Crestwood Midstream Partners 10-Q 2013 Q2 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 June 30, 2013

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	x	Accelerated filer	¨
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 July 31, 2013
Common Units	53,766,588

CRESTWOOD MIDSTREAM PARTNERS LP

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1.      Financial Statements	5
Item 2.      Management’s Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.      Quantitative and Qualitative Disclosures About Market Risk	40
Item 4.      Controls and Procedures	40
PART II. OTHER INFORMATION
Item 1.      Legal Proceedings	41
Item 1A.   Risk Factors	41
Item 2.      Unregistered Sales of Equity Securities and Use of Proceeds	41
Item 3.      Defaults Upon Senior Securities	41
Item 4.      Mine Safety Disclosures	41
Item 5.      Other Information	41
Item 6.      Exhibits	41
Signatures	42
Exhibits	43

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FORWARD-LOOKING INFORMATION

In this report, unless the context requires otherwise, references to “we,” “us,” “our,” “CMLP,” 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 natural gas liquid (NGL) prices;

• the extent and success of drilling efforts, as well as the extent and quality of natural gas volumes produced within areas of acreage dedicated on and within the 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;

• the likelihood and timing of the completion of the proposed merger involving Inergy, L.P., Inergy Midstream, L.P. and certain of their affiliates;

• the terms and conditions of any required regulatory approvals of the proposed merger;

• the impact of the proposed merger on our employees and potential diversion of management’s time and attention from ongoing business during this period; 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 2012 Annual Report on Form 10-K, 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

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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						Six Months Ended
	June 30,						June 30,
	2013			2012(1)			2013			2012(1)
Operating revenues
Gathering revenues	$	24,103		$	17,761		$	48,099		$	29,598
Gathering revenues—related party		19,066			21,616			38,973			45,462
Processing revenues		3,926			1,198			7,974			2,394
Processing revenues—related party		5,515			6,550			11,197			13,321
Compression revenues		3,873			—			7,799			—
Product sales		14,616			8,104			29,473			18,187
Total operating revenues		71,099			55,229			143,515			108,962
Operating expenses
Product purchases		6,154			7,441			12,902			16,414
Product purchases—related party		7,878			—			14,635			—
Operations and maintenance		12,592			9,400			25,608			19,111
General and administrative		10,380			8,657			18,169			15,395
Depreciation, amortization and accretion		17,701			13,695			35,061			24,341
Total operating expenses		54,705			39,193			106,375			75,261
Operating income		16,394			16,036			37,140			33,701
Interest and debt expense		(11,185	)		(8,963	)		(22,635	)		(16,520	)
Income before income taxes		5,209			7,073			14,505			17,181
Income tax expense		339			275			677			578
Net income	$	4,870		$	6,798		$	13,828		$	16,603
General partner’s interest in net income	$	5,192		$	4,154		$	10,393		$	7,522
Limited partners’ interest in net income	$	(322	)	$	2,644		$	3,435		$	9,081
Basic earnings (loss) per unit:
Net income (loss) per limited partner unit	$	(0.01	)	$	0.06		$	0.06		$	0.21
Diluted earnings (loss) per unit:
Net income (loss) per limited partner unit	$	(0.01	)	$	0.06		$	0.06		$	0.21

⁽¹⁾  Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 2.

See accompanying notes.

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CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data)

(Unaudited)

	June 30,		December 31,
	2013		2012
ASSETS
Current assets
Cash and cash equivalents	$	110	$	111
Accounts receivable		21,772		21,636
Accounts receivable—related party		20,851		23,755
Insurance receivable		3,496		2,920
Prepaid expenses and other		1,476		1,941
Assets held for sale		6,680		—
Total current assets		54,385		50,363
Property, plant and equipment, net of accumulated depreciation of $153,421 in 2013 and $130,030 in 2012		1,016,770		939,846
Intangible assets, net of accumulated amortization of $23,821 in 2013 and $12,814 in 2012		490,503		501,380
Goodwill		95,031		95,031
Deferred financing costs, net		21,134		22,528
Other assets		2,107		1,321
Total assets	$	1,679,930	$	1,610,469
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accrued additions to property, plant and equipment	$	36,173	$	9,213
Capital leases		3,408		3,862
Deferred revenue		2,426		2,634
Accounts payable—related party		2,997		3,088
Accounts payable, accrued expenses and other liabilities		34,056		29,717
Total current liabilities		79,060		48,514
Long-term debt		778,944		685,161
Long-term capital leases		1,509		3,161
Asset retirement obligations		14,425		14,024
Commitments and contingent liabilities (Note 7)
Partners’ capital
Common unitholders (53,766,588 and 41,164,737 units issued and outstanding at June 30, 2013 and December 31, 2012)		676,214		442,348
Class C unitholders (7,165,819 units issued and outstanding at December 31, 2012)		—		159,908
Class D unitholder (6,341,707 units issued and outstanding at June 30, 2013)		126,644		—
General partner (1,112,674 and 979,614 units issued and outstanding at June 30, 2013 and December 31, 2012)		3,134		257,353
Total partners’ capital		805,992		859,609
Total liabilities and partners’ capital	$	1,679,930	$	1,610,469

See accompanying notes.

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CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended
	June 30,
	2013			2012(1)
Cash flows from operating activities
Net income	$	13,828		$	16,603
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion		35,061			24,341
Equity-based compensation		1,378			994
Other non-cash income items		2,067			2,546
Changes in assets and liabilities:
Accounts receivable		(136	)		245
Accounts receivable—related party		2,904			4,010
Insurance receivable		(576	)		—
Prepaid expenses and other assets		(321	)		(560	)
Accounts payable—related party		(91	)		(1,046	)
Accounts payable, accrued expenses and other liabilities		3,415			(4,919	)
Net cash provided by operating activities		57,529			42,214
Cash flows from investing activities
Capital expenditures		(80,297	)		(22,373	)
Acquisitions, net of cash acquired		—			(376,805	)
Other		20			—
Net cash used in investing activities		(80,277	)		(399,178	)
Cash flows from financing activities
Proceeds from credit facilities		316,900			244,700
Repayments of credit facilities		(223,000	)		(176,250	)
Payments on capital leases		(2,248	)		(1,375	)
Deferred financing costs paid		(82	)		(6,486	)
Proceeds from issuance of common units, net		118,562			103,034
Contributions from partners		—			247,163
Distribution to General Partner for additional interest in CMM		(129,000	)		—
Distributions to partners		(57,709	)		(45,471	)
Taxes paid for equity-based compensation vesting		(676	)		(402	)
Net cash provided by financing activities		22,747			364,913
Change in cash and cash equivalents		(1	)		7,949
Cash and cash equivalents at beginning of period		111			797
Cash and cash equivalents at end of period	$	110		$	8,746

⁽¹⁾  Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 2.

See accompanying notes.

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CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(In thousands)

(Unaudited)

	Limited Partners
	Common			Class C Unitholders			Class D Unitholder		General Partner			Total
Partners’ capital as of December 31, 2012	$	442,348		$	159,908		$	—	$	257,353		$	859,609
Issuance of units, net of offering costs		118,562			—			—		—			118,562
Issuance of units		—			—			126,286		(126,286	)		—
Conversion of Class C units to Common units		159,908			(159,908	)		—		—			—
Net income		3,077			—			358		10,393			13,828
Equity-based compensation		1,378			—			—		—			1,378
Taxes paid for equity-based compensation vesting		(676	)		—			—		—			(676	)
Distributions to partners		(48,383	)		—			—		(9,326	)		(57,709	)
Distribution to General Partner for additional interest in CMM		—			—			—		(129,000	)		(129,000	)
Partners’ capital as of June 30, 2013	$	676,214		$	—		$	126,644	$	3,134		$	805,992
	Limited Partners
	Common			Class C Unitholders			Class D Unitholder		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		103,034			—			—		—			103,034
Contributions from partners		—			—			—		247,163			247,163
Net income		7,664			1,417					7,522			16,603
Equity-based compensation		994			—			—		—			994
Taxes paid for equity-based compensation vesting		(402	)		—			—		—			(402	)
Distributions to partners		(36,172	)		—			—		(9,299	)		(45,471	)
Partners’ capital as of June 30, 2012(1)	$	362,063		$	158,803		$	—	$	256,678		$	777,544

⁽¹⁾  Financial information has been revised to include the results of Crestwood Marcellus Midstream LLC as discussed in Note 2.

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. Our common units are listed on the New York Stock Exchange (NYSE) under the symbol “CMLP.” Prior to June 19, 2013, Crestwood Gas Services GP LLC, our general partner (General Partner), was owned by Crestwood Holdings Partners LLC and its affiliates (Crestwood Holdings). On June 5, 2013, our General Partner distributed all of its common units and Class D units that it owned in us to Crestwood Holdings. On June 19, 2013, Crestwood Holdings acquired the general partner of Inergy, L.P. (NRGY) and contributed its ownership of our General Partner and incentive distribution rights to NRGY in exchange for NRGY common units.

On May 5, 2013, we entered into a definitive merger agreement under which we will be merged with a subsidiary of Inergy Midstream, L.P. (NRGM) in a merger in which our unitholders receive 1.07 units of NRGM for each unit of CMLP they own. Additionally, under the merger agreement, our unitholders (other than Crestwood Holdings) will receive a one-time approximately $35 million cash payment at closing of the merger transaction, or $1.03 per unit, $25 million of which will be payable by NRGM and approximately $10 million of which will be payable by Crestwood Holdings. The merger of NRGM and CMLP is conditioned upon the approval of the holders of a majority of the limited partner interests of CMLP and other customary closing conditions.

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Organizational Structure

The following chart depicts our ownership structure as of June 30, 2013:

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Our general partner and limited partner ownership interests as of June 30, 2013 is as follows:

	Crestwood Holdings			Public			Total
General partner interest		1.8	%		—			1.8	%
Limited partner interests:
Common unitholders		32.1	%		55.7	%		87.8	%
Class D unitholder		10.4	%		—			10.4	%
Total		44.3	%		55.7	%		100.0	%

Description of Business

We are a growth-oriented midstream master limited partnership which owns and operates predominately fee-based gathering, processing, treating and compression assets servicing producers in the Marcellus Shale in northern West Virginia, the Barnett Shale in north Texas, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Avalon Shale/Bone Spring in southeastern New Mexico and the Haynesville/Bossier Shale in western Louisiana.

2. BASIS OF PRESENTATION AND 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.

On March 26, 2012, Crestwood Holdings contributed approximately $244 million for a 65% membership interest in Crestwood Marcellus Midstream LLC (CMM) and we contributed approximately $131 million for a 35% membership interest in CMM. On January 8, 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM and as a result, we now own 100% of CMM and have the ability to control the operating and financial decisions of CMM. We accounted for this transaction as a reorganization of entities under common control and the accounting standards related to such transactions require us to retroactively adjust our historical results. Accordingly, the consolidated balance sheets reflect the historical carrying value of CMM’s assets and liabilities. Earnings related to the recast of our historical results due to the acquisition of the 65% membership interest in CMM were allocated to the General Partner. As a result, there was no impact to our 2012 reported basic or diluted earnings per limited partner unit. We funded the purchase price for the 65% membership interest in CMM of approximately $258 million through $129 million of borrowings under our CMLP credit facility, the issuance of 6,190,469 Class D units, representing limited partner interests in us to Crestwood Holdings, and the issuance of 133,060 general partner units to our General Partner. For accounting purposes, because of the consolidation of CMM, we reflected the $129 million cash paid to acquire the 65% interest in CMM and the issuance of Class D units as a reduction of our General Partner’s capital.

You should read this Quarterly Report on Form 10-Q along with our Form 8-K filed with the SEC on May 10, 2013. The financial statements as of June 30, 2013 and for the three and six months ended June 30, 2013 and 2012 are unaudited. The consolidated balance sheet as of December 31, 2012, was derived from the audited balance sheet filed in our Form 8-K filed with the SEC on May 10, 2013. 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. 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 Form 8-K filed with the SEC on May 10, 2013.

Significant Accounting Policies

There were no changes in the significant accounting policies described in our 2012 Annual Report on Form 10-K filed with the SEC on February 27, 2013, except as noted below.

Revenues

Our revenues are generated from the gathering, compression and processing of natural gas from producers predominately under fee-based contracts. Our gathering revenues relate to contracts pursuant to which we both transport and compress natural gas based on the volumes that flow through our systems and are not directly dependent on commodity prices. Compression revenues relate to contracts under which we solely provide compression services or contracts under which we charge a compression services fee that is

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separate from other services provided under our contracts. For the three and six months ended June 30, 2013, our compression revenues were entirely comprised of services provided under contracts obtained in the E. Marcellus Asset Company, LLC (EMAC) acquisition (See Note 3). Under our processing contracts, raw natural gas is gathered, processed and sold at published index prices. Producers are paid based on an agreed percentage of the residue gas and NGLs multiplied by index prices or the actual sale prices.

3. ACQUISITIONS AND DIVESTITURES

Acquisitions

Antero Acquisition

On February 27, 2012, we announced the execution, through CMM, of an Asset Purchase Agreement related to the acquisition of gathering assets owned by Antero Resources Appalachian Corporation (Antero) in the Marcellus Shale located in Harrison and Doddridge Counties, West Virginia (Antero Acquisition), and, at closing, the planned execution of a 20 year, fixed-fee, Gas Gathering and Compression Agreement (GGA) with Antero. On March 26, 2012, CMM completed the Antero Acquisition for approximately $380 million. The assets acquired by CMM consisted of a 33 mile low pressure gathering system which delivers Antero’s Marcellus Shale production to various regional pipeline systems including Columbia, Dominion, Equitrans and MarkWest Energy Partners’ Sherwood Gas Processing Plant.

The GGA with Antero provides for an area of dedication at the time of acquisition 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. As part of the GGA, Antero committed to deliver minimum annual throughput volumes to us for a seven year period from January 1, 2012 to January 1, 2019, ranging from an average of 300 million cubic feet per day (MMcf/d) in 2012 to an average of 450 MMcf/d in 2018. During the period ended December 31, 2012, Antero delivered less than the minimum annual throughput volumes and at December 31, 2012, we recorded a receivable and deferred revenue of approximately $2.6 million due to Antero’s potential ability to recover this amount if Antero’s 2013 throughput volumes exceed the minimum annual throughput volumes included in the GGA for 2013.

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

Cash	$	381,718
Total purchase price	$	381,718
Purchase price allocation:
Property, plant and equipment	$	90,562
Intangible assets		291,218
Total assets	$	381,780
Asset retirement obligation	$	62
Total liabilities	$	62
Total	$	381,718

Our intangible assets recorded as a result of the Antero Acquisition relate to the GGA with Antero. These intangible assets will be amortized over the life of the contract. For the period from the acquisition date (March 26, 2012) to June 30, 2012, we recorded approximately $ 7 million of operating revenues and $5 million of operating expenses related to the operations of the assets acquired from Antero.

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 final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed.

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The preliminary purchase price allocation is as follows (In thousands):

Cash	$	87,247
Total purchase price	$	87,247
Preliminary purchase price allocation:
Property, plant and equipment	$	41,555
Intangible assets		46,959
Total assets	$	88,514
Asset retirement obligation	$	540
Property tax liability		527
Environmental liability		200
Total liabilities	$	1,267
Total	$	87,247

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.

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.

EMAC Acquisition

On December 28, 2012, CMM acquired all of the membership interest of EMAC from Enerven Compression, LLC (Enerven) for approximately $95 million. We financed this acquisition through our CMM credit facility. At the time of acquisition, EMAC’s assets consisted of four compression and dehydration stations located on our gathering systems in Harrison County, West Virginia. These assets provide compression and dehydration services to Antero under a compression services agreement through 2018. Antero has the option to renew the agreement for an additional five years upon expiration of the original agreement. The final purchase price allocation is pending the completion of the valuation of the assets acquired and liabilities assumed.

The preliminary purchase price allocation is as follows (In thousands):

Cash	$	95,000
Total purchase price	$	95,000
Preliminary purchase price allocation:
Property, plant and equipment	$	45,938
Intangible assets		49,817
Total assets	$	95,755
Asset retirement obligation	$	755
Total liabilities	$	755
Total	$	95,000

Our intangible assets recorded as a result of the EMAC acquisition relate to the compression services agreements with Antero. These intangible assets will be amortized over the life of the contract. Pro forma information has not been provided for the acquisition of the EMAC assets as the impact is immaterial to our financial statements.

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Divestitures

On July 25, 2013, we sold a cryogenic plant and associated equipment for approximately $11 million, net of fees. At June 30, 2013, we have classified these assets as held for sale at their historical book value of approximately $7 million.

4. NET INCOME PER LIMITED PARTNER UNIT AND DISTRIBUTIONS

Earnings Per Limited Partner Unit. Our net income is allocated to the General Partner and the limited partners, in accordance with their respective ownership percentages, after giving effect to incentive distributions paid to the General Partner. To the extent cash distributions exceed net income, the excess distributions are allocated proportionately to all participating units outstanding based on their respective ownership percentages. Basic earnings per unit are computed by dividing net income attributable to limited partner unitholders by the weighted-average number of limited partner units outstanding during each period. Diluted earnings per unit are computed using the treasury stock method, which considers the impact to net income and limited partner units from the potential issuance of limited partner units.

The tables below show the (i) allocation of net income attributable to limited partners and the (ii) net income per limited partner unit based on the number of basic and diluted limited partner units outstanding for the three and six months ended June 30, 2013 and 2012.

Allocation of Net Income to General Partner and Limited Partners

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
	(In thousands)
Net income	$	4,870		$	6,798		$	13,828		$	16,603
General Partner’s incentive distributions		(5,104	)		(3,280	)		(10,140	)		(6,535	)
Net income (loss) after incentive distributions		(234	)		3,518			3,688			10,068
General Partner’s interest in net income after incentive distributions		(88	)		(874	)		(253	)		(987	)
Limited Partners’ interest in net income (loss) after distributions	$	(322	)	$	2,644		$	3,435		$	9,081

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Net Income Per Limited Partner Unit

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2013			2012		2013		2012
	(In thousands, except per unit data)
Limited partners’ interest in net income	$	(322	)	$	2,644	$	3,435	$	9,081
Weighted-average limited partner units—basic(1)		60,004			43,333		57,400		43,014
Effect of unvested phantom units		—			201		273		190
Weighted-average limited partner units—diluted(1)		60,004			43,534		57,673		43,204
Basic earnings (loss) per unit:
Net income (loss) per limited partner	$	(0.01	)	$	0.06	$	0.06	$	0.21
Diluted earnings (loss) per unit:
Net income (loss) per limited partner	$	(0.01	)	$	0.06	$	0.06	$	0.21

⁽¹⁾  The three months ended June 30, 2013 includes 6,275,229 Class D units. The six months ended June 30, 2013 includes 9,610,969 Class C and Class D units. The three and six months ended June 30, 2012 includes 6,791,526 and 6,727,074 Class C units.

There were 274 unvested phantom units excluded from our diluted earnings per unit as our limited partners’ interest in net income was a loss for the three months ended June 30, 2013. There were no units excluded from our diluted earnings per unit as we do not have any anti-dilutive units for the six months ended June 30, 2013 and the three and six months ended June 30, 2012.

Distributions. Our Second Amended and Restated Agreement of Limited Partnership, dated February 19, 2008, as amended (Partnership Agreement), 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 2013 and 2012 (In millions, except per unit data):

				Distributions Paid
				Limited Partner						General Partner
Payment Date	Attributable to the Quarter Ended	Per  Unit Distribution		Cash paid to common(1)		Paid-In-Kind Value to Class C unitholders		Paid-In-Kind Value to Class D unitholder		Cash paid to  General Partner and IDR		Paid-In-Kind Value to Class C unitholder		Paid-In-Kind Value to Class D unitholder		Total Cash		Total Distribution
2013
August 9, 2013	June 30, 2013	$	0.51	$	27.5	$	—	$	3.2	$	5.2	$	—	$	0.5	$	32.7	$	36.4
May 10, 2013	March 31, 2013	$	0.51	$	27.4	$	—	$	3.2	$	5.2	$	—	$	0.5	$	32.6	$	36.3
February 12, 2013	December 31, 2012	$	0.51	$	21.0	$	3.7	$	—	$	4.1	$	0.6	$	—	$	25.1	$	29.4
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

⁽¹⁾  Distributions for the quarter ended June 30, 2012 exclude approximately $3 million paid by CMM to Crestwood Holdings.

Our Class D units are substantially similar in all respects to our existing common units, representing limited partner interests, except that we have the option to pay distributions to our Class D unitholders with cash or by issuing additional Paid-In-Kind Class D 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. We issued 151,238 additional Class D units in lieu of paying cash quarterly distributions on our Class D units attributable to the quarter ended March 31, 2013.

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On April 1, 2013, our outstanding Class C units converted to common units on a one-for-one basis. Prior to the conversion of our Class C units to common, we had the options 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. The unitholders of the converted units received a quarterly cash distribution for the period ended March 31, 2013 although the Class C units were not converted until April 1, 2013. We issued 136,128 and 138,731 additional Class C units in lieu of paying cash quarterly distributions on our Class C units attributable to the quarters ended March 31, 2012 and June 30, 2012.

On March 22, 2013, we completed a public offering of 4,500,000 common units, representing limited partner interests in us, at a price of $23.90 per common unit ($23.00 per common unit, net of underwriting discounts) providing net proceeds of approximately $103.5 million. We granted the underwriters a 30-day option to purchase up to 675,000 additional common units if the underwriters sold more than 4,500,000 common units in the offering. The underwriters exercised this option on April 5, 2013 providing net proceeds of approximately $15.5 million. The unitholders of these common units received a quarterly distribution for the period ended March 31, 2013. In connection with the issuance of the common units, our General Partner did not make an additional capital contribution to us resulting in a reduction in their general partner interest in us to approximately 1.8% at June 30, 2013.

See our 2012 Annual Report on Form 10-K for additional information regarding our distributions.

5. FINANCIAL INSTRUMENTS

Fair Values

We separate the fair values of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instrument and would be reflected at the end of the period in which the change occurs. At June 30, 2013 and December 31, 2012, there have been no changes to the inputs and valuation techniques used to measure fair value, the types of instruments, or the levels in which they are classified.

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable. As of June 30, 2013 and December 31, 2012, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair value based on the short-term nature of these instruments.

Credit Facilities. The fair value of our credit facilities approximates their carrying amounts as of June 30, 2013 and December 31, 2012 due primarily to the variable nature of the interest rate of the instrument, which is considered a Level 2 fair value measurement.

Senior Notes. We estimated the fair value of our 7.75% Senior Notes due April 2019 (Senior Notes) (representing a Level 2 fair value measurement) primarily based on quoted market prices for the same or similar issuances. The following table reflects the carrying value and fair value of our Senior Notes (In millions):

	June 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior Notes	$	351	$	362	$	351	$	365

Debt

Our long-term debt consists of the following (In thousands):

	June 30, 2013		December 31, 2012
CMM Credit Facility, due March 2017	$	127,400	$	127,000
CMLP Credit Facility, due November 2017		300,200		206,700
Senior Notes, due April 2019		350,000		350,000
		777,600		683,700
Plus: Unamortized premium on Senior Notes		1,344		1,461
Total long-term debt	$	778,944	$	685,161

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Credit Facilities

CMM Credit Facility. The CMM credit agreement, dated March 26, 2012 (CMM Credit Facility) allows for revolving loans, letters of credit and swingline loans in an aggregate principal amount of up to $200 million. The CMM Credit Facility is secured by substantially all of CMM’s assets.

Borrowings under the CMM Credit Facility bear interest at the London Interbank Offered Rate (LIBOR) plus an applicable margin or base rate as defined in the CMM Credit Facility. Under the terms of the CMM Credit Facility, the applicable margin under LIBOR was 2.5% at both June 30, 2013 and December 31, 2012. The weighted-average interest rate at both June 30, 2013 and December 31, 2012 was 2.8%. Based on our results through June 30, 2013, our remaining available capacity under the CMM Credit Facility was $73 million. For the three and six months ended June 30, 2013, our average outstanding borrowings were approximately $102 million and $112 million. For the three and six months ended June 30, 2013, our maximum outstanding borrowings were approximately $127 million and $130 million.

The CMM Credit Facility requires CMM to maintain:

• a ratio of trailing 12-month EBITDA (as defined in the CMM Credit Facility) to net interest expense of not less than 2.0 to 1.0; and

• a ratio of total indebtedness to trailing 12-month EBITDA (as defined in the CMM Credit Facility) of not more than 4.5 to 1.0, or not more than 5.0 to 1.0 for up to nine months following certain acquisitions.

CMLP Credit Facility. Our amended and restated senior secured credit agreement, dated November 16, 2012 (CMLP Credit Facility), allows for revolving loans, letters of credit and swingline loans in an aggregate amount of up to $550 million. The CMLP Credit Facility is secured by substantially all of CMLP’s assets and those of certain of its subsidiaries. As of June 30, 2013, the CMLP Credit Facility is guaranteed by our 100% owned subsidiaries except for CMM and its consolidated subsidiaries.

Borrowings under the CMLP Credit Facility bear interest at LIBOR plus an applicable margin or a base rate as defined in the CMLP Credit Facility. Under the terms of the CMLP Credit Facility, the applicable margin under LIBOR borrowings was 2.8% and 2.5% at June 30, 2013 and December 31, 2012. The weighted-average interest rate as of June 30, 2013 and December 31, 2012 was 3.0% and 2.8%. Based on our results through June 30, 2013, our remaining available capacity under the CMLP Credit Facility was $111 million. For the three and six months ended June 30, 2013, our average outstanding borrowings were $312 million and $324 million. For the three and six months ended June 30, 2013, our maximum outstanding borrowings were $328 million and $373 million.

Our CMLP Credit Facility requires us to maintain:

• a ratio of our consolidated trailing 12-month EBITDA (as defined in the CMLP 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 CMLP 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 June 30, 2013, we were in compliance with the financial covenants under each of the CMM and CMLP Credit Facilities.

Our credit facilities contain 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 our credit facilities, the termination of our credit facilities and foreclosure on collateral.

Senior Notes

In November 2012, we issued $150 million aggregate principal amount of 7.75% Senior Notes in a private placement offering. These notes were issued as additional notes under the indenture dated April 1, 2011 among us, Crestwood Midstream Finance Corporation, the guarantors names therein, and The Bank of New York Mellon Trust Company, N.A., as trustee, pursuant to which we previously issued our $200 million aggregate principal amount of 7.75% Senior Notes in April 2011. 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 June 30, 2013, we were in compliance with this covenant. For additional information regarding our Senior Notes, see our 2012 Annual Report on Form 10-K.

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6. ACCOUNTS PAYABLE, ACCRUED EXPENSES AND OTHER LIABILITIES

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

	June 30, 2013		December 31, 2012
Accrued expenses	$	9,232	$	9,608
Accrued property taxes		4,713		5,638
Accrued product purchases payable		2,014		2,450
Tax payable		1,297		2,159
Interest payable		7,791		7,505
Accounts payable		8,914		2,278
Other		95		79
Total accounts payable, accrued expenses and other liabilities	$	34,056	$	29,717

7. COMMITMENTS AND CONTINGENT LIABILITIES

Legal Proceedings

Class Action Lawsuits.Five putative class action lawsuits challenging the Crestwood-Inergy merger have been filed, four in federal court in the United States District Court for the Southern District of Texas: (i) Abraham Knoll v. Robert G. Phillips, et al. (Case No. 4:13-cv-01528); (ii) Greg Podell v. Crestwood Midstream Partners, LP, et al. (Case No. 4:13-cv-01599); (iii) Johnny Cooper v. Crestwood Midstream Partners LP, et al. (Case No. 4:13-cv-01660); and (iv) Steven Elliot LLC v. Robert G. Phillips, et al. (Case No. 4:13-cv-01763), and one in Delaware Chancery Court,Hawley v. Crestwood Midstream Partners LP, et al. (Case No. 8689-VCL). All of the cases name Crestwood, Crestwood Gas Services GP LLC, Crestwood Holdings LLC, the current and former directors of Crestwood Gas Services GP LLC, Inergy, L.P., Inergy Midstream, L.P., NRGM GP, LLC, and Intrepid Merger Sub, LLC as defendants. All of the suits are brought by a purported holder of common units of Crestwood, both individually and on behalf of a putative class consisting of holders of common units of Crestwood. The lawsuits generally allege, among other things, that the directors of Crestwood Gas Services GP LLC breached their fiduciary duties to holders of common units of Crestwood by agreeing to a transaction with inadequate consideration and unfair terms and pursuant to an inadequate process. The lawsuits further allege that Inergy, L.P., Inergy Midstream, L.P., NRGM GP, LLC, and Intrepid Merger Sub, LLC aided and abetted the Crestwood directors in the alleged breach of their fiduciary duties. The lawsuits seek, in general, (i) injunctive relief enjoining the merger, (ii) in the event the merger is consummated, rescission or an award of rescissory damages, (iii) an award of plaintiffs’ costs, including reasonable attorneys’ and experts’ fees, (iv) the accounting by the defendants to plaintiffs for all damages caused by the defendants, and (v) such further equitable relief as the court deems just and proper. Certain of the actions also assert claims of inadequate disclosure under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934, and the Elliot case also names Citigroup Global Markets Inc. as an alleged aider and abettor. The plaintiff in the Hawley action in Delaware filed a motion for expedited proceedings but subsequently withdrew that motion and then filed a stipulation voluntarily dismissing the action without prejudice, which has been granted by the Court, such that the Hawley action has now been dismissed. The plaintiffs in the Knoll, Podell, Cooper, and Elliot actions filed an unopposed motion to consolidate these four cases, which the Court granted. The plaintiff in the Elliot action filed a motion for expedited discovery, which remains pending. These lawsuits are at a preliminary stage. Crestwood, Inergy Midstream and the other defendants believe that these lawsuits are without merit and intend to defend against them vigorously.

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 June 30, 2013, we had no amounts accrued for our legal proceedings. At December 31, 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

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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 June 30, 2013 and December 31, 2012, we had accrued approximately $0.3 million and $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 $0.3 million to $0.4 million.

8. 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 responsible for our portion of the Texas Margin tax that is included in Crestwood Holdings’ consolidated Texas franchise tax return. 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 Form 8-K filed with the SEC on May 10, 2013 for more information about our income taxes.

9. 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 phantom and restricted unit activity during the six months ended June 30, 2013:

	Payable In Cash					Payable In Units
	Units			Weighted- Average Grant Date Fair Value		Units			Weighted- Average Grant Date Fair Value
Unvested—January 1, 2013		8,312		$	26.45		221,992		$	28.35
Vested—phantom units		(518	)	$	27.72		(71,006	)	$	28.70
Vested—restricted units		—			—		(8,015	)	$	27.47
Granted—phantom units		—			—		161,807		$	24.33
Granted—restricted units		—			—		27,900		$	24.86
Canceled—phantom units		(354	)	$	25.81		(7,114	)	$	27.96
Unvested—June 30, 2013		7,440		$	26.39		325,564		$	25.99

As of June 30, 2013 and December 31, 2012, we had total unamortized compensation expense of approximately $5 million and $3 million related to phantom and restricted units, which we expect will be amortized over three years (the original vesting period of these instruments), except for grants to non-employee directors of our General Partner which vest over one year. Upon the occurrence of certain events, such as a change in control, the vesting period of our phantom and restricted units could be accelerated. We recognized compensation expense of approximately $1.4 million and $1.0 million during the six months ended June 30, 2013 and 2012, 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 six months ended June 30, 2013. As of June 30, 2013, we had 345,067 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 six months ended June 30, 2013 and 2012, we withheld 2,429 common units and 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.

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10. TRANSACTIONS WITH RELATED PARTIES

We enter into transactions with our affiliates within the ordinary course of business. For a further discussion of our affiliated transactions, see our 2012 Annual Report on Form 10-K. Reimbursements from our affiliates were less than $1 million for the three and six months ended June 30, 2013 and 2012. The following table shows revenues and expenses from our affiliates for the three and six months ended June 30, 2013 and 2012 (In millions):

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Operating revenues	$	24	$	28	$	50	$	59
Operating expenses		13		5		26		10

11. SEGMENT INFORMATION

We conduct our operations in the midstream sector with eight operating segments, four of which are reportable 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 and income tax expense.

Our reportable segments reflect the primary geographic areas in which we operate and consist of Marcellus, Barnett, Fayetteville and Granite Wash, 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. Our Other operating segment consists of those operating segments or reporting units that did not meet quantitative reporting thresholds.

For the six months ended June 30, 2013 and 2012, one of our customers in the Barnett segment, which is a related party, accounted for approximately 34% and 54% of our total revenues in the Barnett segment. In our Marcellus segment, one customer accounted for approximately 21% of our revenues for the six months ended June 30, 2013. In addition, in our Fayetteville segment, one customer accounted for approximately 10% of our total revenues for the six months ended June 30, 2012.

The following table is a reconciliation of net income to EBITDA (In thousands):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2013		2012		2013		2012
Net income	$	4,870	$	6,798	$	13,828	$	16,603
Add:
Interest and debt expense		11,185		8,963		22,635		16,520
Income tax expense		339		275		677		578
Depreciation, amortization and accretion expense		17,701		13,695		35,061		24,341
EBITDA	$	34,095	$	29,731	$	72,201	$	58,042

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The following tables summarize the reportable segment data for the three and six months ended June 30, 2013 and 2012 (In thousands):

	Three Months Ended June 30, 2013
	Marcellus		Barnett		Fayetteville		Granite Wash		Other		Corporate			Total
Operating revenues	$	15,309	$	8,994	$	6,331	$	13,221	$	2,663	$	—		$	46,518
Operating revenues—related party		88		24,078		—		415		—		—			24,581
Product purchases		—		146		190		4,614		1,204		—			6,154
Product purchases—related party		—		—		—		7,878		—		—			7,878
Operations and maintenance expense		2,545		6,312		2,310		685		740		—			12,592
General and administrative expense		—		—		—		—		—		10,380			10,380
EBITDA	$	12,852	$	26,614	$	3,831	$	459	$	719	$	(10,380	)	$	34,095
Goodwill	$	—	$	—	$	76,767	$	14,211	$	4,053	$	—		$	95,031
Total assets	$	587,434	$	604,447	$	298,902	$	81,875	$	79,328	$	27,944		$	1,679,930
Capital expenditures	$	48,468	$	3,210	$	1,756	$	1,604	$	915	$	71		$	56,024

	Three Months Ended June 30, 2012
	Marcellus		Barnett		Fayetteville		Granite Wash		Other		Corporate			Total
Operating revenues	$	7,027	$	3,337	$	6,330	$	7,722	$	2,647	$	—		$	27,063
Operating revenues—related party		—		28,166		—		—		—		—			28,166
Product purchases		—		—		124		6,732		585		—			7,441
Operations and maintenance expense		513		5,345		2,231		541		770		—			9,400
General and administrative expense		—		—		—		—		—		8,657			8,657
EBITDA	$	6,514	$	26,158	$	3,975	$	449	$	1,292	$	(8,657	)	$	29,731
Goodwill	$	—	$	—	$	76,767	$	14,211	$	—	$	—		$	90,978
Total assets	$	427,692	$	537,333	$	305,767	$	77,031	$	82,774	$	17,301		$	1,447,898
Capital expenditures	$	838	$	4,132	$	886	$	675	$	2,660	$	293		$	9,484

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	Six Months Ended June 30, 2013
	Marcellus		Barnett		Fayetteville		Granite Wash		Other		Corporate			Total
Operating revenues	$	29,583	$	18,390	$	13,584	$	26,635	$	5,153	$	—		$	93,345
Operating revenues—related party		88		49,232		—		850		—		—			50,170
Product purchases		—		401		483		10,064		1,954		—			12,902
Product purchases—related party		—		—		—		14,635		—		—			14,635
Operations and maintenance expense		4,942		13,567		4,444		1,293		1,362		—			25,608
General and administrative expense		—		—		—		—		—		18,169			18,169
EBITDA	$	24,729	$	53,654	$	8,657	$	1,493	$	1,837	$	(18,169	)	$	72,201
Goodwill	$	—	$	—	$	76,767	$	14,211	$	4,053	$	—		$	95,031
Total assets	$	587,434	$	604,447	$	298,902	$	81,875	$	79,328	$	27,944		$	1,679,930
Capital expenditures	$	64,721	$	8,769	$	2,712	$	2,523	$	1,160	$	412		$	80,297

	Six Months Ended June 30, 2012
	Marcellus		Barnett		Fayetteville		Granite Wash		Other		Corporate			Total
Operating revenues	$	7,027	$	6,663	$	13,194	$	17,319	$	5,976	$	—		$	50,179
Operating revenues—related party		—		58,783		—		—		—		—			58,783
Product purchases		—		—		206		15,033		1,175		—			16,414
Operations and maintenance expense		513		11,475		4,544		1,059		1,520		—			19,111
General and administrative expense		—		—		—		—		—		15,395			15,395
EBITDA	$	6,514	$	53,971	$	8,444	$	1,227	$	3,281	$	(15,395	)	$	58,042
Goodwill	$	—	$	—	$	76,767	$	14,211	$	—	$	—		$	90,978
Total assets	$	427,692	$	537,333	$	305,767	$	77,031	$	82,774	$	17,301		$	1,447,898
Capital expenditures	$	838	$	5,999	$	8,954	$	1,963	$	4,185	$	434		$	22,373

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12. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

The CMLP Credit Facility and our Senior Notes are fully and unconditionally guaranteed, jointly and severally, by CMLP’s present and future direct and indirect 100% owned subsidiaries (the Guarantor Subsidiaries), except for CMM and its consolidated subsidiaries (the Non-Guarantor Subsidiaries). CMLP (Issuer) issued the Senior Notes together with Crestwood Midstream Finance Corporation (Co-Issuer). The Co-Issuer is our 100% owned subsidiary and has no material assets, operations, revenues or cash flows other than those related to its service as co-issuer of our Senior Notes. Accordingly, it has no ability to service obligations on our debt securities.

The following reflects condensed consolidating financial information of the Issuer, Co-Issuer, Guarantor Subsidiaries, Non-Guarantor Subsidiaries, eliminating entries to combine the entities and our consolidated results as of June 30, 2013 and December 31, 2012 and for the three and six months ended June 30, 2013 and 2012.

	For the Three Months Ended June 30, 2013
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Operating revenues	$	—		$	—	$	55,790		$	15,309		$	—		$	71,099
Operating expenses		202			—		46,709			7,794			—			54,705
Operating income (loss)		(202	)		—		9,081			7,515			—			16,394
Interest and debt expense		(10,108	)		—		(61	)		(1,016	)		—			(11,185	)
Income (loss) before income tax		(10,310	)		—		9,020			6,499			—			5,209
Income tax expense		—			—		339			—			—			339
Income (loss) before earnings from consolidated subsidiaries		(10,310	)		—		8,681			6,499			—			4,870
Earnings (loss) from consolidated subsidiaries		15,180			—		—			—			(15,180	)		—
Net income (loss)		4,870			—		8,681			6,499			(15,180	)		4,870
General partner’s interest in net income		5,192			—		—			—			—			5,192
Limited partner’s interest in net income (loss)	$	(322	)	$	—	$	8,681		$	6,499		$	(15,180	)	$	(322	)

	For the Three Months Ended June 30, 2012
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Operating revenues	$	—		$	—	$	48,202		$	7,027		$	—		$	55,229
Operating expenses		179			—		33,923			5,091			—			39,193
Operating income (loss)		(179	)		—		14,279			1,936			—			16,036
Interest and debt expense		(8,242	)		—		(44	)		(677	)		—			(8,963	)
Income (loss) before income tax		(8,421	)		—		14,235			1,259			—			7,073
Income tax expense		—			—		275			—			—			275
Income (loss) before earnings from consolidated subsidiaries		(8,421	)		—		13,960			1,259			—			6,798
Earnings (loss) from consolidated subsidiaries		15,219			—		—			—			(15,219	)		—
Net income (loss)		6,798			—		13,960			1,259			(15,219	)		6,798
General partner’s interest in net income		4,154			—		—			—			—			4,154
Limited partner’s interest in net income (loss)	$	2,644		$	—	$	13,960		$	1,259		$	(15,219	)	$	2,644

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	For the Six Months Ended June 30, 2013
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Operating revenues	$	—		$	—	$	113,932		$	29,583		$	—		$	143,515
Operating expenses		394			—		89,815			16,166			—			106,375
Operating income (loss)		(394	)		—		24,117			13,417			—			37,140
Interest and debt expense		(20,213	)		—		(133	)		(2,289	)		—			(22,635	)
Income (loss) before income tax		(20,607	)		—		23,984			11,128			—			14,505
Income tax expense		—			—		677			—			—			677
Income (loss) before earnings from consolidated subsidiaries		(20,607	)		—		23,307			11,128			—			13,828
Earnings (loss) from consolidated subsidiaries		34,435			—		—			—			(34,435	)		—
Net income (loss)		13,828			—		23,307			11,128			(34,435	)		13,828
General partner’s interest in net income		10,393			—		—			—			—			10,393
Limited partner’s interest in net income (loss)	$	3,435		$	—	$	23,307		$	11,128		$	(34,435	)	$	3,435

	For the Six Months Ended June 30, 2012
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Operating revenues	$	—		$	—	$	101,935		$	7,027		$	—		$	108,962
Operating expenses		218			—		69,952			5,091			—			75,261
Operating income (loss)		(218	)		—		31,983			1,936			—			33,701
Interest and debt expense		(15,749	)		—		(94	)		(677	)		—			(16,520	)
Income (loss) before income tax		(15,967	)		—		31,889			1,259			—			17,181
Income tax expense		—			—		578			—			—			578
Income (loss) before earnings from consolidated subsidiaries		(15,967	)		—		31,311			1,259			—			16,603
Earnings (loss) from consolidated subsidiaries		32,570			—		—			—			(32,570	)		—
Net income (loss)		16,603			—		31,311			1,259			(32,570	)		16,603
General partner’s interest in net income		7,522			—		—			—			—			7,522
Limited partner’s interest in net income (loss)	$	9,081		$	—	$	31,311		$	1,259		$	(32,570	)	$	9,081

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	As of June 30, 2013
	Issuer		Co-Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	84	$	—	$	—	$	26	$	—		$	110
Accounts receivable		6,266		—		10,365		5,141		—			21,772
Accounts receivable—related party		407,884		1		20,797		—		(407,831	)		20,851
Insurance receivable		—		—		3,496		—		—			3,496
Prepaid expenses and other		968		—		508		—		—			1,476
Assets held for sale		—		—		6,680		—		—			6,680
Total current assets		415,202		1		41,846		5,167		(407,831	)		54,385
Investment in consolidated affiliates		1,042,846		—		—		—		(1,042,846	)		—
Property, plant and equipment—net		3,152		—		799,205		214,413		—			1,016,770
Intangible assets—net		—		—		156,930		333,573		—			490,503
Goodwill		—		—		95,031		—		—			95,031
Deferred financing costs, net		16,388		—		—		4,746		—			21,134
Other assets		1,032		—		1,075		—		—			2,107
Total assets	$	1,478,620	$	1	$	1,094,087	$	557,899	$	(1,450,677	)	$	1,679,930
LIABILITIES AND PARTNERS’ CAPITAL/MEMBERS’ EQUITY
Current liabilities
Accrued additions to property, plant and equipment	$	—	$	—	$	24,002	$	12,171	$	—		$	36,173
Capital leases		402		—		3,006		—		—			3,408
Deferred revenue		—		—		—		2,426		—			2,426
Accounts payable—related party		868		—		409,888		72		(407,831	)		2,997
Accounts payable, accrued expenses and other liabilities		19,042		—		8,293		6,721		—			34,056
Total current liabilities		20,312		—		445,189		21,390		(407,831	)		79,060
Long-term debt		651,544		—		—		127,400		—			778,944
Long-term capital leases		772		—		737		—		—			1,509
Asset retirement obligations		—		—		13,564		861		—			14,425
Partners’/members’ equity		805,992		1		634,597		408,248		(1,042,846	)		805,992
Total liabilities and partners’ capital/members’ equity	$	1,478,620	$	1	$	1,094,087	$	557,899	$	(1,450,677	)	$	1,679,930

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	As of December 31, 2012
	Issuer		Co-Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	21	$	—	$	—	$	90	$	—		$	111
Accounts receivable		608		—		14,515		6,513		—			21,636
Accounts receivable—related party		366,405		1		22,587		—		(365,238	)		23,755
Insurance receivable		—		—		2,920		—		—			2,920
Prepaid expenses and other		584		—		1,357		—		—			1,941
Total current assets		367,618		1		41,379		6,603		(365,238	)		50,363
Investment in consolidated affiliates		1,041,936		—		—		—		(1,041,936	)		—
Property, plant and equipment—net		8,519		—		775,852		155,475		—			939,846
Intangible assets—net		—		—		163,021		338,359		—			501,380
Goodwill		—		—		95,031		—		—			95,031
Deferred financing costs, net		17,149		—		—		5,379		—			22,528
Other assets		20		—		1,301		—		—			1,321
Total assets	$	1,435,242	$	1	$	1,076,584	$	505,816	$	(1,407,174	)	$	1,610,469
LIABILITIES AND PARTNERS’ CAPITAL/MEMBERS’ EQUITY
Current liabilities
Accrued additions to property, plant and equipment	$	—	$	—	$	3,829	$	5,384	$	—		$	9,213
Capital leases		429		—		3,433		—		—			3,862
Deferred revenue		—		—		—		2,634		—			2,634
Accounts payable—related party		536		—		367,682		108		(365,238	)		3,088
Accounts payable, accrued expenses and other liabilities		15,547		—		11,876		2,294		—			29,717
Total current liabilities		16,512		—		386,820		10,420		(365,238	)		48,514
Long-term debt		558,161		—		—		127,000		—			685,161
Long-term capital leases		960		—		2,201		—		—			3,161
Asset retirement obligations		—		—		13,188		836		—			14,024
Partners’/members’ equity		859,609		1		674,375		367,560		(1,041,936	)		859,609
Total liabilities and partners’ capital/members’ equity	$	1,435,242	$	1	$	1,076,584	$	505,816	$	(1,407,174	)	$	1,610,469

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	For the Six Months Ended June 30, 2013
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	(21,601	)	$	—	$	74,455		$	25,115		$	(20,440	)	$	57,529
Investing activities:
Capital expenditures		(412	)		—		(24,726	)		(55,159	)		—			(80,297	)
Capital contribution to consolidated affiliate		(50,000	)		—		—			—			50,000			—
Other		—			—		—			20			—			20
Change in advances to affiliates, net		47,019			—		—			—			(47,019	)		—
Net cash provided by (used in) investing activities		(3,393	)		—		(24,726	)		(55,139	)		2,981			(80,277	)
Financing activities:
Proceeds from credit facilities		247,500			—		—			69,400			—			316,900
Repayments of credit facilities		(154,000	)		—		—			(69,000	)		—			(223,000	)
Payments on capital leases		(214	)		—		(2,034	)		—			—			(2,248	)
Deferred financing costs paid		(82	)		—		—			—			—			(82	)
Proceeds from issuance of common units, net		118,562			—		—			—			—			118,562
Contributions received		—			—		—			50,000			(50,000	)		—
Distributions to General Partner for additional interest in CMM		(129,000	)		—		—			—			—			(129,000	)
Distributions paid		(57,709	)							(20,440	)		20,440			(57,709	)
Change in advances from affiliates, net		—			—		(47,019	)		—			47,019			—
Taxes paid for equity-based compensation vesting		—			—		(676	)		—			—			(676	)
Net cash provided by (used in) financing activities		25,057			—		(49,729	)		29,960			17,459			22,747
Change in cash and cash equivalents		63			—		—			(64	)		—			(1	)
Cash and cash equivalents at beginning of period		21			—		—			90			—			111
Cash and cash equivalents at end of period	$	84		$	—	$	—		$	26		$	—		$	110

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	For the Six Months Ended June 30, 2012
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	(16,255	)	$	—	$	55,789		$	3,121		$	(441	)	$	42,214
Investing activities:
Acquisitions, net of cash acquired		—			—		—			(376,805	)		—			(376,805	)
Capital expenditures		(434	)		—		(21,101	)		(838	)		—			(22,373	)
Acquisition of interests in CMM		(131,250	)		—		—			—			131,250			—
Capital contribution to consolidated affiliate		1,284			—		—			—			(1,284	)		—
Change in advances to affiliates, net		33,043			—		—			—			(33,043	)		—
Net cash provided by (used in) investing activities		(97,357	)		—		(21,101	)		(377,643	)		96,923			(399,178	)
Financing activities:
Proceeds from credit facilities		223,700			—		—			21,000			—			244,700
Repayments of credit facilities		(174,750	)		—		—			(1,500	)		—			(176,250	)
Payments on capital leases		(132	)		—		(1,243	)		—			—			(1,375	)
Deferred financing costs paid		(161	)		—		—			(6,325	)		—			(6,486	)
Proceeds from issuance of common units, net		103,034			—		—			—			—			103,034
Contributions received		3,413			—		—			375,000			(131,250	)		247,163
Distributions paid		(42,268	)		—		—			(4,928	)		1,725			(45,471	)
Change in advances from affiliate, net		—			—		(33,043	)		—			33,043			—
Taxes paid for equity-based compensation vesting		—			—		(402	)		—			—			(402	)
Net cash provided by (used in) financing activities		112,836			—		(34,688	)		383,247			(96,482	)		364,913
Change in cash and cash equivalents		(776	)		—		—			8,725			—			7,949
Cash and cash equivalents at beginning of period		797			—		—			—			—			797
Cash and cash equivalents at end of period	$	21		$	—	$	—		$	8,725		$	—		$	8,746

13. SUBSEQUENT EVENT

On June 24, 2013, Crestwood Niobrara LLC, our consolidated subsidiary, entered into an agreement with RKI Exploration and Production LLC (RKI), an affiliate of our General Partner, to purchase RKI’s 50% interest in a gathering system located in the Powder River Basin Niobrara play for approximately $108 million. This acquisition closed on July 19, 2013, and was funded through our contribution of approximately $27 million to Crestwood Niobrara (which was borrowed under the CMLP Credit Facility) and an additional $81 million was obtained through Crestwood Niobrara’s issuance of a preferred interest to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE EFS).

Crestwood Niobrara will fund 75% of future capital contributions to the gathering system joint venture through additional preferred interest issuances to GE EFS (up to a maximum of $69 million), with the remainder to be funded through our capital contributions to Crestwood Niobrara. We serve as the managing member of Crestwood Niobrara and we have the ability to redeem GE EFS’s preferred security in either cash or CMLP common units, subject to certain restrictions.

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

On June 19, 2013, Crestwood Holdings acquired the general partner of Inergy, L.P. (NRGY) and contributed its ownership of our General Partner and incentive distribution rights to NRGY in exchange for NRGY common units. On May 5, 2013, we entered into a definitive merger agreement under which we will be merged with a subsidiary of Inergy Midstream, L.P. (NRGM) in a merger in which our unitholders will receive 1.07 units of NRGM for each unit of CMLP they own. Additionally, under the merger agreement, our unitholders (other than Crestwood Holdings) will receive a one-time approximately $35 million cash payment at closing of the merger transaction, or $1.03 per unit, $25 million of which will be payable by NRGM and approximately $10 million of which will be payable by Crestwood Holdings. The merger of NRGM and CMLP is conditioned upon the approval of the holders of a majority of the limited partner interests of CMLP and other customary closing conditions.

Overview and Performance Metrics

We are a growth-oriented midstream master limited partnership which owns and operates predominately fee-based gathering, processing, treating and compression assets servicing producers in the Marcellus Shale in northern West Virginia, the Barnett Shale in north Texas, the Fayetteville Shale in northwestern Arkansas, the Granite Wash in the Texas Panhandle, the Avalon Shale/Bone Spring 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 six months ended June 30, 2013 and 2012, services provided to Quicksilver accounted for approximately 34% and 54% of our total revenues.

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 Marcellus, Barnett, Fayetteville and Granite Wash. Our operating segments are engaged in gathering, processing, treating, compression, transportation and sales of natural gas and delivery of NGLs in the United States. Our Other operating segment consists of those operating segments or reporting units that did not meet quantitative reporting thresholds.

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 six months ended June 30, 2013, 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 six months ended June 30, 2013, 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 in the Barnett Shale; (ii) the Granite Wash System; (iii) the Las Animas Systems in the Avalon Shale; and (iv) two systems in the Marcellus segment. For the three and six months ended June 30, 2013, our systems located in NGL rich gas basins contributed approximately 72% and 71% of our total revenues and 65% and 64% of our total 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.

Volumes— 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 the impact of certain significant items, such as third party costs incurred related to potential and completed acquisitions and other transactions identified in 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. We believe that our experience and market position will allow us to realize significant ongoing growth opportunities by developing new greenfield projects in NGL and oil plays in areas with limited or constrained infrastructure which offer attractive returns on investment and seeking bolt-on acquisitions that provide operating synergies and allow for the development of our business in rich gas infrastructure plays. Our acquisition strategy includes diversifying and extending our geographic, customer and business profile and developing organic growth opportunities along the midstream value chain.

Our systems gathered 993 MMcf/d and 984 MMcf/d during the three and six months ended June 30, 2013, which is an increase of 21% and 37% from the same periods in 2012. During the three and six months ended June 30, 2013, our Marcellus systems’ compression volumes were 284 MMcf/d and 277 MMcf/d. Additionally, our processed volumes were 217 MMcf/d and 221 MMcf/d for the three and six months ended June 30, 2013, an increase of 51% compared to the same periods in 2012, respectively. The increase in volumes resulted in a 29% and 32% increase in our overall revenues for the three and six months ended June 30, 2013 compared to the same periods in 2012.

Distribution Growth — For the three months ended June 30, 2013, we declared a distribution of $0.51 per limited partner unit compared to $0.50 per limited partner unit during the same period in 2012.

Antero Agreements

In March 2013, Crestwood Marcellus Midstream LLC (CMM) entered into a seven year agreement with Antero Resources Appalachian Corporation (Antero) to provide natural gas compression services on developing rich gas acreage in Doddridge County, West Virginia (Compression Services Agreement). The Compression Services Agreement provides for the construction and operation of compressor stations on Antero’s Western Area acreage (Western Area) which is not dedicated to us under the existing GGA which covers the Eastern Area of Dedication (Eastern AOD). We will provide fixed-fee compression services to Antero under the Compression Services Agreement, which provides for minimum fees based on the capacity of the compressor stations constructed under the agreement. The Compression Services Agreement does not impact our seven year right of first offer to acquire midstream infrastructure from Antero in the Western Area and is in addition to the previously announced construction of two compressor stations we are constructing in the Eastern AOD during 2013.

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The West Union compressor station to be constructed under the Compression Services Agreement will be a two phase project adding approximately 120 MMcf/d of flow capacity at an estimated cost of $35 million. Phase I will add 55 MMcf/d of capacity and is expected to be in service during the third quarter of 2013. Phase II will add 65 MMcf/d and is expected to be in service by the end of 2013. The Victoria compressor station to be constructed will add approximately 120 MMcf/d of flow capacity at an estimated cost of $41 million. Phase I is expected to be in service during the first quarter of 2014 and Phase II is expected to be in service during the third quarter of 2014. The Compression Services Agreement also provides for the construction of additional compression facilities if agreed to by Antero and CMM in the future.

In December 2012, CMM completed the acquisition of natural gas compression and dehydration assets from Enerven Compression, LLC (Enerven) for approximately $95 million expanding the value chain and range of services we provide in the high growth Marcellus Shale. The acquisition included four compression stations connected to CMM’s low pressure gathering systems and a five-year minimum term compression services agreement with Antero which expires in 2018. In addition, CMM provides compression services to Antero under a 20 year, fixed fee, Gas Gathering and Compression Agreement (GGA), which became effective in January 2012. We believe the Enerven assets will provide an excellent opportunity for organic growth as gathering infrastructure in the Marcellus rich gas region continues to be built at a rapid pace.

RKI Exploration and Production (RKI) Agreement

On July 19, 2013, Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, paid approximately $108 million to acquire a 50% interest in a gathering system located in the Powder River Basin of the Niobrara play from RKI, an affiliate of our General Partner. The joint venture gathering system has 20 year gathering and processing agreements with Chesapeake Energy Corporation (Chesapeake) and RKI under which it receives cost-of-service based fees with annual redeterminations. The gathering and processing agreements provide for an area of dedication of approximately 311,000 gross acres located in the core of the Powder River Basin Niobrara Shale. This acquisition further diversifies our portfolio and positions us to participate in additional greenfield development opportunities in the core of the Powder River Basin Niobrara Shale which currently has limited midstream infrastructure.

Financing Activities

Equity Offering

On March 22, 2013, we completed a public offering of 4,500,000 common units, representing limited partner interests in us at a price of $23.90 per common unit ($23.00 per common unit, net of underwriting discounts) providing net proceeds of approximately $103.5 million. We granted the underwriters a 30 day option to purchase up to 675,000 additional common units if the underwriters sold more than 4,500,000 common units in the offering. The underwriters exercised this option on April 5, 2013, providing net proceeds of approximately $15.5 million. The net proceeds from these transactions were used to reduce indebtedness under each of the CMM and CMLP Credit Facilities. In connection with the issuance of the common units, our General Partner did not make an additional capital contribution to us resulting in a reduction in their general partner interest in us to approximately 1.8%.

Unit Issuances

On January 8, 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for approximately $258 million. We funded the purchase price through $129 million of borrowings under our CMLP credit facility, the issuance of 6,190,469 Class D units, representing limited partner interests in us to Crestwood Holdings, and the issuance of 133,060 general partner units to our General Partner.

Preferred Interest Issuance

In July 2013 Crestwood Niobrara acquired a 50% interest in a joint venture which was funded through our contribution of approximately $27 million (which was borrowed under the CMLP Credit Facility) and an additional $81 million obtained through Crestwood Niobrara’s issuance of a preferred interest to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE EFS). Crestwood Niobrara will fund 75% of future capital contributions to the gathering system joint venture through additional preferred interest issuances to GE EFS (up to a maximum of $69 million), with the remainder to be funded through our capital contributions to Crestwood Niobrara. We serve as the managing member of Crestwood Niobrara and we have the ability to redeem GE EFS’s preferred security in either cash or CMLP common units, subject to certain restrictions.

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Results of Operations

Three and Six Months Ended June 30, 2013 Compared with Three and Six Months Ended June 30, 2012

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

	Three Months Ended June 30,				Six Months Ended June 30,
	2013		2012		2013		2012
Operating revenues	$	71,099	$	55,229	$	143,515	$	108,962
Product purchases		14,032		7,441		27,537		16,414
Operations and maintenance expense		12,592		9,400		25,608		19,111
General and administrative expense		10,380		8,657		18,169		15,395
Depreciation, amortization and accretion expense		17,701		13,695		35,061		24,341
Operating income		16,394		16,036		37,140		33,701
Interest and debt expense		11,185		8,963		22,635		16,520
Income tax expense		339		275		677		578
Net income	$	4,870	$	6,798	$	13,828	$	16,603
Add:
Interest and debt expense		11,185		8,963		22,635		16,520
Income tax expense		339		275		677		578
Depreciation, amortization and accretion expense		17,701		13,695		35,061		24,341
EBITDA	$	34,095	$	29,731	$	72,201	$	58,042
Expenses associated with significant items		4,799		2,295		5,517		2,346
Adjusted EBITDA	$	38,894	$	32,026	$	77,718	$	60,388

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EBITDA in the table above includes operating results from our Marcellus, Barnett, Fayetteville and Granite Wash segments and other operations, and general and administrative expenses. The following table summarizes the results of our Barnett, Marcellus, Fayetteville and Granite Wash segments and other operations (In thousands):

	For the Three Months Ended June 30, 2013
	Marcellus		Barnett		Fayetteville		Granite Wash		Other		Total
Gathering revenues	$	11,524	$	23,568	$	6,140	$	478	$	1,459	$	43,169
Processing revenues		—		9,440		—		1		—		9,441
Compression revenues		3,873		—		—		—		—		3,873
Product sales		—		64		191		13,157		1,204		14,616
Total operating revenues	$	15,397	$	33,072	$	6,331	$	13,636	$	2,663	$	71,099
Product purchases		—		146		190		12,492		1,204		14,032
Operations and maintenance expense		2,545		6,312		2,310		685		740		12,592
EBITDA	$	12,852	$	26,614	$	3,831	$	459	$	719
Gathering volumes (in MMcf)		37,765		39,833		7,696		1,870		3,176		90,340
Processing volumes (in MMcf)		—		17,913		—		1,864		—		19,777
Compression volumes (in MMcf)		25,882		—		—		—		—		25,882

	For the Three Months Ended June 30, 2012
	Marcellus		Barnett		Fayetteville		Granite Wash		Other		Total
Gathering revenues	$	7,027	$	23,771	$	6,228	$	270	$	2,081	$	39,377
Processing revenues		—		7,732		—		16		—		7,748
Product sales		—		—		102		7,436		566		8,104
Total operating revenues	$	7,027	$	31,503	$	6,330	$	7,722	$	2,647	$	55,229
Product purchases		—		—		124		6,732		585		7,441
Operations and maintenance expense		513		5,345		2,231		541		770		9,400
EBITDA	$	6,514	$	26,158	$	3,975	$	449	$	1,292
Gathering volumes (in MMcf)		23,424		36,529		7,112		1,367		6,044		74,476
Processing volumes (in MMcf)		—		11,765		—		1,362		—		13,127

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	For the Six Months Ended June 30, 2013
	Marcellus		Barnett		Fayetteville		Granite Wash		Other		Total
Gathering revenues	$	21,872	$	47,910	$	13,099	$	992	$	3,199	$	87,072
Processing revenues		—		19,168		—		3		—		19,171
Compression revenues		7,799		—		—		—		—		7,799
Product sales		—		544		485		26,490		1,954		29,473
Total operating revenues	$	29,671	$	67,622	$	13,584	$	27,485	$	5,153	$	143,515
Product purchases		—		401		483		24,699		1,954		27,537
Operations and maintenance expense		4,942		13,567		4,444		1,293		1,362		25,608
EBITDA	$	24,729	$	53,654	$	8,657	$	1,493	$	1,837
Gathering volumes (in MMcf)		71,674		80,206		15,141		3,905		7,115		178,041
Processing volumes (in MMcf)		—		36,235		—		3,709		—		39,944
Compression volumes (in MMcf)		50,157		—		—		—		—		50,157

	For the Six Months Ended June 30, 2012
	Marcellus		Barnett		Fayetteville		Granite Wash		Other		Total
Gathering revenues	$	7,027	$	49,830	$	12,994	$	409	$	4,800	$	75,060
Processing revenues		—		15,616		—		99		—		15,715
Product sales		—		—		200		16,811		1,176		18,187
Total operating revenues	$	7,027	$	65,446	$	13,194	$	17,319	$	5,976	$	108,962
Product purchases		—		—		206		15,033		1,175		16,414
Operations and maintenance expense		513		11,475		4,544		1,059		1,520		19,111
EBITDA	$	6,514	$	53,971	$	8,444	$	1,227	$	3,281
Gathering volumes (in MMcf)		23,424		77,182		14,647		2,720		12,107		130,080
Processing volumes (in MMcf)		—		23,822		—		2,707		—		26,529

EBITDA and Adjusted EBITDA —EBITDA for the three and six months ended June 30, 2013 was approximately $34 million and $72 million, an increase of approximately $4 million and $14 million compared to same periods in 2012. In the same manner, Adjusted EBITDA for the three and six months ended June 30, 2013 was approximately $39 million and $78 million, an increase of approximately $7 million and $17 million compared to the same periods in 2012. Adjusted EBITDA considers expenses for evaluating certain transaction opportunities, which were approximately $5 million and $6 million for the three and six months ended June 30, 2013 and $2 million for the same periods in 2012, respectively.

Below is a discussion of the factors that impacted EBITDA by segment for the three and six months ended June 30, 2013 compared to the same periods in 2012.

Marcellus:

EBITDA for our Marcellus segment was approximately $13 million and $25 million for the three and six months ended June 30, 2013. On March 26, 2012, CMM acquired gathering assets from Antero, which contributed approximately $7 million to our Marcellus segment EBITDA for the three and six months ended June 30, 2012.

Revenues and Volumes —Revenues in our Marcellus segment increased by approximately $8 million and $23 million during the three and six months ended June 30, 2013 compared to the same periods in 2012 primarily due to the increase in gathering volumes. During 2013, we experienced gathering system and compression capacity constraints in our Marcellus segment, however we have several projects with anticipated in-service dates during the third and fourth quarters of 2013 that we believe will mitigate those capacity constraints, which we anticipate will result in higher gathering volumes during the last half of 2013. For the three and six months ended June 30, 2013, we gathered 415 MMcf/d and 396 MMcf/d in our Marcellus segment compared to 257 MMcf/d for the three months ended June 30, 2012. In addition, we recognized gathering revenues for the entire first half of 2013 versus three months during the same period in 2012. During the three and six months ended June 30, 2013, we connected 15 and 30 new wells in our Marcellus segment which contributed to the increase in gathering volumes and revenues.

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In addition to the increase in gathering revenues, our compression volumes increased due to CMM’s acquisition of E. Marcellus Asset Company, LLC (EMAC) from Enerven in December 2012. The acquisition of these natural gas compression and dehydration assets has expanded the value chain and range of services we provide in the high growth Marcellus Shale. The acquisition included four compression stations connected to CMM’s low pressure gathering systems and a five-year minimum term compression services agreement with Antero which expires in 2018. During the three and six months ended June 30, 2013, our compression volumes under this agreement were 284 MMcf/d and 277 MMcf/d. In addition, for the remainder of 2013, we anticipate an increase in our compression revenues as a result of a compressor station that will be placed in service during the third quarter of 2013.

Operations and Maintenance Expense — Operations and maintenance expenses in our Marcellus segment increased by approximately $2 million and $4 million for the three and six months ended June 30, 2013 when compared to the same periods in 2012 primarily due to the acquisition of the Enerven assets discussed above.

Barnett:

For the three and six months ended June 30, 2013, our Barnett segment’s EBITDA was relatively consistent with the same periods in 2012, primarily due to higher processing revenues being offset by lower gathering revenues and higher operations and maintenance expenses.

Revenues and Volumes — Our processing revenues increased by approximately $2 million and $3 million for the three and six months ended June 30, 2013 compared to the same periods in 2012, primarily due to the Devon Acquisition, which was completed on August 24, 2012. Partially offsetting this increase in processing revenues was a $0.2 million and $1.9 million decrease in gathering revenues during the three and six months ended June 30, 2013 compared to the same periods in 2012, primarily due to lower dry gas gathering volumes. The decrease in dry gas gathering volumes primarily related to reduced production from Quicksilver’s existing wells. In addition, Quicksilver did not connect any new wells during the three months ended June 30, 2013. Partially offsetting the decline in Quicksilver volumes were two new wells we connected from other producers during the three months ended June 30, 2013 and five new wells connected during the six months ended June 30, 2013.

Operations and Maintenance Expense — Operations and maintenance expenses in our Barnett segment increased by approximately $1 million and $2 million for the three and six months ended June 30, 2013 when compared to the same periods in 2012 primarily due to the operation of the West Johnson County system acquired in the Devon Acquisition during August 2012. During the three and six months ended June 30, 2013, operations and maintenance expenses related to the West Johnson County system were approximately $0.3 million and $1 million, which reflects the full synergies of the integration of the system with our Cowtown system completed in December 2012. As a result of the integration, the West Johnson County plant that was acquired in the Devon Acquisition is now available for redeployment or other uses.

Fayetteville:

Our Fayetteville segment EBITDA was relatively flat during the three and six months ended June 30, 2013 compared to the same periods in 2012.

Revenues and Volumes —During the six months ended June 30, 2013, revenues in our Fayetteville segment increased by approximately $0.4 million compared to the same period in 2012 primarily due to an increase in volumes due to twelve new wells connected during the first half of 2013.

Operations and Maintenance Expense —Operations and maintenance expenses in our Fayetteville segment for the three and six months ended June 30, 2013 were relatively flat compared to the same periods in 2012.

Granite Wash:

During the six months ended June 30, 2013, our Granite Wash segment’s EBITDA was relatively flat during the three and six months ended June 30, 2013 compared to the same periods in 2012, primarily due to slightly higher gathering revenues offset by slightly higher operations and maintenance expense.

Revenues/Margin and Volumes — For the six months ended June 30, 2013, we experienced a $0.6 million increase in gathering revenues due to a gathering and processing agreement entered during the third quarter of 2012 with Sabine Oil and Gas LLC and its affiliates (Sabine), an affiliate of our General Partner. During the six months ended June 30, 2013, we gathered 21MMcf/d in the Granite Wash compared to 15 MMcf/d during the same period in 2012. Granite Wash’s margins earned on our percent-of-proceeds contracts were relatively flat for the three and six months ended June 30, 2013 compared to the same periods in 2012.

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Operations and Maintenance Expense — Operations and maintenance expenses in our Granite Wash segment were approximately $0.1 million and $0.2 million higher during the three and six months ended June 30, 2013 compared to the same periods in 2012 primarily due to the increase in volumes gathered and processed under our agreement with Sabine described above.

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 six months ended June 30, 2013, our other operations’ EBITDA decreased by approximately $1 million compared to the same periods in 2012, which primarily relates to the operations of our Sabine System.

Revenues and Volumes — The Sabine System had 27 MMcf/d and 31 MMcf/d in gathered volumes for the three and six months ended June 30, 2013 compared to 57 MMcf/d during each of the same periods in 2012. The decrease in volumes was primarily due to lower volumes transported below the minimum quantity under our gathering contract with a subsidiary of US Infrastructure Holdings, LLC (USI) which expired in June 2013. Our gathering volumes from other producers on our Sabine System was lower for the three and six months ended June 30, 2013 compared to the same periods in 2012, which also contributed to the $0.6 million and $1.4 million decrease in revenues period over period. EBITDA related to our Las Animas System remained relatively unchanged for the three and six months ended June 30, 2013, compared to the same periods in 2012.

Operations and Maintenance Expense —Operations and maintenance expenses decreased by approximately $0.2 million during the six months ended June 30, 2013 compared to the same period in 2012 due to decreased gathering activity on our Sabine System.

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

General and Administrative Expenses — During the three and six months ended June 30, 2013, general and administrative expenses increased by approximately $2 million and $3 million when compared to the same periods in 2012. General and administrative expenses include costs related to legal and other consulting services to evaluate certain transaction opportunities and other non-recurring matters. We incurred approximately $5 million and $6 million of these costs during the three and six months ended June 30, 2013 compared to $2 million of these costs in the same periods in 2012, respectively, which was the primary driver for the increase in general and administrative expense compared to June 30, 2012.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense —We have experienced increases in our depreciation, amortization and accretion expense primarily due to assets acquired during 2012. For a further discussion of our asset acquisitions during 2012, see our 2012 Annual Report on Form 10-K.

Interest and Debt Expense— Interest and debt expense increased for the three and six months ended June 30, 2013 compared to the same periods in 2012, primarily due to (i) higher outstanding balances on our credit facilities; and (ii) the issuance of an additional $150 million of 7.75% Senior Notes in November 2012.

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

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2013			2012			2013			2012
Credit Facilities	$	4,263		$	4,903		$	8,653		$	8,106
Senior Notes		7,025			4,027			14,015			8,054
Capital lease interest		70			45			142			94
Other debt-related costs		(52	)		93			(54	)		462
Gross interest and debt expense		11,306			9,068			22,756			16,716
Less capitalized interest		(121	)		(105	)		(121	)		(196	)
Interest and debt expense	$	11,185		$	8,963		$	22,635		$	16,520

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Liquidity and Capital Resources

Our sources of liquidity include cash flows generated from operations, available borrowing capacity under each of the CMM and CMLP Credit Facilities, 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 2013. 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 each of the CMM and CMLP Credit Facilities 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:We depend on Quicksilver for a substantial percentage of our current business. For the three and six months ended June 30, 2013, services to Quicksilver accounted for approximately 34% of our total revenues in each period. In April 2013, Quicksilver sold approximately 25% of its interest in its Barnett Shale assets to TG Barnett Resources LP, a wholly-owned U.S. subsidiary of Tokyo Gas Co., Ltd. Quicksilver will remain the operator of the assets. The risk of revenue fluctuations from Quicksilver 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.

• Access to Capital Markets: Our total borrowings under our credit facilities were $428 million as of June 30, 2013 and based on our results through June 30, 2013, our remaining available capacity under the CMLP Credit Facility and CMM Credit Facility was $111 million and $73 million, respectively. While we anticipate that our current available borrowing capacity under our credit facilities is sufficient to fund our planned level of growth capital spending for the remainder of 2013, additional debt and equity offerings may be necessary to fund additional acquisitions or other growth capital projects. During 2013, we have raised approximately $119 million through equity offerings to reduce indebtedness under each of the CMM and CMLP Credit Facilities and for general partnership purposes. We also raised approximately $81 million through the issuance of a preferred security to GE EFS, and secured the ability to raise up to an additional $69 million from GE EFS under this security to fund future expenditures in the Niobrara shale play. On May 5, 2013, CMLP and NRGM entered into a definitive agreement that established the terms and conditions under which CMLP and NRGM would merge. As a part of that agreement, CMLP agreed to interim operating covenants that restrict it from executing additional equity and debt offerings during the pendency period of the merger without prior authorization and written consent from NRGM.

• 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; (ii) the Granite Wash System; (iii) the Las Animas Systems; and (iv) two systems in the Marcellus segment. For three and six months ended June 30, 2013, these rich gas systems accounted for approximately 72% and 71% of our total 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.

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• Regulatory Requirements: Our operations and the operations of our customers are subject to complex and evolving federal, state, local and other laws and regulations. In April 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.

Cash Flows

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

	Six Months Ended June 30,
	2013			2012
Net cash provided by operating activities	$	57,529		$	42,214
Net cash used in investing activities		(80,277	)		(399,178	)
Net cash provided by financing activities		22,747			364,913

Operating Activities

During the six months ended June 30, 2013, we experienced an increase in our operating cash flows compared to the same period in 2012 primarily due to higher operating revenues as a result of our asset acquisitions during 2012 partially offset by higher operations and maintenance expenses related to the acquired assets. In addition, our interest costs increased due to higher outstanding balances on our credit facilities and Senior Notes.

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.

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The following table summarizes our capital expenditures for the six months ended June 30, 2013. We anticipate that our expansion capital expenditures during 2013 will expand our gathering systems through additional pipelines to connect to new wells, purchase additional compression equipment and generally increase the capacity of our systems in each of our operating segments, primarily in the Marcellus segment.

	(In thousands)
Expansion capital	$	75,462
Maintenance capital		2,923
Other(1)		1,912
Total	$	80,297

⁽¹⁾  Represents capital expenditures that are reimbursable from our insurers.

In July 2013, Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, paid approximately $108 million to acquire a 50% interest in a gathering system located in the Powder River Basin of the Niobrara play from RKI, an affiliate of our General Partner.

Financing Activities

Significant items impacting our financing activities during the six months ended June 30, 2013 included the following:

• Net borrowings under our credit facilities of approximately $94 million; and

• $103.5 million in proceeds from the issuance of 4,500,000 common units in March 2013.

• $15.5 million in proceeds from the issuance of 675,000 common units in April 2013.

During the six months ended June 30, 2013, we paid distributions to our unitholders of approximately $58 million, which increased by $11 million when compared to the same period in 2012. On April 1, 2013, all of the Class C units representing limited partner interests in us automatically converted into common units on a one-for-one basis. Quarterly distributions on these converted units will be paid in cash.

In January 2013, we acquired Crestwood Holdings’ 65% membership interest in CMM for $258 million, which was funded through $129 million of borrowings under the CMLP Credit Facility and the issuance of approximately $129 million of equity to Crestwood Holdings.

In July 2013 Crestwood Niobrara acquired a 50% interest in a joint venture which was funded through our contribution of approximately $27 million (which was borrowed under the CMLP Credit Facility) and an additional $81 million was obtained through Crestwood Niobrara’s issuance of a preferred interest to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE EFS). Crestwood Niobrara will fund 75% of future capital contributions to the gathering system joint venture through additional preferred interest issuances to GE EFS (up to a maximum of $69 million), with the remainder to be funded through our capital contributions to Crestwood Niobrara. We serve as the managing member of Crestwood Niobrara and we have the ability to redeem GE EFS’s preferred security in either cash or CMLP common units, subject to certain restrictions.

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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 2012 Annual Report on Form 10-K.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As of June 30, 2013, we carried out an evaluation under the supervision and with the participation of our management, including the Chief Executive Officer and Interim 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 Interim 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 Interim Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2013.

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 June 30, 2013 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

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PART II — OTHER INFORMATION

Item 1. Legal Proceedings

See Part I, Item 1. Financial Statements, Note 7, which 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 2012 Annual Report on Form 10-K under Part I, Item 1A. Risk Factors. Except for the additional risk factors set forth below, there have been no material changes in our risk factors since that report.

Failure to complete the merger or delays in completing the merger with Inergy Midstream, L.P. could negatively impact our unit price, future business and operation, and financial results.

On May 5, 2013, we entered into a definitive merger agreement under which we would be merged with a subsidiary of Inergy Midstream, L.P. (NRGM). Completion of the proposed merger is subject to various conditions, including, among others, approval by the holders of a majority of the limited partner interest of CMLP and other customary closing conditions. If the merger is not completed, we will be subject to a number of risks, including the following:

• because the current price of our common units may reflect a market premium based on the assumption that we will complete the merger, a failure to complete the merger could result in a decline in the price of our common units;

• the pending merger, its effects and related matters may distract our employees from day-to-day operations and require substantial commitments of time and resources, and may also impair our relations with our employees, customers, suppliers and other constituencies due to uncertainty about the future following the completion of the merger;

• in specified circumstances, if the merger is not completed, we may be required to pay NRGM a termination fee of $50.8 million;

• we will not realize the benefits expected from being part of a larger combined organization; and

• some costs related to the merger, such as legal, accounting and financial advisor fees, must be paid even if the merger is not completed.

While the merger is pending we may be subject to restrictions on the conduct of our business.

The merger agreement restricts us from taking specified actions without NRGM’s approval. These restrictions could adversely affect our ability to execute certain of our business strategies, including the ability in certain cases to enter into contracts, acquire or dispose of assets, incur indebtedness or incur capital expenditures. Such limitations could negatively affect our businesses and operations prior to the completion of the merger.

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: August 7, 2013	By:	/s/ Steven M. Dougherty
		Steven M. Dougherty
		Senior Vice President—Interim Chief Financial Officer and Chief Accounting Officer
		(Principal Financial and 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. Exhibits designated by a plus (+) represent a management contract or compensatory plan or arrangement.

Exhibit No.	Description
2.1	Agreement and Plan of Merger dated as of May 5, 2013, by and among Inergy Midstream, L.P., NRGM GP, LLC, Intrepid Merger Sub, LLC, Inergy, L.P., Crestwood Holdings LLC, Crestwood Midstream Partners LP, and Crestwood Gas Services GP LLC (filed as Exhibit 2.1 to Crestwood Midstream Partners LP’s Form 8-K filed May 9, 2013, and included herein by reference).
10.1	Voting Agreement dated as of May 5, 2013, by and among Inergy Midstream, L.P., NRGM GP, LLC, Intrepid Merger Sub, LLC, Inergy, L.P., Crestwood Holdings LLC, Crestwood Midstream Partners LP, Crestwood Gas Services Holdings LLC, and Crestwood Gas Services GP LLC (filed as Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed May 9, 2013, and included herein by reference).
10.2	Payment Agreement dated as of May 5, 2013, by and between Crestwood Midstream Partners LP and Crestwood Holdings LLC (filed as Exhibit 10.2 to Crestwood Midstream Partners LP’s Form 8-K filed May 9, 2013, and included herein by reference).
+10.3	Letter Agreement dated May 3, 2013, between Crestwood Holdings Partners, LLC and Steven M. Dougherty (filed as Exhibit 10.2 to Crestwood Midstream Partners LP’s Form 10-Q for the quarter ended March 31, 2013, and included herein by reference).
10.4	Purchase and Sale Agreement, dated June 21, 2013 by and between RKI Exploration & Production, LLC, Crestwood Niobrara LLC and Crestwood Midstream Partners LP (filed as Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed June 24, 2013, and included herein by reference).
*12.1	Computation of Ratio of Earnings to Fixed Charges
*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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