		799		—			18,132

Total assets	$	952,138	$	947,876	$	(955,152	)	$	944,862


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	62,821	$	349,681	$	(372,389	)	$	40,113
Long-term liabilities		428,000		15,432		—			443,432
Partners’ capital		461,317		582,763		(582,763	)		461,317

Total liabilities and partners’ capital	$	952,138	$	947,876	$	(955,152	)	$	944,862


	December 31, 2010
								Crestwood
	Crestwood		Restricted					Midstream
	Midstream		Guarantor					Partners LP
	Partners LP		Subsidiaries		Eliminations			Consolidated

			(in thousands)
ASSETS
Current assets	$	291,637	$	23,843	$	(289,744	)	$	25,736
Properties, plant and equipment, net		11,142		520,229		—			531,371
Investment in subsidiaries		228,587		—		(228,587	)		—
Other assets		12,890		630		—			13,520

Total assets	$	544,256	$	544,702	$	(518,331	)	$	570,627


LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities	$	1,999	$	306,238	$	(289,744	)	$	18,493
Long-term liabilities		283,504		9,877		—			293,381
Partners’ capital		258,753		228,587		(228,587	)		258,753

Total liabilities and partners’ capital	$	544,256	$	544,702	$	(518,331	)	$	570,627

Condensed Consolidated Statement of Cash Flows


	For the Nine Months Ended September 30, 2011
									Crestwood
	Crestwood			Restricted					Midstream
	Midstream			Guarantor					Partners LP
	Partners LP			Subsidiaries			Eliminations		Consolidated
				(in thousands)
Net cash (used in) provided by operating activities	$	(9,886	)	$	78,351		$	—	$	68,465

Capital expenditures		(265	)		(30,991	)		—		(31,256	)
Proceeds from exchange of plant, property and equipment		5,943			—			—		5,943
Acquisitions, net of cash acquired		—			(349,662	)		—		(349,662	)

Net cash (used in) provided by investing activities		5,678			(380,653	)		—		(374,975	)

Proceeds from Senior Notes		200,000			—			—		200,000
Proceeds from Credit Facility		100,200			—			—		100,200
Repayments of Credit Facility		(155,704	)		—			—		(155,704	)
Debt issuance costs paid		(6,982	)		—			—		(6,982	)
Proceeds from issuance of equity		206,221			—			—		206,221
Contributions by other partners		8,741			—			—		8,741
Distributions to unitholders		(45,910	)		—			—		(45,910	)
Advances to Affiliates		38,290			(38,290	)		—		—

Net cash (used in) provided by financing activities		344,856			(38,290	)		—		306,566

Net cash increase (decrease)		340,648			(340,592	)		—		56
Cash and cash equivalents at beginning of period		2			—			—		2

Cash and cash equivalents at end of period	$	340,650		$	(340,592	)	$	—	$	58


	For the Nine Months Ended September 30, 2010
									Crestwood
	Crestwood			Restricted					Midstream
	Midstream			Guarantor					Partners LP
	Partners LP			Subsidiaries			Eliminations		Consolidated
				(in thousands)
Net cash (used in) provided by operating activities	$	(4,989	)	$	49,862		$	—	$	44,873

Capital expenditures		—			(52,470	)		—		(52,470	)
Distributions to Quicksilver for Alliance Midstream Assets		—			(80,276	)		—		(80,276	)

Net cash used in investing activities		—			(132,746	)		—		(132,746	)

Proceeds from Credit Facility		143,200			—			—		143,200
Repayments of Credit Facility		(30,100	)		—			—		(30,100	)
Proceeds from issuance of equity		11,088			—			—		11,088
Equity issuance cost paid		(34	)		—			—		(34	)
Distributions to unitholders		(35,826	)		—			—		(35,826	)
Taxes paid for equity-based compensation vesting		(1,144	)		—			—		(1,144	)
Advances to Affiliates		123,741			(123,741	)				—

Net cash (used in) provided by financing activities		210,925			(123,741	)		—		87,184

Net cash increase (decrease)		205,936			(206,625	)		—		(689	)
Cash and cash equivalents at beginning of period		746			—					746

Cash and cash equivalents at end of period	$	206,682		$	(206,625	)	$	—	$	57

17. SEGMENT INFORMATION

Our operations include three reportable operating segments. These operating segments reflect the way we manage our operations. We evaluate the performance of our operating segments based on EBITDA. Our business segments reflect the primary geographic areas in which we operate and consist of the Barnett Shale, the Fayetteville Shale and the Granite Wash. Each of our business segments are engaged in the gathering, compression, processing and treating of natural gas and delivery of NGLs.

The following tables summarize the reportable segment data for the three and nine months ended September 30, 2011 and September 30, 2010:


	Three Months Ended September 30, 2011
	Barnett		Fayetteville			Granite
	Shale		Shale			Wash		Corporate			Total
	(In thousands)
Revenue	$	3,836	$	7,081		$	12,675	$	—		$	23,592
Revenue — related party		35,023		—			—		—			35,023

Total revenues	$	38,859	$	7,081		$	12,675	$	—		$	58,615

Operations and maintenance expense		6,109		3,965			499		—			10,573
Product purchases		1,764		454			11,264		—			13,482
General and administrative expense		—		—			—		5,566			5,566
Gain from exchange of property, plant and equipment		—		—			—		1,106			1,106

EBITDA		30,986		2,662			912		(4,460	)		30,100
Depreciation, amortization and accretion expense		6,185		2,895			508		7			9,595

Operating income (loss)	$	24,801	$	(233	)	$	404	$	(4,467	)	$	20,505

Goodwill	$	—	$	76,767		$	16,861	$	—		$	93,628
Total assets	$	556,399	$	296,771		$	73,156	$	18,536		$	944,862
Capital Expenditures	$	3,876	$	9,806		$	421	$	265		$	14,368


	Three Months Ended September 30, 2010
	Barnett		Fayetteville		Granite
	Shale		Shale		Wash		Corporate			Total
	(In thousands)
Revenue	$	2,324	$	—	$	—	$	—		$	2,324
Revenue — related party		28,042		—		—		—			28,042

Total revenues	$	30,366	$	—	$	—	$	—		$	30,366
Operations and maintenance expense		6,564		—		—		—			6,564
General and administrative expense		—		—		—		2,652			2,652

EBITDA		23,802		—		—		(2,652	)		21,150
Depreciation, amortization and accretion expense		5,689		—		—		—			5,689

Operating income (loss)	$	18,113	$	—	$	—	$	(2,652	)	$	15,461

Total assets	$	528,845	$	—	$	—	$	670		$	529,515
Capital Expenditures	$	17,625	$	—	$	—	$	—		$	17,625


	Nine Months Ended September 30, 2011
	Barnett		Fayetteville		Granite
	Shale		Shale⁽¹⁾		Wash⁽¹⁾		Corporate			Total
	(In thousands)
Revenue	$	9,727	$	14,164	$	25,210	$	—		$	49,101
Revenue — related party		97,429		—		—		—			97,429

Total revenues	$	107,156	$	14,164	$	25,210	$	—		$	146,530

Operations and maintenance expense		18,811		6,356		998		—			26,165
Product purchases		3,259		1,012		21,739		—			26,010
General and administrative expense		—		—		—		17,996			17,996
Gain from exchange of property, plant and equipment		—		—		—		1,106			1,106

EBITDA		85,086		6,796		2,473		(16,890	)		77,465
Depreciation, amortization and accretion expense		18,459		4,604		900		18			23,981

Operating income (loss)	$	66,627	$	2,192	$	1,573	$	(16,908	)	$	53,484

Goodwill	$	—	$	76,767	$	16,861	$	—		$	93,628
Total assets	$	556,399	$	296,771	$	73,156	$	18,536		$	944,862
Capital Expenditures	$	15,696	$	12,134	$	3,161	$	265		$	31,256


⁽¹⁾		Includes six months of operating income for Fayetteville and Granite Wash, from April 1, 2011 to September 30, 2011, subsequent to acquisition.


	Nine Months Ended September 30, 2010
	Barnett		Fayetteville		Granite
	Shale		Shale		Wash		Corporate			Total
	(In thousands)
Revenue	$	6,210	$	—	$	—	$	—		$	6,210
Revenue — related party		76,089		—		—		—			76,089

Total revenues	$	82,299	$	—	$	—	$	—		$	82,299
Operations and maintenance expense		19,979		—		—		—			19,979
General and administrative expense		—		—		—		8,112			8,112

EBITDA		62,320		—		—		(8,112	)		54,208
Depreciation, amortization and accretion expense		16,696		—		—		—			16,696

Operating income (loss)	$	45,624	$	—	$	—	$	(8,112	)	$	37,512


Total assets	$	528,845	$	—	$	—	$	670		$	529,515
Capital Expenditures	$	52,470	$	—	$	—	$	—		$	52,470

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

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with our condensed consolidated interim financial statements, and notes thereto, and the other financial data included elsewhere in this Quarterly Report. The following discussion should also be read in conjunction with our audited consolidated financial statements, and notes thereto, and “Management’s Discussion and Analysis of Financial Condition and Results of Operations” included in our 2010 Annual Report on Form 10-K.

Overview

We are a growth-oriented publicly traded Delaware master limited partnership engaged in gathering, compression, processing and treating of natural gas and delivery of NGLs produced in the Barnett Shale, Fayetteville Shale, Avalon Shale and in Granite Wash. We began operations in 2004 to provide midstream services primarily to Quicksilver as well as to other natural gas producers in the Barnett Shale. During the quarter and nine months ended September 30, 2011, Quicksilver accounted for 60% and 66%, respectively of our total revenue. Approximately 6% of our revenue for the nine months ended September 30, 2011 are comprised of natural gas purchased by Quicksilver from Eni SpA and gathered under Quicksilver’s Alliance System gathering agreement.

Our Operations

Our results of operations are significantly influenced by the volumes of natural gas gathered and processed through our systems. We gather, process, compress and treat natural gas pursuant primarily to long term, fixed fee-based contracts. However, a prolonged low commodity price environment could result in our customers reducing their production volumes which would cause a decrease in our revenue. All of our natural gas volumes gathered and processed in the Barnett Shale, Fayetteville Shale, Avalon Shale and Granite Wash during the three and nine months ended September 30, 2011 were subject to a mixture of percent-of-proceeds and fee-based contracts.

Operational Measurement

Our Management uses a variety of financial and operational measures to analyze our performance. We view these measures as important factors affecting our profitability and unitholder value and therefore we review them monthly for consistency and to identify trends in our operations. These performance measures are outlined below:

Volume— We must continually obtain new supplies of natural gas to maintain or increase throughput volumes on our gathering and processing systems. We routinely monitor producer activity in the areas we serve to identify new supply opportunities. Our ability to achieve these objectives is impacted by:

	•		the level of successful drilling and production activity in areas where our systems are located;

	•		our ability to compete with other midstream companies for production volumes; and

	•		our pursuit of new opportunities.

Operating Expenses— We consider operating expenses in evaluating the performance of our operations. These expenses are comprised primarily of direct labor, insurance, property taxes, repair and maintenance expense, utilities and contract services, and are largely independent of the volumes through our systems, but may fluctuate depending on the scale of our operations during a specific period. Our ability to manage operating expenses has a significant impact on our profitability and ability to pay distributions.

EBITDA— We believe that EBITDA is a widely accepted financial indicator of a company’s operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. EBITDA is not a measure calculated in accordance with GAAP, as it does not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA calculations may vary among entities, so our computation may not be comparable to EBITDA measures of other entities. In evaluating EBITDA, we believe that investors should also consider, among other things, the amount by which EBITDA exceeds interest costs, how EBITDA compares to principal payments on debt and how EBITDA compares to capital expenditures for each period. A reconciliation of EBITDA to amounts reported under GAAP is presented in “Results of Operations.”

EBITDA is also used as a supplemental performance measure by our Management and by external users of our financial statements such as investors, commercial banks, research analysts and others, to assess:

•

financial performance of our assets without regard to financing methods, capital structure or historical cost basis;

•

our operating performance as compared to those of other companies in the midstream industry without regard to financing methods, capital structure or historical cost basis; and

•

the viability of acquisitions and capital expenditure projects and the rates of return on investment opportunities.

ADJUSTED EBITDA —We define adjusted EBITDA as net income from continuing operations plus, interest expense, provision for income taxes, depreciation, amortization and accretion expense and non-recurring expenses. Adjusted EBITDA is commonly used as a supplemental financial measure by senior management and by external users of our financial statements, such as investors, research analysts and rating agencies, to assess the financial performance of our assets without regard to financing methods, capital structures or historical cost basis. A reconciliation of adjusted EBITDA to amounts reported under GAAP is presented in “Results of Operations.”

2011 Developments

Las Animas Acquisition- Effective February 1, 2011, we acquired approximately 46 miles of natural gas gathering pipelines near the emerging Avalon Shale and Bone Spring trends in Southeastern New Mexico for $5.1 million. The pipelines are supported by long-term, fixed-fee contracts which include existing Morrow/Atoka production and dedications of approximately 55,000 acres.

Bridge Loans-In February 2011, in connection with the Frontier Gas Acquisition, we obtained commitments from multiple lenders for senior unsecured bridge loans in an aggregate amount up to $200 million. On April 1, 2011, the commitment was not drawn and was terminated in connection with the closing of the Senior Notes described below. We recognized $2.5 million of commitment fees in the second quarter of 2011, which is included in interest expense, related to the bridge loans.

Frontier Gas Acquisition —On April 1, 2011, we completed the Frontier Gas Acquisition for a purchase price of approximately $338 million. The $338 million purchase price paid at closing was financed through a combination of equity and debt as described in Notes 4 and 7 to our condensed consolidated interim financial statements in this Quarterly Report.

The Fayetteville Shale System, located in Arkansas, consists of approximately 127 miles of high pressure and low pressure gathering pipelines with capacity of approximately 510 MMcfd, treating capacity of approximately 165 MMcfd and approximately 35,000 hp of compression. The Fayetteville Shale System which interconnects with multiple interstate pipelines are supported by long-term, fixed-fee contracts with producers who have dedicated approximately 100,000 acres in the core of the Fayetteville Shale System to Frontier. These contracts have initial terms that extend through 2020 with a five year extension.

The Granite Wash System, located in the Texas Panhandle, consist of a 28 mile pipeline system and a 36 MMcfd natural gas processing unit. This area has emerged as a highly economic liquids-rich natural gas play with active drilling programs and the Granite Wash System is supported by long-term contracts. We have made progress payments for a delivery of a second processing plant with 60 MMcfd of capacity to support growth in volumes from this region.

With the completion of the Frontier Gas Acquisition, we own and/or operate over 700 miles of natural gas gathering pipelines, and NGL, gas lift, residue and production lines.

Class C Units —On April 1, 2011, we issued 6,243,000 Class C units, representing limited partner interests, in a private placement. The negotiated purchase price for the Class C units was $24.50 per unit, resulting in net proceeds to us of approximately $153 million which was used to finance a portion of our Frontier Gas Acquisition. The Class C units are substantially similar in all respects to our existing common units, representing limited partner interests, except that we can elect to pay distributions for our Class C units through the issuance of additional Class C units or cash. The Class C units will convert into common units on a one-for-one basis on April 1, 2013.

In connection with the issuance of the Class C units, our General Partner made an additional capital contribution of $8.7 million to us in exchange for an additional 293,948 general partner units, increasing the General Partner interest to 2%.

Senior Notes —On April 1, 2011, we issued the Senior Notes. Our obligations under the Senior Notes are guaranteed on an unsecured basis by our current and future domestic subsidiaries. The proceeds were used to partially finance the Frontier Gas Acquisition. The Senior Notes accrue interest at a rate of 7.75% per annum, and are payable in cash semi-annually in arrears on April 1 and October 1 of each year, commencing on October 1, 2011, and mature April 2019.

Joinder Agreement to Credit Facility —On April 1, 2011, we entered into a Joinder Agreement with certain lenders under our Credit Facility, which expanded our borrowing capacity from $400 million to $500 million.

Offering of Common Units —On May 4, 2011, we completed a public offering of 1,800,000 common units, representing limited partner interests, under an existing shelf registration statement at a price of $30.65 per common unit ($29.75 per common unit, net of underwriting discounts and commissions), providing net proceeds of approximately $53 million. The net proceeds from the offering were used to reduce indebtedness under our Credit Facility and for general partnership purposes. In connection with the issuance of the common units, our General Partner did not make an additional capital contribution resulting in a reduction of our General Partner’s interest to approximately 1.9%.

Tristate Acquisition- On November 1, 2011, we acquired Tristate from affiliates of Energy Spectrum Capital, Zwolle Pipeline, LLC and the Tristate management for $65 million of cash paid at closing and a deferred payment of approximately $8 million one year following the closing date, subject to customary post-closing adjustments. Tristate owns the Sabine System which consists of approximately 61 miles of high-pressure natural gas gathering pipelines located in Sabine Parish, Louisiana. The Sabine System provides gathering and treating services for Haynesville and Bossier Shale production from the Toledo Bend South field area for redelivery to Gulf South Pipeline and Tennessee Gas Pipeline. We have contracts on the Sabine System with multiple producers with dedications of approximately 20,000 acres under long term, fixed-fee arrangements. The acquisition was financed with borrowings under our Credit Facility.

RESULTS OF OPERATIONS

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

The following discussion compares the results of operations for the three months ended September 30, 2011 to the three months ended September 30, 2010, which we refer to as the 2011 quarter and the 2010 quarter, respectively.


	Three Months Ended September 30,
	2011			2010
	(In thousands)
Total revenues	$	58,615		$	30,366
Operations and maintenance expense		10,573			6,564
Product purchases		13,482			—
General and administrative expense		5,566			2,652
Gain from exchange of property, plant and equipment		1,106			—

EBITDA		30,100			21,150
Non-recurring expenses		129			—
Gain from exchange of property, plant and equipment		(1,106	)		—

Adjusted EBITDA		29,123			21,150
Depreciation, amortization and accretion expense		9,595			5,689
Interest expense		7,100			3,185
Income tax provision		347			45

Net income	$	13,058		$	12,231

The following table summarizes our volumes:


	Gathering				Processing
	2011		2010		2011		2010
			(MMcf)
Barnett Shale		47,678		33,391		11,975		12,339
Fayetteville Shale		7,813		—		—		—
Granite Wash		1,473		—		1,475		—


Total		56,964		33,391		13,450		12,339

The following table summarizes our revenue:


	Gathering				Processing				Product Sales				Total
	2011		2010		2011		2010		2011		2010		2011		2010
							(In thousands)
Barnett Shale	$	29,200	$	22,380	$	7,842	$	7,986	$	1,817	$	—	$	38,859	$	30,366
Fayetteville Shale		6,534		—		—		—		547		—		7,081		—
Granite Wash		113		—		33		—		12,529		—		12,675		—


Total	$	35,847	$	22,380	$	7,875	$	7,986	$	14,893	$	—	$	58,615	$	30,366

The following table summarizes our operations and maintenance expense:


	Three Months Ended September 30,
	2011		2010
	(In thousands)
Barnett Shale	$	6,109	$	6,564
Fayetteville Shale		3,965		—
Granite Wash		499		—

	$	10,573	$	6,564

Total RevenueandVolumes —Revenues related to the Fayetteville Shale totaled $7.1 million. Revenues related to the Granite Wash totaled $12.6 million primarily related to product sales to third parties. The increase in revenue related to the Barnett Shale was $8.5 million due to increased volumes primarily in the Alliance System of the Fort Worth Basin.

Operations and Maintenance Expense —The increase in operations and maintenance expense of $4.0 million was primarily attributable to the Frontier Gas Acquisition, partially offset by lower costs in the Barnett Shale due to lower head count and lower operation costs at the facilities.

Product purchases —The increase in product purchases of $13.5 million was due primarily to the cost of gas purchased from local producers under percent-of-proceeds contracts, primarily related to Granite Wash.

General and Administrative Expense —The increase in general and administrative expense of $2.9 million was primarily due to an increase in compensation and benefits costs, costs of a new corporate location and costs related to professional services. General and administrative expense included $0.2 million and $0.7 million of equity-based compensation expense for the quarters ended September 30, 2011 and 2010, respectively.

Gain from exchange of property, plant and equipment —The gain from exchange of property, plant and equipment was due to an agreement with PVR Midstream, LLC, (“PVR”) on August 18, 2011, to exchange the delivery of certain processing plants that were under contract with Exterran Energy Solutions, L.P. resulting in proceeds of $5.9 million and a gain of $1.1 million. Our original plant was delivered to PVR during the third quarter 2011, and our new plant is scheduled to be received by the second quarter of 2012. We continue to make progress payments on our new plant.

EBITDA —EBITDA increased primarily as a result of the increase in revenues described above. As a percentage of revenue, EBITDA decreased from 70% of revenues in the 2010 quarter to 51% in the 2011 quarter. Increased revenues and expenses include product sales and product purchases primarily related to Granite Wash, which decreased EBITDA as a percent of revenue. Barnett Shale’s EBITDA increased from 78% to 80% of revenues was primarily due to higher revenues offset by product purchases. Fayetteville Shale’s EBITDA was 38% and Granite Wash’s EBITDA was 7% of revenue for the 2011 quarter.

Depreciation, Amortization and Accretion Expense —Depreciation, amortization and accretion expense increased primarily as a result of the Frontier Gas Acquisition and the continuing expansion of our Barnett Shale asset base. Fayetteville Shale and Granite Wash contributed $2.9 million and $0.5 million, respectively, to depreciation, amortization and accretion expense.

Interest Expense— Interest expense increased primarily due to the increases in the borrowings under our Credit Facility, which were principally used to fund capital projects and the addition of the Senior Notes. These increases were partially offset by the termination of the subordinated note in October 2010.

The following table summarizes the details of interest expense for the three months ended September 30, 2011 and 2010.


	Three Months Ended September 30,
	2011			2010
	(In thousands)
Interest:
Revolving Credit Facility	$	3,089		$	2,527
Senior Notes		4,005			—
Capital lease interest		60			—
Subordinated note		—			658

Total		7,154			3,185
Less interest capitalized		(54	)		—

Interest expense	$	7,100		$	3,185

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

The following discussion compares the results of operations for the nine months ended September 30, 2011 to the nine months ended September 30, 2010, which we refer to as the 2011 period and the 2010 period, respectively.


	Nine Months Ended September 30,
	2011			2010
	(In thousands)
Total revenues	$	146,530		$	82,299
Operations and maintenance expense		26,165			19,979
Product purchases		26,010			—
General and administrative expense		17,996			8,112
Gain from exchange of property, plant and equipment		1,106			—

EBITDA		77,465			54,208
Non-recurring expenses		3,166			—
Gain from exchange of property, plant and equipment		(1,106	)		—

Adjusted EBITDA		79,525			54,208

Depreciation, amortization and accretion expense		23,981			16,696
Interest expense		19,925			8,808
Income tax provision		898			171

Net income	$	32,661		$	28,533

The following table summarizes our volumes:


	Gathering				Processing
	2011		2010		2011		2010
			(MMcf)
Barnett Shale		129,126		88,797		36,028		35,076
Fayetteville Shale		15,146		—		—		—
Granite Wash		3,011		—		2,941		—


Total		147,283		88,797		38,969		35,076

The following table summarizes our revenue:


	Gathering				Processing				Product Sales				Total
	2011		2010		2011		2010		2011		2010		2011		2010
							(In thousands)
Barnett Shale	$	80,311	$	59,629	$	23,552	$	22,670	$	3,293	$	—	$	107,156	$	82,299
Fayetteville Shale		13,095		—		—		—		1,069		—		14,164		—
Granite Wash		208		—		38		—		24,964		—		25,210		—


Total	$	93,614	$	59,629	$	23,590	$	22,670	$	29,326	$	—	$	146,530	$	82,299

The following table summarizes our operations and maintenance expense:


	Nine Months Ended September 30,
	2011		2010
	(In thousands)
Barnett Shale	$	18,811	$	19,979
Fayetteville Shale		6,356		—
Granite Wash		998		—

	$	26,165	$	19,979

Total RevenueandVolumes —Operations related to the Fayetteville Shale contributed $14.2 million to gathering revenue. Operations related to Granite Wash contributed $25.2 million to revenue primarily related to product sales to third parties. The increase in revenue related to the Barnett Shale was $24.8 million due to increased volumes on all the systems.

Operations and Maintenance Expense —The increase in operations and maintenance expense of $6.2 million was primarily attributable to the Frontier Gas Acquisition, partially offset by lower costs in the Barnett Shale due to lower head count and lower operation costs at the facilities.

Product purchases —The increase in product purchases of $26.0 million was due primarily to the cost of gas purchased from local producers under percent-of-proceeds contracts, primarily related to Granite Wash.

General and Administrative Expense —The increase in general and administrative expense of $9.9 million was primarily due to transaction costs associated with the Frontier Gas Acquisition, an increase in compensation and benefits costs, costs of a new corporate location, costs related to professional services and transition costs related to the transition services agreement with Quicksilver, which expired March 31, 2011. Transaction costs related to the Crestwood Transaction and Frontier Gas Acquisition amounted to approximately $3.2 million for the 2011 period. General and administrative expense included $0.6 million and $2.0 million of equity-based compensation expense for the periods ended September 30, 2011 and 2010, respectively.

Gain from exchange of property, plant and equipment —The gain from exchange of property, plant and equipment was due to an agreement with PVR on August 18, 2011, to exchange the delivery of certain processing plants that were under contract with Exterran Energy Solutions, L.P. resulting in proceeds of $5.9 million and a gain of $1.1 million. Our original plant was delivered to PVR during the third quarter 2011, and our new plant is scheduled to be received by the second quarter of 2012. We continue to make progress payments on our new plant.

EBITDA —EBITDA increased primarily as a result of the increase in revenues described above. As a percentage of revenue, EBITDA decreased from 66% of revenues in the 2010 period to 53% in the 2011 period. Increased revenues and expenses include product sales and product purchases primarily related to Granite Wash, which decreases EBITDA as a percent of revenue. Barnett Shale’s EBITDA increased from 76% to 79% of revenues was primarily due to higher revenues offset by product purchases. Fayetteville Shale’s EBITDA was 48% and Granite Wash’s EBITDA 10% of revenue for the 2011 period.

Depreciation, Amortization and Accretion Expense —Depreciation, amortization and accretion expense increased primarily as a result of the Frontier Gas Acquisition and the continuing expansion of our Barnett Shale asset base. Fayetteville Shale and Granite Wash contributed $4.6 million and $0.9 million, respectively, to depreciation, amortization and accretion expense.

Interest Expense— Interest expense increased primarily due to the increases in the borrowings under our Credit Facility, which were principally used to fund capital projects, the addition of the Senior Notes and expenses related to the bridge loans commitments. These increases were partially offset by the termination of the subordinated note in October 2010.

The following table summarizes the details of interest expense for the nine months ended September 30, 2011 and 2010.


	Nine Months Ended September 30,
	2011			2010
	(In thousands)
Interest cost:
Revolving Credit Facility	$	9,325		$	6,917
Senior Notes		8,097			—
Bridge Loan		2,500			—
Capital lease interest		125			—
Subordinated note		—			1,891

Total cost		20,047			8,808
Less interest capitalized		(122	)		—

Interest expense	$	19,925		$	8,808

Liquidity and Capital Resources

Our sources of liquidity include:

•

cash generated from operations;

•

borrowings under our Credit Facility; and

•

future capital market transactions.

We believe that the cash generated from these sources will be sufficient to meet our expected $0.48 per unit quarterly cash distributions during 2011 and satisfy our short-term working capital and maintenance capital expenditure requirements.

Since the inception of operations in 2004, our cash flows have been significantly influenced by Quicksilver’s production in the Barnett Shale. As Quicksilver and others have developed the Barnett Shale, we have expanded our gathering and processing facilities to serve the additional volumes produced by such development. We expect to benefit from the Frontier Gas Acquisition and the acquisition of Tristate which will result in lower dependency on Quicksilver and our Barnett Shale operations. During the quarter ended September 30, 2011, Quicksilver accounted for 60% of our total revenue, which has decreased approximately 32% from 92% in the third quarter of 2010.

Known Trends and Uncertainties

Our financial condition and results of operations, including our liquidity and profitability, can be significantly affected by the following:

	•		natural gas prices;

	•		dependency on Quicksilver and the Barnett Shale; and

	•		regulatory requirements.

The volumes of natural gas that we gather and process are dependent upon the natural gas volumes produced by our customers, which may be affected by prevailing natural gas prices, their derivative programs, and the availability and cost of their capital. We cannot predict future changes to natural gas prices or how any such pricing changes will influence producers’ behaviors. If reduced drilling and development programs were to be sustained over a prolonged period of time, we could experience a reduction in volumes through our systems and therefore reductions of revenue and cash flows.

For the nine months ended September 30, 2011, approximately 73% of our revenue was derived from our operations in the Barnett Shale, including approximately 66% associated with Quicksilver. The risk of revenue fluctuations in the near-term is somewhat mitigated by the use of predominantly fixed-fee contracts for providing gathering and processing and treating services to our customers, but we are still susceptible to volume fluctuations. While the Frontier Gas Acquisition and the acquisition of Tristate reduce the concentration risk associated with our dependency on one producer and one geographic area, we continue to regularly review opportunities for both organic growth projects and acquisitions in other producing basins and with other producers.

We are subject to environmental laws, regulations and permits, including greenhouse gas requirements that may expose us to significant costs or obligations. In general, these laws, regulations, and permits have become more stringent over time and are subject to further changes and could materially affect our financial condition and results of operations in the future.

Significant Economic Factors That Impact our Business

Changes in natural gas supply such as new discoveries of natural gas reserves, declining production in older fields and the introduction of new sources of natural gas supply, such as non-conventional and emerging natural gas shale plays, affect the demand from producers for our services. As these supply dynamics change, we anticipate that we will actively pursue projects that will allow us to provide midstream services to producers associated with the growth of new sources of supply. Changes in demographics, the amount of natural gas fired power generation, liquefied natural gas imports and exports and shifts in industrial and residential usage affect the overall demand for natural gas.

We believe that the key factors that impact our business are natural gas prices, our customers’ drilling and completion activities, and government regulation on natural gas pipelines. These key factors play an important role in how we evaluate our operations and implement our long-term strategies.

Cash Flows


	Nine Months Ended June 30,
	2011			2010
	(In thousands)
Net cash provided by operating activities	$	68,465		$	44,873
Net cash used in investing activities		(374,975	)		(132,746	)
Net cash provided by financing activities		306,566			87,184

Cash Flows Provided by Operating Activities —The increase in cash flows provided by operating activities is the result of an increase in operating income as a result of the Frontier Gas Acquisition and improved performance by our Barnett Shale operations. The income also reflects an increase in accrued expenses related to operations, ad valorem tax, interest expense and incentive compensation, partially offset by higher receivables from the Fayetteville Shale and Granite Wash operations and the gain on exchange of property, plant and equipment.

Cash Flows Used in Investing Activities —The increase in cash flows used in investing activities resulting from the Frontier and Las Animas System acquisitions were approximately $349.7 million, offset by the proceeds received with the exchange of property, plant and equipment of $5.9 million and the distribution to Quicksilver of $80.3 million related to the purchase of the Alliance Midstream Assets in the prior year. For the 2011 period, we spent $31.3 million for gathering assets and processing facilities.

Cash Flows Provided by Financing Activities —Changes in cash flows provided by financing activities during the 2011 period resulted primarily from the net borrowings under our Senior Notes and Credit Facility of $144.5 million compared with the 2010 period net borrowings of $113.1 million. This change is largely reflective of our Frontier Gas Acquisition in the 2011 period compared to the purchase of the Alliance Midstream Assets for $84.4 million in the 2010 period. We also had $206.2 million in proceeds from issuance of common and Class C units. In addition, we distributed $10.1 million more to our unitholders during the 2011 period. We have increased our distributions by 14.3% from the 2010 quarter to the 2011 quarter. In January 2010, the underwriters of our equity offering exercised their option to purchase an additional 549,200 common units, which generated proceeds of $11.1 million for which there was no comparable 2011 event.

Information regarding historical and pending cash distributions is included in Note 4 to our condensed consolidated interim financial statements included in Item 1 of Part I of this Quarterly Report.

Capital Expenditures

The midstream energy business is capital intensive, requiring significant investment for the acquisition or development of new facilities. We categorize our capital expenditures as either:

•

expansion capital expenditures, which are made to construct additional assets, expand and upgrade existing systems, or acquire additional assets; or

•

maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets and extend their useful lives.

We anticipate that we will continue to make capital expenditures to develop our gathering and processing network as Quicksilver and other producers continue to expand their development efforts in the Barnett Shale, Fayetteville Shale, Avalon Shale and the Granite Wash areas. Consequently, our ability to develop and maintain sources of funds to meet our capital requirements is critical to our ability to meet our growth objectives and to maintain our distribution levels.

For the full year of 2011, we plan capital spending to total approximately $40 to $50 million, including approximately $2 to $3 million for maintenance capital projects. The approximate $15 million reduction from previous estimates is primarily attributable to delayed timing of expenditures related to expansion projects on the Alliance System. These expenditures are currently expected to be incurred in the first half of 2012.

During the nine months ended September 30, 2011, we increased gross property, plant and equipment by $172.7 million, including $144.5 million for the Frontier Gas Acquisition, $5.1 million for the Las Animas Acquisition, expansion capital expenditures of approximately $22.0 million, $1.0 million in maintenance capital expenditures and $0.1 million in asset retirement cost.

Other Matters

We regularly review opportunities for both organic growth projects and acquisitions that will enhance our financial performance. Since we distribute all of our available cash to our unitholders, we will depend on a combination of borrowings under our Credit Facility, operating cash flows and debt or equity offerings to finance any future growth capital expenditures or acquisitions.

Debt

Credit Facility— At September 30, 2011, we had $228 million outstanding under our $500 million Credit Facility at a weighted-average interest rate of 3.6%. Our average outstanding debt was $238 million for the three months ended September 30, 2011. Note 7 to the consolidated financial statements in our 2010 Annual Report on Form 10-K contains a more complete description of our indebtedness. On April 1, 2011, we entered into a Joinder Agreement with certain lenders under our Credit Facility, which expanded our borrowing capacity from $400 million to $500 million.

Our Credit Facility requires us to maintain:

•

a ratio of our consolidated trailing 12-month EBITDA (as defined in the Credit Facility) to our net interest expense of not less than 2.5 to 1.0; and

•

a ratio of total indebtedness to consolidated trailing 12-month EBITDA of not more than 5.0 to 1.0 or not more than 5.5 to 1.0 for up to nine months following certain acquisitions.

As of September 30, 2011, we were in compliance with these financial covenants. The Credit Facility contains provisions that trigger an acceleration of indebtedness based solely on the occurrence of a material adverse change in our financial condition or results of operations.

Bridge Loans —In February 2011, in connection with the Frontier Gas Acquisition, we obtained commitments from multiple lenders for senior unsecured bridge loans in an aggregate amount up to $200 million. On April 1, 2011, the commitment was not drawn and was terminated in connection with the closing of the Senior Notes described below. We recognized $2.5 million of commitment fees in the second quarter of 2011, which is included in interest expense, related to the bridge loans.

Senior Notes— On April 1, 2011, we issued the Senior Notes. Our obligations under the Senior Notes are guaranteed on an unsecured basis by our current and future domestic subsidiaries. The proceeds were used to partially finance the Frontier Gas Acquisition. The Senior Notes accrue at a rate of 7.75% per annum, and are payable in cash semi-annually in arrears on April 1 and October 1 of each year, commencing on October 1, 2011, and mature April 2019.

Our Senior Notes require us to maintain a ratio of our consolidated trailing 12-month EBITDA (as defined in the senior notes indenture) to fixed charges of at least 1.75 to 1.0. As of September 30, 2011, we were in compliance with this covenant.

Contractual Obligations and Commercial Commitments

The following table summarizes our total contractual cash obligations as of September 30, 2011.


	Payments Due by Period
Contractual Obligations	Total		2011 (remaining)		2012		2013		2014		2015		Thereafter
					(In millions)
Long-term debt⁽¹⁾	$	428.0	$	—	$	—	$	—	$	—	$	228.0	$	200.0
Scheduled interest obligations⁽²⁾		148.7		5.9		23.6		23.6		23.6		21.6		50.4
Contractual obligations⁽³⁾		12.6		3.5		5.9		2.0		0.8		0.4		—
Capital lease obligations⁽⁴⁾		7.3		0.7		2.7		2.7		1.2		—		—
Asset retirement obligations⁽⁵⁾		10.8		—		—		—		—		—		10.8

Total contractual obligations	$	607.4	$	10.1	$	32.2	$	28.3	$	25.6	$	250.0	$	261.2


⁽¹⁾		As of September 30, 2011, we had $228.0 million outstanding under our Credit Facility and $200 million outstanding on our Senior Notes.

⁽²⁾		Based on our debt outstanding and interest rates in effect at September 30, 2011, we would anticipate interest payments to be approximately $8.1 million annually on our Credit Facility and $15.5 million annually on our Senior Notes. For each additional $10.0 million in borrowings on our Credit Facility, annual interest payments will increase by approximately $0.4 million. If the committed amount under our Credit Facility were to be fully utilized by year-end 2011 at interest rates in effect at September 30, 2011, we estimate that annual interest expenses would increase by approximately $9.7 million. If interest rates on our September 30, 2011 variable debt balance of $228.0 million increase or decrease by one percentage point, our annual income will decrease or increase by $2.3 million.

⁽³⁾		We lease office buildings and other property under operating leases, including a contract to purchase a second processing plant at Granite Wash.


⁽⁴⁾		We lease compressors which are accounted for as capital leases, see Note 9 to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report.

⁽⁵⁾		For more information regarding our asset retirement obligations, see Note 10 to our condensed consolidated financial statements included in Item 1 of Part I of this Quarterly Report.

Off-Balance Sheet Arrangements

We have no off-balance sheet arrangements within the definition of Item 303(a)(4) of SEC Regulation S-K.

Recently Issued Accounting Standards

The information regarding recent accounting pronouncements is included in Note 2 to our condensed consolidated interim financial statements included in Item 1 of Part I of this Quarterly Report.

Critical Accounting Estimates

Management’s discussion and analysis of financial condition and results of operations are based on our condensed consolidated interim financial statements and related footnotes contained within Item 1 of Part I of this Quarterly Report. The process of preparing financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses. Our critical accounting estimates used in the preparation of the consolidated financial statements were discussed in Item 7 in our 2010 Annual Report on Form 10-K. These critical estimates, for which no significant changes have occurred in the nine months ended September 30, 2011, include estimates and assumptions pertaining to:

•

depreciation expense for property, plant and equipment;

•

asset retirement obligations; and

•

equity-based compensation.

These estimates and assumptions are based upon what we believe is the best information available at the time of the estimates or assumptions. The estimates and assumptions could change materially as conditions within and beyond our control change. Accordingly, actual results could differ materially from those estimates.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

We have established policies and procedures for managing risk within our organization, including internal controls. The level of risk assumed by us is based on our objectives and capacity to manage risk.

Credit Risk

Our primary credit risk relates to our dependency on Quicksilver for the majority of our natural gas volumes, which causes us to be subject to the risk of nonpayment or late payment by Quicksilver for gathering and processing fees. Quicksilver’s credit ratings are below investment grade, where they may remain for the foreseeable future. Accordingly, this risk could be higher than it might be with a more creditworthy customer or with a more diversified group of customers. Unless and until we significantly diversify our customer base, we expect to continue to be subject to non-diversified risk of nonpayment or late payment of our fees. Additionally, we perform credit analysis of our customers on a regular basis pursuant to our corporate credit policy. We have not had any significant losses due to counter-party failures to perform.

Interest Rate Risk

Although our base interest rates remain low, our leverage ratios directly influence the spreads charged by lenders. The credit markets could also drive the spreads charged by lenders upward. As base rates or spreads increase, our financing costs will increase accordingly. Although this could limit our ability to raise funds in the capital markets, we expect that our competitors would face similar challenges with respect to funding acquisitions and capital projects. We are exposed to variable interest rate risk as a result of borrowings under our Credit Facility.

Item 4. Controls and Procedures

Conclusion Regarding the Effectiveness of Disclosure Controls and Procedures

Our management, including our Chief Executive Officer and our Chief Financial Officer (the “Certifying Officers”) evaluated the effectiveness of our disclosure controls and procedures as of September 30, 2011. The term “disclosure controls and procedures,” as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, as amended, or Exchange Act, means controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported, within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. In designing and evaluating the disclosure controls and procedures, management designs controls and procedures to provide reasonable assurance of achieving the desired control objectives. Based on the evaluation of our disclosure controls and procedures as of September 30, 2011, the Certifying Officers concluded that, as of such date, our disclosure controls and procedures were effective.

Subsequently, in the fourth quarter of 2011, management became aware of a deficiency in controls relating to the preparation of pro forma financial information that is required to be disclosed in Note 3 — Acquisitions — to our condensed consolidated financial statements. We have concluded that such a deficiency represented a material weakness in internal control over financial reporting. This material weakness resulted in the amendment to our Quarterly Report on Form 10-Q/A for the three months and nine months ended September 30, 2011, in order to restate the pro forma financial information. As a result of this material weakness, the Certifying Officers have revised their earlier conclusion and have now concluded that our disclosure controls and procedures were not effective as of September 30, 2011.

Remediation of Material Weakness

The Partnership is implementing additional controls related to financial reporting disclosures for acquisitions and additional review procedures by individuals with expertise in U.S. GAAP and SEC financial reporting standards.

Changes in Internal Control Over Financial Reporting

During the quarter ended September 30, 2011, we have continued to migrate our financial systems to a hosted environment. In connection with this implementation and resulting business process changes, we continue to enhance the design and documentation of our internal control processes to ensure suitable controls over our financial reporting.

There were no other changes in our internal control over financial reporting during the quarter ended September 30, 2011 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

Our operations are subject to a variety of risks and disputes normally incident to our business. As a result, we may, at any given time, be a defendant in various legal proceedings and litigation arising in the ordinary course of business. We are not currently subject to any material lawsuits or other legal proceedings that could have a material adverse effect on our results of operations, cash flows or financial condition or for which disclosure is required by Item 103 of Regulation S-K.

Ginardi v. Frontier Gas Services, LLC, et al.In May 2011, a class action lawsuit was filed in the United States District Court of the Eastern District of Arkansas against Frontier Gas Services, LLC; Chesapeake Energy Corporation, BHP Billiton Petroleum, No 4:11-cv-0420 BRW alleging that defendant’s, including Crestwood Arkansas which was served in August 2011, operations pollute the atmosphere, groundwater, and soil with allegedly harmful gases, chemicals, and compounds and the facilities creates excessive noise levels constituting trespass, nuisance and annoyance. The plaintiffs seek compensatory and punitive damages of loss of use and enjoyment of property, contamination of soil and ground water, air and atmosphere and seek future monitoring. Crestwood Arkansas has filed an answer in the matter denying liability. This case has not had, and is not expected to have, a material impact on our results of the operation or financial condition. We intend to vigorously defend against the claims.

Item 1A. Risk Factors

In addition to the other information set forth in this report, you should carefully consider the risk factor discussed below and the risk factors discussed in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2010, which could materially affect our business, results of operations and cash flows, except that the following risk factors are no longer applicable:

	•		“Our pending acquisition of Frontier may not be consummated”;

	•		“The closing of the Frontier Acquisition is not subject to a financing condition and the Bridge Loans do not backstop the equity portion of the purchase price or our equity commitments”; and

	•		“Financing the Frontier Acquisition will substantially increase our leverage. We may not be able to obtain debt financing for the acquisition on expected or acceptable terms.”

Failure to maintain effective internal control over financial reporting could have an adverse effect on our operations, financial results or unit price.

Section 404 of the Sarbanes-Oxley Act of 2002 requires companies to conduct a comprehensive evaluation of their internal control over financial reporting. To comply with this statute, we are required to document and test our internal control over financial reporting; our management is required to assess and issue a report concerning our internal control over financial reporting; and our independent registered public accounting firm is required to attest to and report on management’s assessment and the effectiveness of internal control over financial reporting.

As described in “Part I — Item 4. Controls and Procedures” of this report, our Certifying Officers concluded that as of September 30, 2011, there was a material weakness in our internal control over financial reporting and, as a result, as of that date, the Certifying Officers determined that our disclosure controls and procedures were not effective. As a result of this material weakness, errors occurred in the Partnership’s interim condensed consolidated financial statements related to presentation of pro forma financial information disclosed in the footnotes to the condensed consolidated financial statements. These errors ultimately resulted in the restatement of the Partnership’s Form 10-Q for the quarter ended September 30, 2011. Although the Partnership is implementing additional controls related to financial reporting disclosures for acquisitions and additional review procedures by individuals with expertise in U.S. GAAP and SEC financial reporting standards, the Partnership may fail to maintain effective internal control over financial reporting in the future. Failure to maintain effective internal control over financial reporting could result in investigations or sanctions by regulatory authorities, and could have a material adverse effect on investor confidence in our reported financial information, the market price of our common units could decline, we may be unable to obtain additional financing to operate and expand our business, and our business and financial condition could be harmed.

The risk factors should be carefully considered when evaluating our business and the forward-looking statements in this report. See “Forward-Looking Information” on page five of this Quarterly Report on Form 10-Q/A.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. (Removed and Reserved)

Not Applicable.

Item 5. Other Information

None.

Item 6. Exhibits:

The exhibit index is incorporated herein by reference into this quarterly report on Form 10-Q/A.

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.

Dated: December 1, 2011


	CRESTWOOD MIDSTREAM PARTNERS LP
	By:	CRESTWOOD GAS SERVICES GP LLC, its General Partner




	By:	/s/ William G. Manias
		William G. Manias
		Senior Vice President — Chief Financial Officer

EXHIBIT INDEX

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


Exhibit No.		Description
**10.1		Separation Agreement and Release, dated October 29, 2011, by and among Crestwood Midstream Partners, LP, Crestwood Gas Services GP. LLC, Crestwood Holdings Partners, LLC, Crestwood Midstream Partners II, LLC and Terry L. Morrison (incorporated by reference herein to Exhibit 10.1 to the Company’s Current Report on Form 8-K filed on November 1, 2011).

*31.1		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*31.2		Certification Pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

*32.1		Certification Pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

**101.INS		XBRL Instance Document

**101.SCH		XBRL Taxonomy Extension Schema Linkbase Document

**101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

**101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

**101.LAB		XBRL Taxonomy Extension Labels Linkbase Document

**101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

Crestwood Midstream Partners Inactive 10-Q/A2011 Q3 Quarterly report (amended)

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