Crestwood Midstream Partners 10-Q 2012 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2012

or

¨ 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	56-2639586
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
700 Louisiana Street, Suite 2060 Houston, Texas	77002
(Address of principal executive offices)	(Zip Code)

(832) 519-2200

(Registrant’s telephone number, including area code)

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

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

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

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨  (Do not check if smaller reporting company)	Smaller Reporting company	¨

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

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 November 2, 2012
Common Units	41,162,787
Class C Units	6,991,589

CRESTWOOD MIDSTREAM PARTNERS LP

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1.     Financial Statements
Consolidated Statements of Income for the three and nine months ended September 30, 2012 and 2011	4
Consolidated Balance Sheets as of September 30, 2012 and December 31, 2011	5
Consolidated Statements of Cash Flows for the nine months ended September 30, 2012 and 2011	6
Consolidated Statements of Changes in Partners’ Capital for the nine months ended September  30, 2012 and 2011	7
Notes to Consolidated Financial Statements	8
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	36
Item 1A.  Risk Factors	36
Item 2.     Unregistered Sales of Equity Securities and Use of Proceeds	37
Item 3.     Defaults Upon Senior Securities	37
Item 4.     Mine Safety Disclosures	37
Item 5.     Other Information	37
Item 6.     Exhibits	37
Signatures	38
Exhibits	39

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FORWARD-LOOKING INFORMATION

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 consolidated subsidiaries.

Certain statements contained in this report and other materials we file with the U.S. Securities and Exchange Commission (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.

Important factors that could cause our actual results to differ materially from the results contemplated by such forward-looking statements include, but are not limited to, the following risks and uncertainties:

• changes in general economic conditions;

• fluctuations in oil, natural gas and NGL prices;

• the extent and success of drilling efforts, as well as the extent and quality of natural gas volumes produced within proximity of our assets;

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

• competitive conditions in our industry and their impact on our ability to connect natural gas supplies to our gathering and processing assets or systems;

• 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 the acquired businesses, realize any cost savings and other synergies from any acquisition;

• changes in the availability and cost of capital;

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

• timely receipt of necessary government approvals and permits, our ability to control the costs of construction, including costs of materials, labor and right-of-way and other factors that may impact our ability to complete projects within budget and on schedule;

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

• the effects of future litigation;

• risks related to our substantial indebtedness; and

• certain factors discussed elsewhere in this report.

These factors do not necessarily include all of the important factors that could cause actual results to differ materially from those expressed in any of our forward-looking statements. Other factors could also have material adverse effects on future results. Consequently, all of the forward-looking statements made in this document are qualified by these cautionary statements, and we cannot assure you that actual results or developments that we anticipate will be realized or, even if substantially realized, will have the expected consequences to, or effect on, us or our business or operations. Also note that we provided additional cautionary discussion of risks and uncertainties under “Risk Factors” in our 2011 Annual Report on Form 10-K, our quarterly reports on Form 10-Q and in our other public filings and press releases. Although the expectations in the forward-looking statements are based on our current beliefs and expectations, caution should be taken not to place undue reliance on any such forward-looking statements because such statements speak only as of the date hereof. Except as required by federal and state securities laws, we undertake no obligation to publicly update or revise any forward-looking statements, whether as a result of new information, future events or otherwise. All forward-looking statements attributable to us or any person acting on our behalf are expressly qualified in their entirety by the cautionary statements contained or referred to in this report and in our future periodic reports filed with the SEC. In light of these risks, uncertainties and assumptions, the forward-looking events discussed in this report may not occur.

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF INCOME

(In thousands, except for per unit data)

(Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Operating revenues
Gathering revenue—related party	$	21,658		$	27,840		$	67,120		$	75,706
Gathering revenue		13,739			8,007			36,310			17,908
Processing revenue—related party		6,298			7,183			19,619			21,723
Processing revenue		2,271			692			4,665			1,867
Product sales		11,071			14,893			29,258			29,326
Total operating revenues		55,037			58,615			156,972			146,530
Operating expenses
Product purchases		10,341			13,482			26,755			26,010
Operations and maintenance		10,127			10,573			28,725			26,165
General and administrative		5,777			5,566			19,451			17,996
Depreciation, amortization and accretion		10,943			9,595			32,427			23,981
Total operating expenses		37,188			39,216			107,358			94,152
Gain from exchange of property, plant and equipment		—			1,106			—			1,106
Operating income		17,849			20,505			49,614			53,484
Earnings from unconsolidated affiliate		1,764			—			2,205			—
Interest and debt expense		(8,202	)		(7,100	)		(24,045	)		(19,925	)
Income before income taxes		11,411			13,405			27,774			33,559
Income tax expense		306			347			884			898
Net income	$	11,105		$	13,058		$	26,890		$	32,661
General partner’s interest in net income	$	4,240		$	2,426		$	10,944		$	4,942
Limited partners’ interest in net income	$	6,865		$	10,632		$	15,946		$	27,719
Basic income per unit:
Net income per limited partner unit	$	0.15		$	0.27		$	0.36		$	0.76
Diluted income per unit:
Net income per limited partner unit	$	0.15		$	0.27		$	0.36		$	0.76
Weighted-average number of limited partner units:
Basic		46,564			39,388			44,206			36,424
Diluted		46,767			39,504			44,395			36,540
Distributions declared per limited partner unit (attributable to the period ended)	$	0.51		$	0.48		$	1.51		$	1.38

See accompanying notes.

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CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data)

(Unaudited)

	September 30,		December 31,
	2012		2011
ASSETS
Current assets
Cash and cash equivalents	$	12	$	797
Accounts receivable—related party		22,632		27,312
Accounts receivable		14,063		11,926
Prepaid expenses and other		5,567		1,935
Total current assets		42,274		41,970
Investment in unconsolidated affiliate		129,603		—
Property, plant and equipment, net of accumulated depreciation of $116,486 in 2012 and $89,860 in 2011		785,404		746,045
Intangible assets, net of accumulated amortization of $7,342 in 2012 and $2,440 in 2011		165,839		127,760
Goodwill		95,031		93,628
Deferred financing costs, net		13,604		16,699
Other assets		694		790
Total assets	$	1,232,449	$	1,026,892
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accrued additions to property, plant and equipment	$	1,899	$	7,500
Capital leases		3,658		2,693
Accounts payable—related party		408		1,308
Accounts payable, accrued expenses and other liabilities		36,280		31,794
Total current liabilities		42,245		43,295
Long-term debt		533,200		512,500
Long-term capital leases		3,429		3,929
Asset retirement obligations		13,002		11,545
Commitments and contingent liabilities (Note 9)
Partners’ capital
Common unitholders (41,158,228 and 32,997,696 units issued and outstanding at September 30, 2012 and December 31, 2011)		462,377		286,945
Class C unitholders (6,991,589 and 6,596,635 units issued and outstanding at September 30, 2012 and December 31, 2011)		159,800		157,386
General partner		18,396		11,292
Total partners’ capital		640,573		455,623
Total liabilities and partners’ capital	$	1,232,449	$	1,026,892

See accompanying notes.

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CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Nine Months Ended
	September 30,
	2012			2011
Cash flows from operating activities
Net income	$	26,890		$	32,661
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion		32,427			23,981
Equity-based compensation		1,528			851
Amortization/accretion of deferred financing costs and capital lease obligations		3,110			2,542
Gain from exchange of property, plant and equipment		—			(1,106	)
Changes in assets and liabilities:
Accounts receivable—related party		4,680			(5,675	)
Accounts receivable		(2,137	)		(5,359	)
Prepaid expenses and other assets		783			(447	)
Accounts payable—related party		(900	)		(2,349	)
Accounts payable, accrued expenses and other liabilities		3,758			23,366
Net cash provided by operating activities		70,139			68,465
Cash flows from investing activities
Capital expenditures		(28,968	)		(31,256	)
Acquisitions, net of cash acquired		(87,269	)		(349,662	)
Proceeds from exchange of property, plant and equipment		—			5,943
Investment in unconsolidated affiliate		(131,250	)		—
Capital distributions from unconsolidated affiliate		1,647			—
Net cash used in investing activities		(245,840	)		(374,975	)
Cash flows from financing activities
Proceeds from issuance of senior notes		—			200,000
Proceeds from credit facility		350,200			100,200
Repayments of credit facility		(329,500	)		(155,704	)
Payments on capital leases		(2,155	)		—
Deferred financing costs paid		(161	)		(6,982	)
Proceeds from issuance of Class C units, net		—			152,671
Proceeds from issuance of common units, net		217,508			53,550
Contributions from partners		5,930			8,741
Distributions to partners		(66,500	)		(45,910	)
Taxes paid for equity-based compensation vesting		(406	)		—
Net cash provided by financing activities		174,916			306,566
Change in cash and cash equivalents		(785	)		56
Cash and cash equivalents at beginning of period		797			2
Cash and cash equivalents at end of period	$	12		$	58

See accompanying notes.

6

CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(In thousands)

(Unaudited)

	Limited Partners
				Class C
	Common			Unitholders		General Partner			Total
Partners’ capital as of December 31, 2011	$	286,945		$	157,386	$	11,292		$	455,623
Issuance of units, net of offering costs		217,508			—		—			217,508
Contributions from partners		—			—		5,930			5,930
Net income		13,532			2,414		10,944			26,890
Equity-based compensation		1,528			—		—			1,528
Taxes paid for equity-based compensation vesting		(406	)		—		—			(406	)
Distributions to partners		(56,730	)		—		(9,770	)		(66,500	)
Partners' capital as of September 30, 2012	$	462,377		$	159,800	$	18,396		$	640,573
	Limited Partners
				Class C
	Common			Unitholders		General Partner			Total
Partners’ capital as of December 31, 2010	$	258,069		$	—	$	684		$	258,753
Issuance of units, net of offering costs		53,550			152,671		—			206,221
Contributions from partners		—			—		8,741			8,741
Net income		24,595			3,124		4,942			32,661
Equity-based compensation		851			—		—			851
Distributions to partners		(42,309	)		—		(3,601	)		(45,910	)
Partners' capital as of September 30, 2011	$	294,756		$	155,795	$	10,766		$	461,317

See accompanying notes.

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CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization

Crestwood Midstream Partners LP (CMLP) is a publicly traded Delaware limited partnership formed for the purpose of acquiring and operating midstream assets. Crestwood Gas Services GP LLC, our general partner (General Partner), is owned by Crestwood Holdings Partners LLC and its affiliates (Crestwood Holdings). Our common units are listed on the New York Stock Exchange (NYSE) under the symbol “CMLP.”

Organizational Structure

The following chart depicts our ownership structure as of September 30, 2012:

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Our general partner and limited partner ownership interests as of September 30, 2012 is as follows:

	Crestwood
	Holdings			Public			Total
General partner interest		2.0	%		—			2.0	%
Limited partner interests:
Common unitholders		39.8	%		44.0	%		83.8	%
Class C unitholders		0.2	%		14.0	%		14.2	%
Total		42.0	%		58.0	%		100.0	%

See Note 13.Partners’ Capital and Distributions for additional information concerning ownership interests.

Description of Business

We are primarily engaged in the gathering, processing, treating, compression, transportation and sales of natural gas and the delivery of NGLs produced in the geological formations of the Barnett Shale in north Texas, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Marcellus Shale in northern West Virginia, the emerging Avalon Shale trend in southeastern New Mexico and the Haynesville/Bossier Shale in western Louisiana.

2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Basis of Presentation

We prepared this Quarterly Report on Form 10-Q under the rules and regulations of the SEC and in accordance with accounting principles generally accepted in the United States of America (GAAP) for interim consolidated financial statements. Accordingly, they do not include all of the disclosures required by GAAP and should be read along with our 2011 Annual Report on Form 10-K. The financial statements as of September 30, 2012, and for the three and nine months ended September 30, 2012 and 2011, are unaudited. The consolidated balance sheet as of December 31, 2011, was derived from the audited balance sheet filed in our 2011 Annual Report on Form 10-K. 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. In 2012, we reclassified approximately $2.7 million from goodwill to accounts receivable and other current assets to reflect the fair value of certain contracts acquired in the Frontier Gas Acquisition (as defined in Note 3.Acquisitions) that were not recorded when the purchase price allocation was finalized for the acquired assets. This reclassification had no impact on previously reported net income, earnings per unit or partners’ capital. Information for interim periods may not be indicative of our operating results for the entire year. Our disclosures in this Form 10-Q are an update to those provided in our 2011 Annual Report on Form 10-K.

Significant Accounting Policies

There were no changes in the significant accounting policies described in our 2011 Annual Report on Form 10-K, except as noted below.

Principles of Consolidation. We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We do not have ownership in any variable interest entities. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct, the policies, decisions or activities of the entity. We use the cost method of accounting where we are unable to exert significant influence over the entity.

Segment Information. We conduct all of our operations within eight operating segments, four of which are reportable. Our operating segments reflect how we manage our operations and are generally reflective of the geographic areas in which we operate. Our reportable segments consist of Barnett, Fayetteville, Granite Wash and Marcellus. Our operating segments are engaged in gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs in the United States.

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Equity Investment Impairment. The Financial Accounting Standards Board’s (FASB) accounting standards related to equity method investments and joint ventures require entities to periodically review their equity method investments to determine whether current events or circumstances indicate that the carrying value of the equity method investment may be impaired. We evaluate our equity investment for impairment when there are indicators of impairment. If indicators suggest impairment we will perform an impairment test to assess whether an adjustment is necessary. The impairment test considers whether the fair value, as determined by us, of our equity method investment has declined and if the decline is other than temporary. If the decline in fair value is determined to be other than temporary, the investment’s carrying value may be required to be written down to fair value.

New Accounting Pronouncement Issued But Not Yet Adopted

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. As of September 30, 2012, the following accounting standard had not yet been adopted by us.

In September 2011, the FASB amended the accounting literature for goodwill impairment testing. This amended guidance provides an entity with the option to first assess qualitative factors to evaluate whether it is more likely than not that the fair value of a reporting unit is less than the carry amount as the basis to determine if the two-step goodwill impairment is required. The effective date is for annual and interim goodwill tests for fiscal years beginning after December 15, 2011, and early adoption is permitted. We are evaluating the effect that this accounting standards update may have on our annual goodwill impairment test, which we complete during the fourth quarter of each year.

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3. ACQUISITIONS

2012 Acquisition

Devon Acquisition

On August 24, 2012, we completed the acquisition of certain gathering and processing assets in the NGL rich gas region of the Barnett Shale from Devon Energy Corporation (Devon) for approximately $87 million (Devon Acquisition). The assets acquired consist of a 74 mile low pressure natural gas gathering system, a cryogenic processing facility with capacity of 100 MMcf/d and 23,100 horsepower of compression equipment, and are located in Johnson County, Texas near our Cowtown gathering system. Additionally, as part of the transaction, we entered into a 20 year, fixed-fee gathering, processing and compression agreement with Devon, under which we will gather and process Devon’s natural gas production from a 20,500 acre dedication. The final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed. The preliminary purchase allocation is as follows (In thousands):

Purchase price:
Cash	$	87,269
Total purchase price	$	87,269
Preliminary purchase price allocation:
Property, plant and equipment	$	41,555
Intangible assets		46,981
Total assets	$	88,536
Asset retirement obligation	$	540
Property tax liability		527
Environmental liability		200
Total liabilities	$	1,267
Total	$	87,269

Our intangible assets recorded as a result of the Devon Acquisition relate to the 20 year fixed-fee gathering, processing and compression agreement with Devon. These intangible assets will be amortized over the life of the contract.

For the period from the acquisition date (August 24, 2012) through September 30, 2012, we recorded approximately $2 million of operating revenues and $1 million of operating expenses related to the operations of the assets acquired from Devon. We did not incur any significant non-operating income or expenses related to the acquired assets during that period. We believe that it is impracticable to present financial information for the acquired assets prior to the acquisition date due to the lack of availability of historical financial information related to the acquired assets, and because the 20 year fixed-fee gathering, processing and compression agreement with Devon has significantly different terms than the historical intercompany relationships between the acquired assets and Devon.

2011 Acquisitions

Las Animas Acquisition

On February 16, 2011, we completed the acquisition of certain midstream assets in the emerging Avalon Shale trend from a group of independent producers for approximately $5 million (Las Animas Acquisition). The Las Animas Acquisition was recorded in property, plant and equipment at fair value of approximately $5 million.

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Frontier Gas Acquisition

On April 1, 2011, we completed the acquisition of certain midstream assets in the Fayetteville Shale and the Granite Wash from Frontier Gas Services, LLC for approximately $345 million (Frontier Gas Acquisition). During the three month period ended September 30, 2011, we finalized the Frontier Gas Acquisition purchase price, which resulted in the recognition of approximately $94 million in goodwill.

Tristate Acquisition

On November 1, 2011, we acquired Tristate Sabine, LLC (Tristate) from affiliates of Energy Spectrum Capital, Zwolle Pipeline, LLC, and Tristate’s management for approximately $72 million in cash consideration comprised of $64 million paid at closing plus a deferred payment of $8 million, which we expect to pay during the fourth quarter of 2012 (Tristate Acquisition). During the three months ended September 30, 2012, we finalized our purchase price allocation for the Tristate acquisition, which resulted in the recognition of approximately $4 million in goodwill, primarily related to anticipated operating synergies between the assets acquired and our existing assets. The final purchase price allocation is as follows (In thousands):

Purchase price:
Cash	$	64,359
Deferred payment		8,000
Total purchase price	$	72,359
Purchase price allocation:
Cash	$	589
Accounts receivable		2,564
Prepaid expenses and other		364
Property, plant and equipment		55,568
Intangible assets		12,000
Goodwill		4,053
Total assets	$	75,138
Accounts payable, accrued expenses and other	$	1,915
Asset retirement obligation		864
Total liabilities	$	2,779
Total	$	72,359

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The following tables are the presentation of income for the three and nine months ended September 30, 2011 as if we had completed the Frontier Gas, Tristate and Las Animas Acquisitions on January 1, 2011 (In thousands, except per unit data):

	Three Months Ended September 30, 2011
	Crestwood
	Midstream			Proforma
	Partners LP (1)			Adjustment (2)			Combined
Operating revenues	$	58,615		$	2,886		$	61,501
Operating expenses, net of gain from exchange of property, plant and equipment		(38,110	)		(2,052	)		(40,162	)
Operating income	$	20,505		$	834		$	21,339
Basic earnings per unit:
Net income per limited partner	$	0.27					$	0.28
Diluted earnings per unit:
Net income per limited partner	$	0.27					$	0.28
Weighted-average number of limited partner units:
Basic		39,388						39,489
Diluted		39,504						39,605

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	Nine Months Ended September 30, 2011
	Crestwood Midstream Partners LP (3)			Proforma Adjustment (4)			Combined
Operating revenues	$	146,530		$	24,931		$	171,461
Operating expenses, net of gain from exchange of property, plant and equipment		(93,046	)		(22,164	)		(115,210	)
Operating income	$	53,484		$	2,767		$	56,251
Basic earnings per unit:
Net income per limited partner	$	0.76					$	0.63
Diluted earnings per unit:
Net income per limited partner	$	0.76					$	0.63
Weighted-average number of limited partner units:
Basic		36,424						38,568
Diluted		36,540						38,684

⁽¹⁾ Includes three months of operating income for the Las Animas Acquisition, three months of operating income from the Frontier Gas Acquisition and no operating income for the Tristate Acquisition.

⁽²⁾  Represents three months of operating income for the Tristate Acquisition, prior to acquisition.

⁽³⁾  Includes approximately eight months of operating income for the Las Animas Acquisition, six months of operating income from the Frontier Gas Acquisition and no operating income for the Tristate Acquisition.

⁽⁴⁾ Represents approximately one month of operating income for the Las Animas Acquisition, three months of operating income for the Frontier Gas Acquisition and nine months of operating income for the Tristate Acquisition.

4. INVESTMENT IN UNCONSOLIDATED AFFILIATE

On March 26, 2012, we invested approximately $131 million in cash in exchange for a 35% interest in Crestwood Marcellus Midstream LLC (CMM), which is held by our wholly-owned subsidiary. Crestwood Holdings owns the remaining 65% interest in CMM. We account for our investment in CMM under the equity method of accounting.

On March 26, 2012, CMM completed the acquisition of Antero Resources Appalachian Corporation’s (Antero) gathering system assets located in Harrison and Doddridge Counties, West Virginia for $375 million in cash, subject to normal purchase price adjustments (Antero Acquisition). During the three months ended September 30, 2012, CMM finalized these purchase price adjustments with Antero, which resulted in CMM owing Antero an additional $5 million, which primarily related to capital expenditures from the acquisition date (March 26, 2012) to the date the purchase price was finalized.

Antero may earn additional payments of up to $40 million based upon average annual production levels achieved during 2012, 2013 and 2014.

Additionally, CMM entered into a 20 year, fixed fee, Gas Gathering and Compression Agreement (GGA) with Antero, which provides for an area of dedication of approximately 127,000 gross acres, or 104,000 net acres, largely located in the rich gas corridor of the southwestern core of the Marcellus Shale play. We have provided guarantees to Antero of future performance by CMM under the GGA. We expect that any impact from nonperformance by CMM under the GGA would be immaterial to our consolidated financial statements. As part of the GGA, Antero committed to deliver minimum annual throughput volumes to CMM for a seven year period from January 1, 2012 to January 1, 2019, ranging from an average of 300 MMcf/d in 2012 to an average of to 450 MMcf/d in 2018.

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Concurrent with the Antero Acquisition by CMM, we entered into an operating agreement with CMM to operate its assets. The terms of the operating agreement provide for, among other things, the reimbursement of costs incurred by us on behalf of CMM in conjunction with operating CMM’s assets. For the three and nine months ended September 30, 2012, CMM reimbursed us approximately $1 million and $2 million for costs under the operating agreement which is reflected as a reduction to operating expenses in our consolidated statement of income.

Our investment in CMM totaled approximately $130 million as of September 30, 2012, which equals our respective share of CMM’s equity. The summarized financial information for our investment in CMM is as follows (In thousands):

	Three Months Ended			Nine Months Ended
	September 30,			September 30,
	2012			2012
Operating revenue	$	7,976		$	15,003
Operations and maintenance expense		815			1,328
General and administrative expense		793			2,514
Depreciation, amortization and accretion expense		625			3,482
Interest and debt expense		703			1,380
Net income	$	5,040		$	6,299
Ownership percentage		35	%		35	%
Equity earnings from CMM	$	1,764		$	2,205
Distributions:
Earnings distributions	$	1,764		$	2,205
Capital distributions		363			1,647
Total distributions to CMLP	$	2,127		$	3,852

5. NET INCOME PER LIMITED PARTNER UNIT

The following is a reconciliation of the limited partner units used in the basic and diluted earnings per unit calculations for the three and nine months ended September 30, 2012 and 2011 (In thousands, except per unit data):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Limited partners’ interest in net income	$	6,865	$	10,632	$	15,946	$	27,719
Weighted-average limited partner units—basic(1)		46,564		39,388		44,206		36,424
Effect of unvested phantom units		203		116		189		116
Weighted-average limited partner units—diluted(1)		46,767		39,504		44,395		36,540
Basic earnings per unit:
Net income per limited partner	$	0.15	$	0.27	$	0.36	$	0.76
Diluted earnings per unit:
Net income per limited partner	$	0.15	$	0.27	$	0.36	$	0.76

⁽¹⁾ Includes 6,929,763 and 6,795,130 Class C units for the three and nine months ended September 30, 2012.

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There were no units excluded from our dilutive earnings per share as we do not have any anti-dilutive units for the three and nine months ended September 30, 2012 and 2011.

6. PROPERTY, PLANT AND EQUIPMENT

On June 21, 2012, we entered into an amendment to the Memorandum of Understanding (MOU Amendment) with Mountaineer Keystone LLC (MK), which extends the term of the original MOU, including its exclusivity provisions from January 31, 2013 to January 31, 2014. The primary purpose of the MOU Amendment was to allow MK to reevaluate its drilling and development plans in the Tygart Valley area. In addition, the MOU Amendment increased MK’s obligation to reimburse us for project costs of the Tygart Valley Pipeline that we incur from a cumulative total of approximately $2 million to approximately $3 million. We have capitalized costs included in construction in progress relating to the Tygart Valley Pipeline project of approximately $3 million as of September 30, 2012.

During the three and nine months ended September 30, 2012, we recorded an impairment of approximately $1.6 million of our property, plant and equipment to write certain of our assets down to their fair value of zero (which is a Level 3 fair value measurement) as a result of a compressor building fire that occurred on September 6, 2012 at our Corvette processing plant in our Barnett Segment. This impairment, in addition to approximately $0.6 million of other operations and maintenance costs incurred related to the incident, is recoverable under our insurance policies and is recorded in Prepaid Expenses and Other current assets on our balance sheet as of September 30, 2012.

During the three months ended September 30, 2011, we recorded a gain of approximately $1 million on the exchange of property, plant and equipment under an agreement with a third party to exchange the delivery of certain processing plants that were under contract. We received proceeds of approximately $6 million on the exchange.

7. ACCOUNTS PAYABLE, ACCRUED EXPENSES AND OTHER LIABILITES

Accounts payable, accrued expenses and other liabilities consist of the following (In thousands):

	September 30,		December 31,
	2012		2011
Accrued expenses	$	6,809	$	3,175
Accrued property taxes		4,428		5,204
Accrued product purchases payable		3,334		3,594
Tax payable		1,367		1,545
Interest payable		8,222		4,788
Accounts payable		4,093		5,128
Tristate Acquisition deferred payment (Note 3)		8,000		8,000
Other		27		360
Total accounts payable, accrued expenses and other liabilities	$	36,280	$	31,794

8. LONG-TERM DEBT

Debt consists of the following (In thousands):

	September 30,		December 31,
	2012		2011
Credit Facility, due October 2015	$	333,200	$	312,500
Senior Notes, due April 2019		200,000		200,000
Long-term debt	$	533,200	$	512,500

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Credit Facility

Our senior secured credit facility, as amended (Credit Facility), allows for revolving loans, letters of credit and swingline loans in an aggregate amount of up to $500 million. On March 20, 2012, we amended our Credit Facility to permit the acquisition of an equity interest in CMM and to allow for additional investments in CMM of up to $160 million. The Credit Facility is secured by substantially all of our and our subsidiaries’ assets and is guaranteed by our wholly-owned subsidiaries.

Borrowings under the Credit Facility bear interest at the London Interbank Offered Rate (LIBOR) plus an applicable margin or a base rate as defined in the credit agreement. Under the terms of the Credit Facility, the applicable margin under LIBOR borrowings was 3.5% at September 30, 2012. The weighted-average interest rate as of September 30, 2012 was 3.73%. Our borrowings under the Credit Facility were $333 million as of September 30, 2012 and based on our results through September 30, 2012, our remaining available capacity under the Credit Facility was $167 million. For the three and nine months ended September 30, 2012, our average outstanding borrowings were $325 million and $313 million. For the three and nine months ended September 30, 2012, our maximum outstanding borrowings were $369 million and $375 million. At September 30, 2012, the carrying value of our Credit Facility approximates its fair value.

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 (as defined in the Credit Facility) 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, 2012, we were in compliance with these financial covenants.

The Credit Facility contains restrictive covenants that prohibit the declaration or payment of distributions by us if a default then exists or would result therefrom, and otherwise limits the amount of distributions that we can make. An event of default may result in the acceleration of our repayment of outstanding borrowings under the Credit Facility, the termination of the Credit Facility and foreclosure on collateral.

Senior Notes

On April 1, 2011, we issued $200 million of senior notes, which accrue interest at the rate of 7.75% per annum and mature in April 2019 (Senior Notes). Our obligations under the Senior Notes are guaranteed on an unsecured basis by our current and future domestic subsidiaries. Interest is payable semi-annually in arrears on April 1 and October 1 of each year. Our Senior Notes require us to maintain a ratio of our consolidated trailing 12-month EBITDA (as defined in the indenture governing the Senior Notes) to fixed charges of at least 1.75 to 1.0. As of September 30, 2012, we were in compliance with this covenant.

The fair value of our Senior Notes was approximately $204 million and $197 million as of September 30, 2012 and December 31, 2011. The fair value of our Senior Notes was determined using quoted market prices on the same or similar debt issuances, which is categorized as Level 2 within the fair value hierarchy.

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 terminated on April 1, 2011 in conjunction with the issuance of the Senior Notes described above. We incurred approximately $3 million of commitment fees during the nine months ended September 30, 2011, which was included in interest expense on our consolidated statement of income.

Guarantor Subsidiaries

Our consolidated subsidiaries, which are wholly-owned by us, are full and unconditional, joint and several guarantors of our Credit Facility and Senior Notes. We have no independent assets or operations.

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9. COMMITMENTS AND CONTINGENT LIABILITIES

Legal Proceedings

Bartlett Case.In December 2011, a putative class action lawsuit,George Bartlett, et al., 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, Kinder Morgan Treating LP and Crestwood Arkansas Pipeline, LLC. The lawsuit alleged that the defendants’ operations polluted the atomosphere, groundwater, and soil with allegedly harmful gases, chemicals, and compounds and the facilities created excessive noise levels constituting trespass, nuisance and annoyance.

On September 17, 2012, this case was settled and dismissed. The settlement did not have a material impact on our results of operations or financial condition.

From time to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and are incidental to our business. There are currently no such pending proceedings to which we are a party that our management believes will have a material adverse effect on our results of operations, cash flows or financial condition. However, future events or circumstances, currently unknown to management, will determine whether the resolution of any litigation or claims will ultimately have a material effect on our results of operations, cash flows or financial condition in any future reporting periods. As of September 30, 2012, we had less than $0.1 million accrued for our legal proceedings.

Regulatory Compliance

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

Environmental Compliance

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. 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, 2012, we had accrued approximately $0.2 million for environmental matters, which is based on our undiscounted estimate of amounts we will spend on environmental compliance and remediation. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures could range from approximately $0.2 million to $0.3 million. We had no accruals for environmental matters at December 31, 2011.

Operating Leases

Consolidated lease and rental expense was approximately $2 million and $6 million for the three and nine months ended September 30, 2012 and approximately $3 million and $6 million for the three and nine months ended September 30, 2011. There have been no material changes to our operating leases commitments since those reported in our 2011 Annual Report on Form 10-K.

10. 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. Accordingly, each partner is responsible for its share of federal and state income tax. Net earnings for financial statement purposes may differ significantly from taxable income reportable to each partner as a result of differences between the tax basis and financial reporting basis of assets and liabilities.

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. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax. See our 2011 Annual Report on Form 10-K for more information about our income taxes.

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11. EQUITY PLAN

Awards of phantom and restricted units have been granted under our Fourth Amended and Restated 2007 Equity Plan (2007 Equity Plan). The following table summarizes information regarding 2012 phantom and restricted unit activity:

	Payable In Cash					Payable In Units
	Units			Weighted- Average Grant Date Fair Value		Units			Weighted- Average Grant Date Fair Value
Unvested—January 1, 2012		13,346		$	26.40		128,795		$	27.22
Vested—phantom units		(3,220	)	$	27.22		(40,929	)	$	27.21
Vested—restricted units		—			—		(1,348	)	$	27.11
Issued—phantom units		—			—		126,246		$	29.90
Issued—restricted units		—			—		30,000		$	26.30
Canceled—phantom units		(767	)	$	25.63		(24,938	)	$	28.30
Unvested—September 30, 2012		9,359		$	26.19		217,826		$	28.52

As of September 30, 2012 and December 31, 2011, we had total unamortized compensation expense of approximately $4 million and $2 million related to phantom and restricted units, which we expect will be amortized over three years, the original vesting periods of these instruments, except for grants to non-employee directors of our General Partner which vest over one year. We recognized compensation expense of approximately $2 million and $1 million during the nine months ended September 30, 2012 and 2011, included in operating expenses on our consolidated statements of income. We granted phantom and restricted units with a grant date fair value of approximately $5 million during the nine months ended September 30, 2012. As of September 30, 2012, we had 512,300 units available for issuance under the 2007 Equity Plan.

Under the 2007 Equity Plan, participants who have been granted restricted units may elect to have us withhold common units to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-vested common units. Any such common units withheld are returned to the 2007 Equity Plan on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When we withhold these common units, we are required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. During the three month period ended March 31, 2012, we withheld 414 common units to satisfy employee tax withholding obligations. The withholding of common units by us could be deemed a purchase of the common units. There were no common units withheld to satisfy employee tax withholding obligations during the six months ended September 30, 2012.

See our 2011 Annual Report on Form 10-K, for a more complete description of our 2007 Equity Plan.

12. TRANSACTIONS WITH RELATED PARTIES

Omnibus Agreement— In October 2010, concurrent with Quicksilver Resources Inc.’s (Quicksilver) sale of all of its ownership interests in us to Crestwood Holdings (Crestwood Transaction), we entered into an omnibus agreement with Crestwood Holdings and our General Partner (Omnibus Agreement) that addresses the following matters:

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• restrictions on Crestwood Holdings’ ability to engage in certain midstream business activities or own certain related assets in the Hood, Somervell, Johnson, Tarrant, Hill, Parker, Bosque and Erath Counties in Texas;

• Crestwood Holdings’ obligation to indemnify us for certain liabilities and our obligation to indemnify Crestwood Holdings for certain liabilities;

• our obligation to reimburse Crestwood Holdings for all expenses incurred by Crestwood Holdings (or payments made on our behalf) in conjunction with Crestwood Holdings’ provision of general and administrative services to us, including salary and benefits of Crestwood Holdings personnel, our public company expenses, general and administrative expenses and salaries and benefits of our executive management who are Crestwood Holdings’ employees;

• our obligation to reimburse Crestwood Holdings for all insurance coverage expenses it incurs or payments it makes with respect to our assets; and

• our obligation to reimburse Crestwood Holdings for all expenses incurred by Crestwood Holdings (or payments made on our behalf) in conjunction with Crestwood Holdings’ provision of services necessary to operate, manage and maintain our assets.

Any or all of the provisions of the Omnibus Agreement are terminable by Crestwood Holdings at its option if our General Partner is removed without cause and units held by our General Partner and its affiliates are not voted in favor of that removal. The Omnibus Agreement terminates on the earlier of August 10, 2017 or at such times as Crestwood Holdings ceases to own or control a majority of the issued and outstanding voting securities of our General Partner.

We paid Crestwood Holdings approximately $5 million and $14 million during the three and nine months ended September 30, 2012 and $4 million and $12 million during the three and nine months ended September 30, 2011 to reimburse Crestwood Holdings for expenses incurred on our behalf under the Omnibus Agreement. These amounts were reflected as operating expenses on our consolidated statements of income.

Pursuant to the terms of the purchase agreement entered into with Quicksilver in connection with the Crestwood Transaction, Quicksilver is entitled to appoint a director to our General Partner’s board of directors. To date, such appointee has been an executive officer of Quicksilver, and accordingly Quicksilver is considered a related party. We have several contracts with Quicksilver, which include the following:

Gas Gathering and Processing Agreements.Quicksilver has agreed to dedicate all of the natural gas produced on properties operated by Quicksilver within the areas served by our Alliance, Cowtown, and Lake Arlington Systems through 2020. We recognized approximately $28 million and $87 million of revenue for the three and nine months ended September 30, 2012 and approximately $35 million and $97 million of revenue for the three and nine months ended September 30, 2011 under these agreements.

Alliance Pipeline Lease.We also entered into an agreement with Quicksilver to lease pipeline assets attached to the Alliance System. We recognized lease expense of $0.1 million and $0.2 million for the three and nine months ended September 30, 2012 and $0.1 million and $0.4 million for the three and nine months ended September 30, 2011 related to this agreement. As of September 30, 2012, we terminated this pipeline lease agreement.

Hill County Dry System.We operated the Hill County Dry System pursuant to an operating agreement with Quicksilver effective as of the Crestwood Transaction to October 2011. Quicksilver reimbursed us approximately $0.2 million and $0.5 million for the three and nine months ended September 30, 2011 related to this agreement.

Joint Operating Agreement.We entered into an agreement with Quicksilver for the joint development of areas governed by certain of our existing commercial agreements. Quicksilver reimbursed us approximately $0.2 million and $0.7 million for the three and nine months ended September 30, 2012 and $0.3 million and $0.8 million for the three and nine months ended September 30, 2011 for services rendered related to this agreement.

Other Agreements. During 2010, we entered in an agreement with Quicksilver to lease office space in Glen Rose, Texas. We recognized lease expense of less than $0.1 million for the three and nine months ended September 30, 2012 and 2011 related to this agreement.

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13. PARTNERS’ CAPITAL AND DISTRIBUTIONS

Issuance of Units and Contributions. During 2012, we completed public offerings of common units, representing limited partner interests. The net proceeds from these offerings were used to reduce indebtedness under our Credit Facility. The following table presents our common unit issuances during 2012 (In millions, except units and per unit data):

Issuance Date	Units			Per Unit Gross Price		Per Unit Net Price (1)		Proceeds
January 13, 2012		3,500,000		$	30.73	$	29.50	$	103
July 25, 2012		4,600,000	(2)	$	26.00	$	24.97		115
		8,100,000						$	218

⁽¹⁾ Price is net of underwriting discounts.

⁽²⁾  Includes 600,000 units that were issued in August 2012.

On April 12, 2012, our General Partner made an additional capital contribution of approximately $3 million in exchange for the issuance of an additional 118,862 General Partner units, increasing the General Partner interest from 1.74% to 2%. During the three months ended September 30, 2012, our General Partner made an additional capital contribution of approximately $3 million in exchange for the issuance of an additional 96,860 General Partner units to maintain its 2% General Partner interest.

Distributions. Our Second Amended and Restated Agreement of Limited Partnership, dated February 19, 2008, as amended, requires that, within 45 days after the end of each quarter, we distribute all of our Available Cash (as defined therein) to unitholders of record on the applicable record date, as determined by our General Partner.

The following table presents distributions for 2012 and 2011 (In millions, except per unit data):

				Distribution Paid
				Limited Partners				General Partner
Payment Date	Attributable to the Quarter Ended	Per Unit Distribution		Cash paid to common		Paid-In-Kind Value to Class C unitholders (1)		Cash paid to  General Partner and IDR		Paid-In-Kind Value to Class C unitholders (1)		Total Cash		Total Distribution
2012
November 9, 2012	September 30, 2012	$	0.51	$	21.0	$	3.5	$	4.1	$	0.6	$	25.1	$	29.2
August 10, 2012	June 30, 2012	$	0.50	$	20.6	$	3.4	$	3.7	$	0.5	$	24.3	$	28.2
May 11, 2012	March 31, 2012	$	0.50	$	18.2	$	3.4	$	3.3	$	0.5	$	21.5	$	25.4
February 10, 2012	December 31, 2011	$	0.49	$	17.9	$	3.2	$	2.8	$	0.5	$	20.7	$	24.4
2011
November 10, 2011	September 30, 2011	$	0.48	$	15.8	$	3.1	$	2.3	$	0.4	$	18.1	$	21.6
August 12, 2011	June 30, 2011	$	0.46	$	15.2	$	2.9	$	1.6	$	0.2	$	16.8	$	19.9
May 13, 2011	March 31, 2011	$	0.44	$	13.7	$	2.7	$	1.1	$	0.2	$	14.8	$	17.7
February 11, 2011	December 31, 2010	$	0.43	$	13.4	$	—	$	0.9	$	—	$	14.3	$	14.3

⁽¹⁾  We issued 94,093, 115,140, 144,402, 120,095, 136,128 and 138,731 Class C units to Class C unitholders on May 13, 2011, August 12, 2011, November 10, 2011, February 10, 2012, May 11, 2012 and August 10, 2012.

We have the option to pay distributions to our Class C unitholders with cash or by issuing additional Paid-In-Kind 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. On November 9, 2012, we intend to issue an additional 174,230 Class C units to Class C unitholders. See our 2011 Annual Report on Form 10-K for additional information regarding the rights of our Class C unitholders and our General Partner.

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14. SEGMENT INFORMATION

Our operations include four reportable operating segments. These operating segments reflect the way we internally report the financial information used to make decisions and allocate resources in connection with our operations. We evaluate the performance of our operating segments based on EBITDA, which represents operating income plus, depreciation, amortization and accretion expense.

Our reportable segments reflect the primary geographic areas in which we operate and consist of Barnett, Fayetteville, Granite Wash and Marcellus, all of which are located within the United States. Our reportable segments are engaged in the gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs.

Other consists of those operating segments or reporting units that did not meet quantitative reporting thresholds. For the nine months ended September 30, 2012, one of our customers, which is a related party, accounted for 55% of our total revenues in the Barnett segment. In our Fayetteville segment, one customer accounted for 11% of our total revenues.

The following table is a reconciliation of Net Income to EBITDA (In thousands):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2012		2011		2012		2011
Net income	$	11,105	$	13,058	$	26,890	$	32,661
Add:
Interest and debt expense		8,202		7,100		24,045		19,925
Income tax expense		306		347		884		898
Depreciation, amortization and accretion expense		10,943		9,595		32,427		23,981
EBITDA	$	30,556	$	30,100	$	84,246	$	77,465

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The following tables summarize the reportable segment data for the three and nine months ended September 30, 2012 and 2011 (In thousands):

	Three Months Ended September 30, 2012
	Barnett		Fayetteville		Granite Wash		Marcellus		Other		Corporate			Total
Operating revenues	$	5,390	$	7,174	$	10,702	$	—	$	3,815	$	—		$	27,081
Operating revenues—related party		27,956		—		—		—		—		—			27,956
Product purchases		60		137		9,481		—		663		—			10,341
Operations and maintenance expense		6,963		1,855		560		—		749		—			10,127
General and administrative expense		—		—		—		—		—		5,777			5,777
Earnings from unconsolidated affiliate		—		—		—		1,764		—		—			1,764
EBITDA	$	26,323	$	5,182	$	661	$	1,764	$	2,403	$	(5,777	)	$	30,556
Goodwill	$	—	$	76,767	$	14,211	$	—	$	4,053	$	—		$	95,031
Total assets	$	619,768	$	304,669	$	77,611	$	129,603	$	83,701	$	17,097		$	1,232,449
Capital expenditures	$	4,719	$	1,086	$	448	$	—	$	955	$	225		$	7,433
	Three Months Ended September 30, 2011
	Barnett		Fayetteville		Granite Wash		Marcellus		Other		Corporate			Total
Operating revenues	$	1,861	$	7,081	$	12,675	$	—	$	1,975	$	—		$	23,592
Operating revenues—related party		35,023		—		—		—		—		—			35,023
Product purchases		—		454		11,264		—		1,764		—			13,482
Operations and maintenance expense		6,015		3,965		499		—		94		—			10,573
General and administrative expense		—		—		—		—		—		5,566			5,566
Gain from exchange of property, plant and equipment		—		—		—		—		—		1,106			1,106
EBITDA	$	30,869	$	2,662	$	912	$	—	$	117	$	(4,460	)	$	30,100
Goodwill	$	—	$	76,767	$	16,861	$	—	$	—	$	—		$	93,628
Total assets	$	550,440	$	296,771	$	73,156	$	—	$	5,959	$	18,536		$	944,862
Capital expenditures	$	3,797	$	9,806	$	421	$	—	$	79	$	265		$	14,368

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	Nine Months Ended September 30, 2012
	Barnett		Fayetteville		Granite Wash		Marcellus (1)		Other		Corporate			Total
Operating revenues	$	12,053	$	20,368	$	28,021	$	—	$	9,791	$	—		$	70,233
Operating revenues—related party		86,739		—		—		—		—		—			86,739
Product purchases		60		343		24,514		—		1,838		—			26,755
Operations and maintenance expense		18,438		6,399		1,619		—		2,269		—			28,725
General and administrative expense		—		—		—		—		—		19,451			19,451
Earnings from unconsolidated affiliate		—		—		—		2,205		—		—			2,205
EBITDA	$	80,294	$	13,626	$	1,888	$	2,205	$	5,684	$	(19,451	)	$	84,246
Goodwill	$	—	$	76,767	$	14,211	$	—	$	4,053	$	—		$	95,031
Total assets	$	619,768	$	304,669	$	77,611	$	129,603	$	83,701	$	17,097		$	1,232,449
Capital expenditures	$	10,718	$	10,040	$	2,411	$	—	$	5,140	$	659		$	28,968
	Nine Months Ended September 30, 2011
	Barnett		Fayetteville (2)		Granite Wash(2)		Marcellus		Other(3)		Corporate			Total
Operating revenues	$	6,016	$	14,164	$	25,210	$	—	$	3,711	$	—		$	49,101
Operating revenues—related party		97,429		—		—		—		—		—			97,429
Product purchases		—		1,012		21,739		—		3,259		—			26,010
Operations and maintenance expense		18,528		6,356		998		—		283		—			26,165
General and administrative expense		—		—		—		—		—		17,996			17,996
Gain from exchange of property, plant and equipment		—		—		—		—		—		1,106			1,106
EBITDA	$	84,917	$	6,796	$	2,473	$	—	$	169	$	(16,890	)	$	77,465
Goodwill	$	—	$	76,767	$	16,861	$	—	$	—	$	—		$	93,628
Total assets	$	550,440	$	296,771	$	73,156	$	—	$	5,959	$	18,536		$	944,862
Capital expenditures	$	15,579	$	12,134	$	3,161	$	—	$	117	$	265		$	31,256

⁽¹⁾  Includes approximately six months of income for Marcellus, from March 26, 2012 to September 30, 2012, subsequent to the acquisition.

⁽²⁾  Includes six months of income for Fayetteville and Granite Wash, from April 1, 2011 to September 30, 2011, subsequent to the acquisition.

⁽³⁾ Includes approximately eight months of income for Las Animas Systems, from February 16, 2011 to September 30, 2011, subsequent to the acquisition.

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

Overview and Performance Metrics

We are a growth-oriented publicly traded Delaware master limited partnership engaged in the gathering, processing, treating, compression, transportation and sales of natural gas and the delivery of NGLs produced from the geological formations of the Barnett Shale in north Texas, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Marcellus Shale in northern West Virginia, the emerging Avalon Shale trend in southeastern New Mexico, and the Haynesville/Bossier Shale in western Louisiana. We provide midstream services to various producers that focus on developing unconventional resources across the United States. Our largest producer is Quicksilver Resources Inc. (Quicksilver). For the three and nine months ended September 30, 2012, Quicksilver’s production volumes accounted for 46% and 50% of our total revenues. We also gather certain natural gas volumes that Quicksilver purchases from Eni SpA, which comprised 5% of our total revenues for both the three and nine months ended September 30, 2012.

We conduct all of our operations in the midstream sector in eight operating segments, four of which are reportable. Our operating segments reflect how we manage our operations and are generally reflective of the geographic areas in which we operate. Our reportable segments consist of Barnett, Fayetteville, Granite Wash and Marcellus. Our operating segments are engaged in gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs in the United States.

The results of our operations are significantly influenced by the volumes of natural gas gathered and processed through our systems. We gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and percent-of-proceeds contracts. Under our fixed-fee contracts, we do not take title to the natural gas or associated NGLs. For the nine months ended September 30, 2012, approximately 98% of our gross margin, which we define as total revenue less product purchases, is derived from fixed-fee service contracts, which minimizes our commodity price exposure and provides us with less volatile operating performance and cash flows. Under our percent-of-proceeds contracts, we take title to the residue gas, NGLs and condensate and remit a portion of the sale proceeds to the producer based on prevailing commodity prices. For the nine months ended September 30, 2012, the net revenues from percent-of-proceeds contracts accounted for approximately 2% of our gross margin.

Although we do not have significant direct commodity price exposure, lower natural gas prices could have a potential negative impact on the pace of drilling in dry gas areas – such as areas in the Barnett Shale (gathered by the Alliance and Lake Arlington Systems), the Fayetteville Systems and the Sabine System (part of the Haynesville/Bossier Shale). We operate five systems located in basins that include NGL rich gas shale plays: (i) the Cowtown System (which includes the West Johnson County System acquired in the Devon Acquisition), part of the Barnett segment; (ii) the Granite Wash System; (iii) the Las Animas Systems in the Avalon Shale; and (iv) two systems acquired by Crestwood Marcellus Midstream LLC (CMM), our unconsolidated affiliate), in the Marcellus segment. For the three and nine months ended September 30, 2012, our consolidated systems (i.e., excluding CMM) located in NGL rich gas basins contributed approximately 55% and 54% of our total revenues and 33% and 29% of our total gathering volumes. For the three and nine months ended September 30, 2012, our consolidated and unconsolidated systems located in NGL rich gas basins (i.e., including 100% of CMM’s results), when combined, would have contributed approximately 61% and 58% of our total consolidated and unconsolidated revenues and 54% and 46% of total consolidated and unconsolidated gathering volumes. A prolonged decrease in the commodity price environment could result in our customers reducing their production volumes which would result in a decrease in our revenues.

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 acquisition opportunities.

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Operations and Maintenance Expenses — We consider operations and maintenance expenses in evaluating the performance of our operations. These expenses are comprised primarily of labor, parts and materials, insurance, taxes other than income taxes, repair and maintenance costs, utilities and contract services. Our ability to manage operations and maintenance expenses has a significant impact on our profitability and ability to pay distributions.

EBITDA and Adjusted EBITDA — We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company’s operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. EBITDA and Adjusted EBITDA are not measures calculated in accordance with accounting principles generally accepted in the United States of America (GAAP), as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. In addition, Adjusted EBITDA considers certain expenses related to non-recurring matters identified in a specific reporting period. Additionally, Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliate by adjusting our equity earnings from our unconsolidated affiliate for our proportionate share of its depreciation, amortization and accretion, interest and other non-recurring charges for a specific reporting period. EBITDA and Adjusted 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 and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.

See our reconciliation of Net Income to EBITDA and Adjusted EBITDA inResults of Operations below.

Current Year Highlights

Below is a discussion of events that highlight our core business and financing activities.

Operational and Industry Highlights

Shale gas production in the United States has grown rapidly in recent years as the natural gas industry has improved drilling and extraction methods while increasing exploration efforts. The United States has a wide distribution of shale formations containing vast resources of natural gas, NGLs and oil. Led by the rapid development of the Barnett Shale in Texas, shale gas activity has expanded into other areas such as the Marcellus, Fayetteville and Haynesville/Bossier shale plays.

Growth through Diversification —Our operating results reflect our ability to diversify our shale play portfolio and increase volumes not only through our base business located in the Barnett Shale, but also through strategic acquisitions in a number of attractive shale plays in the United States. During the first half of 2012, we focused on acquisitions in NGL rich gas shale plays such as the southwest portion of the Marcellus Shale. Our business strategy going forward will focus on developing new greenfield opportunities in rich gas plays like the Permian, the Utica and the Niobrara and continuing to seek “bolt-on” acquisitions similar to our latest acquisition from Devon Energy Corporation (Devon), which will provide operating synergies and allow for the development of our business in rich gas infrastructure plays.

Our consolidated systems gathered 592 MMcf/d during the nine months ended September 30, 2012 which is an increase of 10% from 539 MMcf/d during the same period in 2011. Additionally, our processed volumes increased slightly from 143 MMcf/d for the nine months ended September 30, 2011 to 157 MMcf/d for the same period in 2012. The increase in volumes resulted in a 7% increase in our overall revenues for the nine months ended September 30, 2012 compared to the same period in 2011.

Additionally, in March 2012, we made an equity investment in CMM, a joint venture, which purchased gathering assets in the Marcellus Shale. For the three and nine months ended September 30, 2012, CMM gathered 289 MMcf/d and 273 MMcf/d. Our earnings from our unconsolidated affiliate were approximately $2 million for both the three and nine months ended September 30, 2012. We believe that this investment will be an integral component of our growth-oriented business model.

Distribution Growth — For the three and nine months ended September 30, 2012, we declared a distribution of $0.51 and $1.51 per limited partner unit compared to $0.48 and $1.38 per limited partner unit during the same periods in 2011. This represents a 6% and 9% increase when comparing the three and nine months ended September 30, 2012 to the same periods in 2011.

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Devon Acquisition

On August 24, 2012, we completed the acquisition of certain gathering and processing assets in the NGL rich gas region of the Barnett Shale from Devon for approximately $87 million (the Devon Acquisition). The assets acquired consist of a 74 mile low pressure natural gas gathering system, a 100 MMcf/d cryogenic processing facility and 23,100 horsepower of compression equipment, and are located in Johnson County, Texas near our Cowtown gathering system. Additionally, we entered into a 20 year, fixed-fee gathering, processing and compression agreement with Devon, under which we will gather and process Devon’s natural gas production from a 20,500 acre dedication. Natural gas production under the agreement was approximately 78 MMcf/d as of September 30, 2012.

The West Johnson County system acquired in the Devon Acquisition has approximately 230 producing wells as of September 30, 2012. Additionally, due to the NGL rich gas quality of the natural gas production in this portion of the Barnett Shale, Devon has maintained an active drilling and development plan for the Johnson County area in 2012 and expects to continue to further develop the dedicated properties in 2013.

Investment in an Unconsolidated Affiliate

On March 26, 2012, we invested approximately $131 million in cash in exchange for a 35% interest in CMM, which is held by our wholly-owned subsidiary. Crestwood Holdings LLC and its affiliates invested $244 million for the remaining 65% interest. CMM is a new joint venture formed to acquire certain of Antero Resources Appalachian Corporation’s (Antero) Marcellus Shale gathering system assets located in Harrison and Doddridge Counties, West Virginia. CMM’s purchase price to acquire the assets was $380 million. Antero may earn additional payments of up to $40 million based upon average annual production levels achieved during 2012, 2013 and 2014.

Additionally, CMM entered into the 20 year, fixed-fee, Gas Gathering and Compression Agreement (GGA) with Antero, which provides for an area of dedication of approximately 127,000 gross acres, largely located in the rich gas corridor of the southwestern core of the Marcellus Shale play. As part of the GGA, Antero committed to delivery of minimum annual volumes to CMM for a seven year period from January 1, 2012 to January 1, 2019, ranging from an average of 300 MMcf/d in 2012 to an average of 450 MMcf/d in 2018.

The assets acquired by CMM at closing include approximately 33 miles of low pressure gathering pipelines gathering approximately 210 MMcf/d from 59 existing horizontal Marcellus Shale wells. The gathering pipelines deliver Antero’s Marcellus Shale production to various regional pipeline systems including Columbia, Dominion and Equitrans.

Financing Activities

Equity Offerings

During the three months ended September 30, 2012, we completed a public offering of 4,600,000 common units, representing limited partner interests, at a price of $26.00 per common unit ($24.97 per common unit, net of underwriting discounts), providing net proceeds of approximately $115 million. We used the net proceeds from the offering to fund the amounts paid for the Devon Acquisition and to reduce indebtedness under our Credit Facility. In connection with the issuance of common units, our General Partner made an additional capital contribution of $3 million to maintain its 2% general partner interest.

On January 13, 2012, we completed a public offering of 3,500,000 common units, representing limited partner interests, at a price of $30.73 per common unit ($29.50 per common unit, net of underwriting discounts), providing net proceeds of approximately $103 million. The net proceeds from the offering were used to reduce indebtedness under our Credit Facility. Our General Partner did not make an additional capital contribution at the time of the offering, resulting in a reduction in our General Partner’s general partner interest to approximately 1.74%. On April 12, 2012, our General Partner made an additional capital contribution of approximately $3 million in exchange for the issuance of an additional 118,862 General Partner units, increasing the General Partner interest from 1.74% to 2%.

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Results of Operations

Three and Nine Months Ended September 30, 2012 Compared with Three and Nine Months Ended September 30, 2011

The following table summarizes our results of operations (In thousands):

	Three Months Ended September 30,						Nine Months Ended September 30,
	2012			2011			2012			2011
Total operating revenues	$	55,037		$	58,615		$	156,972		$	146,530
Product purchases		10,341			13,482			26,755			26,010
Operations and maintenance expense		10,127			10,573			28,725			26,165
General and administrative expense		5,777			5,566			19,451			17,996
Depreciation, amortization and accretion expense		10,943			9,595			32,427			23,981
Gain from exchange of property, plant and equipment		—			1,106			—			1,106
Operating income		17,849			20,505			49,614			53,484
Earnings from unconsolidated affiliate		1,764			—			2,205			—
Interest and debt expense		8,202			7,100			24,045			19,925
Income tax expense		306			347			884			898
Net income	$	11,105		$	13,058		$	26,890		$	32,661
Add:
Interest and debt expense		8,202			7,100			24,045			19,925
Income tax expense		306			347			884			898
Depreciation, amortization and accretion expense		10,943			9,595			32,427			23,981
EBITDA	$	30,556		$	30,100		$	84,246		$	77,465
Non-recurring expenses		932			129			2,710			3,166
Gain from exchange of property, plant and equipment		—			(1,106	)		—			(1,106	)
Earnings from unconsolidated affiliate		(1,764	)		—			(2,205	)		—
Adjusted earnings from unconsolidated affiliate		2,237			—			4,113			—
Adjusted EBITDA	$	31,961		$	29,123		$	88,864		$	79,525

EBITDA in the table above includes operating results from our Barnett, Fayetteville and Granite Wash segments and other operations, earnings from our unconsolidated affiliate (our Marcellus segment), general and administrative expenses, and the gain from exchange of property, plant and equipment. The following table summarizes the results of our Barnett, Fayetteville and Granite Wash segments and other operations (In thousands):

	Three Months Ended September 30,
	Barnett				Fayetteville				Granite Wash				Other				Total
	2012		2011		2012		2011		2012		2011		2012		2011		2012		2011
Gathering revenues	$	24,737	$	29,042	$	7,043	$	6,534	$	465	$	113	$	3,152	$	158	$	35,397	$	35,847
Processing revenues		8,540		7,842		—		—		29		33		—		—		8,569		7,875
Product sales		69		—		131		547		10,208		12,529		663		1,817		11,071		14,893
Total operating revenues	$	33,346	$	36,884	$	7,174	$	7,081	$	10,702	$	12,675	$	3,815	$	1,975	$	55,037	$	58,615
Product purchases		60		—		137		454		9,481		11,264		663		1,764		10,341		13,482
Operations and maintenance expense		6,963		6,015		1,855		3,965		560		499		749		94		10,127		10,573
EBITDA	$	26,323	$	30,869	$	5,182	$	2,662	$	661	$	912	$	2,403	$	117
Gathering volumes (in MMcf)		40,252		46,641		8,403		7,813		1,856		1,473		5,041		1,037		55,552		56,964
Processing volumes (in MMcf)		14,671		11,975		—		—		1,859		1,475		—		—		16,530		13,450

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	Nine Months Ended September 30,
	Barnett				Fayetteville				Granite Wash				Other				Total
	2012		2011		2012		2011		2012		2011		2012		2011		2012		2011
Gathering revenues	$	74,567	$	79,892	$	20,037	$	13,095	$	874	$	208	$	7,952	$	419	$	103,430	$	93,614
Processing revenues		24,156		23,553		—		—		128		37		—		—		24,284		23,590
Product sales		69		—		331		1,069		27,019		24,965		1,839		3,292		29,258		29,326
Total operating revenues	$	98,792	$	103,445	$	20,368	$	14,164	$	28,021	$	25,210	$	9,791	$	3,711	$	156,972	$	146,530
Product purchases		60		—		343		1,012		24,514		21,739		1,838		3,259		26,755		26,010
Operations and maintenance expense		18,438		18,528		6,399		6,356		1,619		998		2,269		283		28,725		26,165
EBITDA	$	80,294	$	84,917	$	13,626	$	6,796	$	1,888	$	2,473	$	5,684	$	169
Gathering volumes (in MMcf)		117,434		126,471		23,049		15,146		4,576		3,011		17,149		2,655		162,208		147,283
Processing volumes (in MMcf)		38,493		36,028		—		—		4,566		2,941		—		—		43,059		38,969

EBITDA and Adjusted EBITDA —EBITDA increased by less than $1 million and approximately $7 million for the three and nine months ended September 30, 2012 compared to same periods during 2011. In the same manner, Adjusted EBITDA increased by approximately $3 million and $9 million for the three and nine months ended September 30, 2012 compared to the respective periods in 2011. Adjusted EBITDA considers expenses for evaluating certain transaction opportunities and other non-recurring matters. For the three and nine months ended September 30, 2012, these adjustments to EBITDA were approximately $1 million and $3 million. Additionally, Adjusted EBITDA includes less than $1 million and approximately $2 million of net earnings adjustments related to adding back our proportionate share of our unconsolidated affiliate’s depreciation, amortization and accretion expense (DA&A), interest and debt expense and non-recurring expenses for the three and nine months ended September 30, 2012.

Below is a discussion of the factors that impacted EBITDA by segment for the three and nine months ended September 30, 2012 compared to the same periods in 2011:

Barnett:

For both the three and nine months ended September 30, 2012, our Barnett segment’s EBITDA was approximately $5 million lower than the same periods in 2011, primarily due to lower gathering revenues.

Revenues and Volumes —Revenues in our Barnett segment decreased by approximately $4 million and $5 million during the three and nine months ended September 30, 2012 compared to the same periods in 2011, primarily due to lower dry gas gathering volumes. Our gathering revenues for our Barnett segment were flat during the third quarter of 2012 compared to the second quarter of 2012, but lower than the first quarter of 2012. The decrease in gathering volumes primarily related to reduced production from existing wells and well shut-ins at our Alliance and Lake Arlington gathering systems. These decreases in volumes were partially offset by producers connecting 11 and 43 new wells during the three and nine months ended September 30, 2012. We anticipate that the number of new wells connected to our systems may be impacted by moderated drilling activity in dry gas areas for the remainder of 2012.

Also, partially offsetting the decline in gathering revenues and volumes discussed above was an increase in gathering and processing revenues due to the Devon Acquisition, which was completed on August 24, 2012. During the three and nine months ended September 30, 2012, the acquired assets generated approximately $2 million of gathering and processing revenues for our Barnett segment.

In addition to the items discussed above, our revenues were also unfavorably impacted by a compressor building fire at our Corvette processing plant that occurred on September 6, 2012, which reduced revenues by approximately $0.5 million. Additional impacts to the Barnett segment’s EBITDA as a result of the compressor building fire are further discussed below.

Operations and Maintenance Expense — Operations and maintenance expenses in our Barnett segment increased by approximately $1 million or 16% for the three months ended September 30, 2012 when compared to the same period in 2011, while remaining relatively flat year over year. The increase in operations and maintenance expenses was primarily due to (i) the Devon Acquisition; (ii) approximately $0.2 million of costs related to a condensate spill at our Corvette facility; and (iii) a compressor building fire at our Corvette processing plant. As a result of the building fire at our Corvette processing plant, we impaired assets of approximately $1.6 million, incurred repair costs of approximately $0.8 million, and recorded an insurance receivable of approximately $2.2 million, all of which resulted in a net impact to our operations and maintenance expenses of approximately $0.2 million.

29

Fayetteville:

Our Fayetteville segment EBITDA increased approximately $2.5 million and $6.8 million during the three and nine months ended September 30, 2012 compared with the same periods in 2011, primarily due to higher revenues and volumes during both periods. Also contributing to the increase in our Fayetteville segment EBITDA during the three months ended September 30, 2012, were lower operations and maintenance expenses.

Revenues and Volumes—During the three months ended September 30, 2012, BHP Billiton Petroleum, Plc. (BHP) connected six new wells on our Twin Groves System, contributing to an increase in revenues and volumes in our Fayetteville segment. Additionally, we recognized nine months of revenues in 2012 versus six months during 2011 due to the acquisition of our operations in Fayetteville on April 1, 2011.

Operations and Maintenance Expense –Operations and maintenance expenses in our Fayetteville segment decreased by approximately $2.1 million during the three months ended September 30, 2012 compared to the same period in 2011, primarily due to the cancellation of several operating leases in January 2012.

Granite Wash:

During the three and nine months ended September 30, 2012, our Granite Wash segment’s EBITDA was approximately $0.2 million and $0.6 million lower than the same periods in 2011 primarily due to lower product sales margin and higher operations and maintenance expenses.

Revenues/Margin and Volumes—For the three and nine months ended September 30, 2012, Granite Wash’s EBITDA decreased compared to the same period in 2011, due to lower margins earned on our percent-of-proceeds contracts, which primarily resulted from lower NGL and natural gas prices experienced during the three and nine months ended September 30, 2012 coupled with relatively consistent costs per volume. Partially offsetting this decrease in product sales margin was higher gathering revenues due to new wells connected by Le Norman Operating LLC (Le Norman) during the three months ended September 30, 2012.

Operations and Maintenance Expense—For the three and nine months ended September 30, 2012 compared to the same periods in 2011, operations and maintenance expenses were higher due to the increase in volumes resulting from the new wells connected by Le Norman.

Other:

Our other operations include our assets in the Haynesville/Bossier Shale (Sabine System) and our assets in the Avalon Shale (Las Animas System). For the three and nine months ended September 30, 2012, our other operations’ EBITDA increased by approximately $2 million and $6 million compared to the same periods in 2011, which primarily relates to the operations of our Sabine System which was acquired in November 2011.

Revenues and Volumes—The Sabine System had 45 MMcf/d and 53 MMcf/d in gathered volumes for the three and nine months ended September 30, 2012 which resulted in approximately $3 million and $8 million in revenues for the three and nine months ended September 30, 2012. Revenues related to our Sabine System during the three months ended September 30, 2012 increased by approximately $1 million when compared to three months ended June 30, 2012 due to a gathering contract entered into with a subsidiary of US Infrastructure Holdings, LLC (USI) at the end of the second quarter of 2012 that has a minimum volume commitment. Although we experienced an increase in our revenues under this contract, our volumes remained relatively flat due to USI transporting volumes at a level below the minimum quantity in the contract. EBITDA related to our Las Animas System remained relatively unchanged for the three and nine months ended September 30, 2012, compared to the same periods in 2011.

30

Operations and Maintenance Expense —Operations and maintenance expenses increased during the nine months ended September 30, 2012, while remaining relatively flat during the third quarter of 2012 compared to the second quarter of 2012. The increase in expenses related to our Sabine System acquired in November 2011.

Marcellus:

In March 2012, we invested approximately $131 million in cash in exchange for a 35% ownership interest in CMM, which is held by our wholly-owned subsidiary. At the same time, CMM purchased assets in the Marcellus Shale from Antero. This investment in CMM, which is an unconsolidated affiliate, represents our Marcellus segment. For the three and nine months ended September 30, 2012, we had approximately $1.8 million and $2.2 million in earnings from our unconsolidated affiliate. The increase in earnings from our unconsolidated affiliate during the three months ended September 30, 2012 when compared to the three months ended June 30, 2012, was due primarily to a decrease in our proportionate share of CMM’s DA&A expense, interest and debt expense and non-recurring expenses, which was $0.5 million and $1.9 million for the three and nine months ended September 30, 2012. During the three months ended September 30, 2012, CMM finalized its purchase price allocation of the assets acquired from Antero, which reduced our proportionate share of its DA&A expense by $0.4 million.

For the three and nine months ended September 30, 2012, CMM gathered 289 MMcf/d and 273 MMcf/d through its assets acquired from Antero. Since the inception of CMM, Antero connected 16 wells and 31 wells to CMM during the three and nine months ended September 30, 2012, and is expected to connect additional wells during the remainder of the year. The expected increase in volumes from the added wells is expected to increase our equity earnings from this investment.

Below is a discussion of items impacting our EBITDA that are not allocated to our segments.

General and Administrative Expenses — During the three and nine months ended September 30, 2012, general and administrative expenses increased by approximately $0.2 million and $1 million when compared to the same periods in 2011. General and administrative expense includes costs related to legal and other consulting services to evaluate certain transaction opportunities and other non-recurring matters. We incurred approximately $2.3 million of these costs during the nine months ended September 30, 2012, as compared to $3.2 million during the nine months ended September 30, 2011, which was the primary driver for the increase in general and administrative expense year over year.

Also impacting our general and administrative expenses for the three and nine months ended September 30, 2012 were increases in payroll and related benefit costs, which reflects the increased scope of our business operations compared to the same periods in 2011.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense —DA&A expense increased by $1 million and $8 million for the three and nine months ended September 30, 2012 compared to the same periods in 2011 primarily due to assets acquired through our Tristate Acquisition during November 2011 and our Devon Acquisition in August 2012.

Interest and Debt Expense— Interest and debt expense increased for the three and nine months ended September 30, 2012 compared to the same periods in 2011, primarily due to higher outstanding balances on our Credit Facility. In addition, our Senior Notes were outstanding for the full nine months during 2012 compared to six months for 2011, as we issued our Senior Notes in April 2011.

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The following table provides a summary of interest and debt expense (In thousands):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2012			2011			2012			2011
Interest cost:
Credit Facility	$	4,172		$	3,089		$	11,601		$	9,325
Senior Notes		4,070			4,005			12,124			8,097
Bridge Loan		—			—			—			2,500
Capital lease interest		55			60			149			125
Other debt-related costs		—			—			462			—
Total cost		8,297			7,154			24,336			20,047
Less capitalized interest		(95	)		(54	)		(291	)		(122	)
Interest and debt expense	$	8,202		$	7,100		$	24,045		$	19,925

Liquidity and Capital Resources

Our sources of liquidity include cash flows generated from operations, available borrowing capacity under our Credit Facility, and issuances of additional debt and equity in the capital markets. We believe that our sources of liquidity will be sufficient to fund our short-term working capital requirements, capital expenditures and cash distributions for the remainder of 2012. The amount of distributions to unitholders is determined by the board of directors of our General Partner on a quarterly basis.

We regularly review opportunities for both acquisitions and greenfield growth projects that will enhance our financial performance. Since we distribute most of our available cash to our unitholders, we depend on a combination of borrowings under our Credit Facility and debt or equity offerings to finance the majority of our long-term growth capital expenditures or acquisitions.

Management continuously monitors our leverage position and our anticipated capital expenditures relative to our expected cash flows. We continue to evaluate funding alternatives, including additional borrowings and the issuance of debt or equity securities, to secure funds as needed or refinance outstanding debt balances with longer term notes.

Known Trends and Uncertainties Impacting Liquidity

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

• Concentration of Gathering Revenues from Quicksilver:While we have reduced our dependency upon Quicksilver through the acquisition of additional midstream assets that have long term contracts with creditworthy producers such as BHP, British Petroleum, Plc., XTO Energy, a subsidiary of Exxon Mobil Corporation and Chesapeake Energy Corporation, we remain dependent upon Quicksilver for a substantial percentage of our current business. For the three and nine months ended September 30, 2012, Quicksilver’s production volumes accounted for 46% and 50% of our total revenues. We also gather certain natural gas volumes that Quicksilver purchases from Eni SpA, which comprised 5% of our total revenues for both the three and nine months ended September 30, 2012. Including approximately 9% that is comprised of natural gas purchased by Quicksilver from Eni SpA and gathered under Quicksilver’s Alliance System gathering agreement. The risk of revenue fluctuations in the near term is mitigated by the use of fixed-fee contracts for providing gathering, processing, treating and compression services; however, our revenues may be impacted by volume fluctuations. While our acquisitions reduce the concentration of risk associated with our dependency on one producer and one geographic area, we continue to regularly review opportunities for both acquisitions and greenfield growth projects in other producing basins and with other producers in the future.

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• Access to Capital Markets:Our borrowings under the Credit Facility were $333 million as of September 30, 2012 and based on our results through September 30, 2012, our remaining available capacity under the Credit Facility was $167 million. On March 20, 2012, we amended our Credit Agreement to permit the acquisition of an equity interest in CMM described above and to allow for additional investments in CMM of up to $160 million. While we anticipate that our current available borrowing capacity under our Credit Facility is sufficient to fund our planned level of growth capital spending for the remainder of 2012, additional debt and equity offerings may be necessary to fund additional acquisitions or other growth capital projects. During 2011, we raised approximately $500 million through debt and equity offerings and increases to our Credit Facility to fund acquisitions and growth capital projects. Additionally, during 2012 approximately $218 million was raised through the issuance of public common units.

• Natural Gas Prices: Adding new volumes through our gathering systems is dependent on the drilling and completion activities of natural gas producers in our areas of operations. Although investment returns differ between natural gas basins, rich gas and dry gas reservoirs in certain natural gas basins and between various production companies, low natural gas prices may reduce the levels of drilling activity in areas around certain of our assets, particularly those that concentrate on gathering from dry gas reservoirs. We seek to mitigate this risk by diversifying into various geographical production basins with predominately rich gas natural gas reservoirs. We have observed that largely due to superior prices for crude oil and NGLs compared to natural gas, producers are shifting their drilling and development plans to focus on increasing production from rich gas basins or shale plays which offer better drilling economics as compared to production from dry gas basins. We have five systems located in basins that include NGL rich gas shale plays, (i) the Cowtown System (which includes the West Johnson County System acquired in the Devon Acquisition), part of the Barnett segment; (ii) the Granite Wash System; (iii) the Las Animas Systems in the Avalon Shale; and (iv) two systems acquired by CMM, (our unconsolidated affiliate), in the Marcellus segment. For three and the nine months ended September 30, 2012, these rich gas systems accounted for approximately 61% and 58% of our total consolidated and unconsolidated revenues. We will continue to focus on expanding our business activities and opportunities in rich gas basins or rich gas shale plays due to the current trend of increased drilling and producer activities in these areas.

• Regulatory Requirements: Our operations and the operations of our customers are subject to complex and evolving federal, state, local and other laws and regulations. For example, on April 17, 2012, the United States Environmental Protection Agency issued a final rule establishing new emission limitations for certain oil and gas facilities. These rules establish emission standards for gas wells that are hydraulically fractured (or re-fractured). These rules also establish emissions standards for natural gas processing equipment, including compressors, controllers, storage tanks, and gas processing plants. These or other federal or state initiatives relating to hydraulic fracturing or other environmental matters could impact the extent of our operations and/or give rise to or accelerate the need for additional capital projects. In addition, any further changes in laws or regulations, or delays in the issuance of required permits, may further impact the volumes on our systems.

• Impact of Inflation and Interest Rates: Although inflation in the United States has been relatively low in recent years, the United States economy may experience a significant inflationary effect in the future. Although inflation would negatively impact the cost of our operations and cash flows through services provided to us, the majority of our gathering and processing agreements allow us to charge increased rates based on indices expected to track such inflationary trends. Interest rates have also remained low in recent years, as compared with historical averages. Should interest rates rise, our financing costs would increase accordingly. In addition, as with other yield-oriented securities, our unit price would also be negatively impacted by higher interest rates. Higher interest rates would increase the costs of issuing debt or equity necessary to finance potential future acquisitions. However, our competitors would face similar circumstances and we expect our cost of capital to remain competitive.

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Cash Flows

The following table provides a summary of our cash flows by category (In thousands):

	Nine Months Ended
	September 30,
	2012			2011
Net cash provided by operating activities	$	70,139		$	68,465
Net cash used in investing activities		(245,840	)		(374,975	)
Net cash provided by financing activities		174,916			306,566

Operating Activities

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011 –During the nine months ended September 30, 2012, our operating cash flows were relatively flat compared to the same period in 2011. Although our revenues were higher by approximately $10 million during 2012 as compared to 2011, cash paid for operations and maintenance expenses, general and administrative expenses and interest costs increased, which partially offset the increase in our revenues.

Investing Activities

The midstream energy business is capital intensive, requiring significant investments 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, extend their useful lives or comply with regulatory requirements.

We anticipate that we will continue to make capital expenditures to develop our gathering and processing assets in the producing basins in which we operate as well as opportunities to expand into new geographical areas through acquisitions and greenfield growth opportunities.

Nine Months Ended September 30, 2012 Compared with Nine Months Ended September 30, 2011 – In March 2012, we invested approximately $131 million in cash in exchange for a 35% ownership interest in CMM, and during the nine months ended September 30, 2012, we received distributions from our unconsolidated affiliate of approximately $2 million. In August 2012, we completed the acquisition of certain gathering and processing assets in the liquids-rich southwestern area of the Barnett Shale from Devon for approximately $87 million. Additionally, during the nine months ended September 30, 2012, we spent approximately $29 million on capital projects, including $3 million related to maintenance capital expenditures. During the nine months ended September 30, 2011, we acquired the Frontier and Las Animas Systems for approximately $350 million. We also received proceeds of approximately $6 million related to the exchange of property, plant and equipment during the nine months ended September 30, 2011.

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The following table summarizes capital expenditures for the nine months ended September 30, 2012 and our expected capital expenditures for the remainder of 2012 (In millions):

	Nine Months Ended September 30, 2012		2012 Remaining		Total
Expansion capital	$	26.1	$	3.8	$	29.9
Maintenance capital		2.9		2.2		5.1
Total	$	29.0	$	6.0	$	35.0

We do not anticipate any contributions to CMM for the remainder of 2012, since CMM entered into a $200 million revolving credit facility during the first quarter of 2012 to finance its future capital requirements and working capital needs.

Financing Activities

Significant items impacting our financing activities during the nine months ended September 30, 2012 included the following:

• Net borrowings under our Credit Facility of $21 million;

• $218 million in proceeds from the issuance of 8,100,000 common units during 2012; and

• General Partner’s capital contribution of approximately $6 million in exchange for the issuance of an additional 215,722 General Partner units to maintain its 2% General Partner interest.

This increase was primarily offset by $67 million of distributions paid to unitholders during the nine months ended September 30, 2012, which increased by $20 million when compared to the same period in 2011.

Off-Balance Sheet Arrangements

We have no significant off-balance sheet arrangements.

New Accounting Pronouncement Issued But Not Yet Adopted

See Item 1. Financial Statements, Note 2.Summary of Significant Accounting Policies, which is incorporated herein by reference.

Critical Accounting Estimates

Our significant accounting policies are described in our 2011 Annual Report on Form 10-K and in Item 1. Financial Statements, Note 2.Summary of Significant Accounting Policies,of this Quarterly Report. The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses.

In addition to the critical accounting estimates discussed in our 2011 Annual Report on Form 10-K, during the nine months ended September 30, 2012, we have also adopted a new critical accounting policy related to our equity method investment in CMM. The accounting standards related to investment impairments require us to continually monitor the business environment and the performance of our investment to determine if an event has occurred that indicates that an investment may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to estimate the fair value of the asset. This estimate considers a number of factors, including the potential value we would receive if we sold the asset and the projected cash flows of the asset based on current and anticipated future market conditions and discounts rates. Our assessment of fair value including, but not limited to estimates of project level cash flows, requires significant judgment to make projections and assumptions that we believe a market participant would use for pricing, demand, competition, operating costs, legal and regulatory issues and other factors that extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can, and often do, differ from our estimates.

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We utilize the cash flow projections to assess our ability to recover the carrying value of our investments based on the fair value of our investment in unconsolidated affiliate and whether any decline in this fair value below our carrying amount is considered to be other than temporary. If an impairment is indicated, we record an impairment charge for the excess of the carrying value of the asset over its fair value. As of September 30, 2012, we have determined that there is no impairment to our equity method investment. Future changes in the economic and business environment can impact our assessments of potential impairments.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

There are no material changes in our quantitative and qualitative disclosures about market risks from those reported in our 2011 Annual Report on Form 10-K.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As of September 30, 2012, we carried out an evaluation under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as to the effectiveness, design and operation of our disclosure controls and procedures (as defined in the Securities Exchange Act of 1934, as amended (Exchange Act) Rules 13a-15(e) and 15d-15(e)). This evaluation considered the various processes carried out under the direction of our disclosure committee in an effort to ensure that information required to be disclosed in the SEC reports we file or submit under the Exchange Act is accurate, complete and timely. Our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our Chief Executive Officer and Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective as of September 30, 2012.

Changes in Internal Control Over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the three months ended September 30, 2012 that have materially affected, or are reasonable likely to materially affect our internal control over financial reporting.

PART II — OTHER INFORMATION

Item 1. Legal Proceedings

A description of our material legal proceedings is included in Part I. Financial Statements, Note 9.Commitments and Contingent Liabilitiesof this Quarterly Report, and is incorporated herein by reference.

Item 1A. Risk Factors

Important factors that could cause actual results to differ materially from estimates or projections contained in our forward-looking statements are described in our 2011 Annual Report on Form 10-K under Part I, Item 1A. Risk Factors, and Part II, Item 1A. Risk Factors in our Quarterly Report on Form 10-Q for the quarter ended March 31, 2012. There have been no material changes in our risk factors since that report.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

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.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

	CRESTWOOD MIDSTREAM PARTNERS LP
	By: CRESTWOOD GAS SERVICES GP LLC, its General Partner
Date: November 6, 2012	By:	/s/ William G. Manias
		William G. Manias
		Senior Vice President – Chief Financial Officer
		(Principal Financial Officer)
Date: November 6, 2012	By:	/s/ Steven M. Dougherty
		Steven M. Dougherty
		Vice President – Chief Accounting Officer
		(Principal Accounting Officer)

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EXHIBIT INDEX

Exhibits designated by an asterisk (*) are filed herewith and those with (**) are furnished and not filed herewith.

Exhibit No.	Description
*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

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