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

3.Table ACQUISITIONSof AND DIVESTITURES Contents

OnTable 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. Contents

TheTable followingof table presents distributions for 2013 and 2012 (In millions, except per unit data): Contents

WeTable 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. Contents

CMMTable 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. Contents

InTable 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. Contents

18Table of Contents

AsTable 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. Contents

20Table of Contents

TheTable 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. Contents

25Table of Contents

26Table of Contents

27Table of Contents

13.Table SUBSEQUENTof EVENT Contents

28Table of Contents

OnTable 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. Contents

WeTable 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. Contents

•Table ourof ability to compete with other midstream companies for production volumes; andContents

GrowthTable 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. Contents

OnTable 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. Contents

EBITDATable forof 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. Contents

InTable 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. Contents

RevenuesTable 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. Contents

Depreciation,Table 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. Contents

•Table 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.Contents

•Table 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.Contents

Item 3.Table Quantitativeof and Qualitative Disclosures About Market Risk Contents

•Table 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;Contents

41Table of Contents

42Table of Contents

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~~September 30, 2013

¨	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.

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~~October 313, 2013 (1)
Common Units		53,~~766~~765,~~588~~220

⁽¹⁾	On October 7, 2013, Crestwood Midstream Partners LP merged with and into Inergy Midstream, L.P.

CRESTWOOD MIDSTREAM PARTNERS LP

TABLE OF CONTENTS

PART I. FINANCIAL INFORMATION
Item 1. Financial Statements		5
Item 1.	Financial Statements		5
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations		29
Item 2	Management’s Discussion and Analysis of Financial Condition and Results of Operations		31
Item 3. Quantitative and Qualitative Disclosures About Market Risk		40
Item 3.	Quantitative and Qualitative Disclosures About Market Risk		41
Item 4. Controls and Procedures		40
Item 4.	Controls and Procedures		41
PART II. OTHER INFORMATION
Item 1. Legal Proceedings		41
Item 1.	Legal Proceedings		42
Item 1A. Risk Factors		41
Item 1A.	Risk Factors		42
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		41
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds		42
Item 3. Defaults Upon Senior Securities		41
Item 3.	Defaults Upon Senior Securities		42
Item 4. Mine Safety Disclosures		41
Item 4.	Mine Safety Disclosures		42
Item 5. Other Information		41
Item 5.	Other Information		42
Item 6. Exhibits		41
Item 6.	Exhibits		42
Signatures		42	43
Exhibits		43	44

EXPLANATORY NOTE

On October 7, 2013, Crestwood Midstream Partners LP (CMLP) completed the merger (the Merger) with a subsidiary of Inergy Midstream, L.P. (NRGM) pursuant to a merger agreement dated as of May 5, 2013, by and among NRGM, NRGM GP, LLC, Intrepid Merger Sub, LLC (Merger Sub), Inergy, L.P. (NRGY), CMLP, Crestwood Holdings LLC (Crestwood Holdings) and Crestwood Gas Services GP LLC (CMLP GP). Immediately following the effective time of the Merger, CMLP merged with and into NRGM, with NRGM continuing as the surviving entity and changing its name to Crestwood Midstream Partners LP (Crestwood Midstream). The Merger has been accounted for as a reverse acquisition under which CMLP was considered the accounting acquirer of NRGM. As such, the financial statements of CMLP are treated as the historical financial statements of Crestwood Midstream, the combined partnership.

This Quarterly Report on Form 10-Q of CMLP for the period ended September 30, 2013 is being filed by Crestwood Midstream as the legal successor by the merger to CMLP. The financial information in this report and the accompanying Management’s Discussion and Analysis of Financial Condition and Results of Operations reflect the status of the reporting entity as of September 30, 2013. Unless the context requires otherwise, all references in this Quarterly Report on Form 10-Q to “we,” “us,” “our,” or “CMLP” refer to the business and operations of Crestwood Midstream Partners LP, a Delaware limited partnership, and its consolidated subsidiaries for the periods prior to the closing of the Merger.

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~~our inability ~~general~~to ~~economic~~consummate ~~conditions~~acquisitions, successfully integrate the businesses of CMLP and NRGM, and realize any cost savings and other synergies from any acquisition;

• ~~fluctuations~~our inability ~~oil,~~to ~~natural~~complete ~~gas~~our ~~and~~growth ~~natural gas liquid (NGL) prices~~projects;

• ~~the~~our ~~extent~~ability ~~and~~to ~~success~~generate ofstable ~~drilling~~cash ~~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~~flows;

• ~~failure~~our orability ~~delays~~to bysuccessfully implement our ~~customers~~business inplan ~~achieving~~for ~~expected~~our ~~production~~assets inand ~~their natural gas projects~~operations;

•

the extent and success of producer or customer drilling efforts, as well as the extent and quality of crude oil and natural gas volumes produced within areas of acreage dedicated to and within the proximity of our assets;

•

failure or delays by our customers in achieving expected production targets;

•

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~~effects ~~businesses,~~of ~~realize~~existing ~~any~~and ~~cost~~future ~~savings~~laws and ~~other~~governmental ~~synergies~~legislation ~~from~~and ~~any acquisition~~regulations;

• ~~changes~~industry infactors that influence the ~~availability~~supply and ~~cost~~prices of, ~~capital~~and demand for, crude oil, natural gas and natural gas liquids (NGLs);

•

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

• ~~timely~~industry ~~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~~influence ~~impact~~the ~~our~~demand ~~ability~~for tonatural ~~complete~~gas ~~projects~~storage ~~within budget~~ and ontransportation ~~schedule~~capacity;

• ~~the~~changes ~~effects~~in ofgeneral ~~existing~~economic ~~and future laws and governmental regulations, including environmental and climate change requirements~~conditions;

• the ~~effects~~availability and price of ~~future~~crude ~~litigation~~oil, natural gas and NGLs to consumers compared to the prices of alternative and competing fuels;

• ~~risks~~environmental ~~related to our substantial indebtedness~~claims;

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

• the ~~terms~~price and ~~conditions~~availability of ~~any~~debt ~~required~~and ~~regulatory~~equity ~~approvals of the proposed merger~~financing;

• ~~the~~risks ~~impact~~related ofto ~~the proposed merger on~~ our ~~employees~~substantial ~~and~~indebtedness; ~~potential~~the ~~diversion~~effects of ~~management’s~~existing ~~time~~or ~~and~~future ~~attention from ongoing business during this period~~litigations; and

•

certain factors discussed elsewhere in this report.

~~These~~All ~~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 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.

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.

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~~Nine Months Ended
	June 30,						June 30,
	September 30,						September 30,
	2013			2012(1)			2013			2012(1)
Operating revenues
Gathering revenues	$	2425,~~103~~188		$	1721,~~761~~715		$	4873,~~099~~287		$	2951,~~598~~313
Gathering revenues—related party		1918,~~066~~726			21,~~616~~658			3857,~~973~~699			4567,~~462~~120
Processing revenues		3,~~926~~548			12,~~198~~271			711,~~974~~522			24,~~394~~665
Processing revenues—related party		5,~~515~~421			6,~~550~~298			1116,~~197~~618			1319,~~321~~619
Compression revenues		34,~~873~~075			—			711,~~799~~874			—
Product sales		14,~~616~~180			811,~~104~~071			2943,~~473~~653			1829,~~187~~258
Total operating revenues		71,~~099~~138			5563,~~229~~013			~~143~~214,~~515~~653			~~108~~171,~~962~~975
Operating expenses
Product purchases		65,~~154~~295			710,~~441~~341			1218,~~902~~197			1626,~~414~~755
Product purchases—related party		7,~~878~~556			—			1422,~~635~~191			—
Operations and maintenance		1214,~~592~~895			910,~~400~~942			2540,~~608~~503			1930,~~111~~053
General and administrative		10,~~380~~367			86,~~657~~570			1828,~~169~~536			1521,~~395~~965
Depreciation, amortization and accretion		1714,~~701~~557			1311,~~695~~568			3549,~~061~~618			2435,~~341~~909
Total operating expenses		5452,~~705~~670			39,~~193~~421			~~106~~159,~~375~~045			75114,~~261~~682
Operating income		16,394			16,036			37,140			33,701
Goodwill impairment		(4,053	)		—			(4,053	)		—
Interest and debt expense		(11,185	)		(8,963	)		(22,635	)		(16,520	)
Gain on sale of asset		4,392			—			4,392			—
Income before income taxes		5,209			7,073			14,505			17,181
Operating income		18,807			23,592			55,947			57,293
Income tax expense		339			275			677			578
Loss from unconsolidated affiliate		(447	)		—			(447	)		—
Net income	$	4,870		$	6,798		$	13,828		$	16,603
Interest and debt expense		(11,625	)		(8,905	)		(34,260	)		(25,425	)
General partner’s interest in net income	$	5,192		$	4,154		$	10,393		$	7,522
Income before income taxes		6,735			14,687			21,240			31,868
Limited partners’ interest in net income	$	(322	)	$	2,644		$	3,435		$	9,081
Income tax expense		347			306			1,024			884
Basic earnings (loss) per unit:
Net income		6,388			14,381			20,216			30,984
Net income (loss) per limited partner unit	$	(0.01	)	$	0.06		$	0.06		$	0.21
Net income attributable to noncontrolling interest		1,923			—			1,923			—
Diluted earnings (loss) per unit:
Net income attributable to Crestwood Midstream Partners LP	$	4,465		$	14,381		$	18,293		$	30,984
Net income (loss) per limited partner unit	$	(0.01	)	$	0.06		$	0.06		$	0.21
General partner’s interest in net income attributable to Crestwood Midstream Partners LP	$	81		$	7,516		$	10,474		$	15,038
Limited partners’ interest in net income attributable to Crestwood Midstream Partners LP	$	4,384		$	6,865		$	7,819		$	15,946
Net income attributable to Crestwood Midstream Partners LP per limited partner unit:
Basic and Diluted	$	0.07		$	0.15		$	0.13		$	0.36

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

See accompanying notes.

CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED BALANCE SHEETS

(In thousands, except for unit data)

(Unaudited)

	June 30,			December 31,
	September 30,			December 31,
	2013			2012
ASSETS
Current assets
Cash and cash equivalents	$	~~110~~5,668		$	111
Accounts receivable		2127,~~772~~666			21,636
Accounts receivable—related party		2024,~~851~~050			23,755
Insurance receivable		3,~~496~~072			2,920
Prepaid expenses and other		~~1,476~~791			1,941
Assets held for sale		6,680			—
Total current assets		61,247			50,363
Total current assets		54,385			50,363
Property, plant and equipment, net of accumulated depreciation of $168,497 in 2013 and $130,030 in 2012		1,144,872			939,846
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 $22,448 in 2013 and $12,814 in 2012		428,880			501,380
Intangible assets, net of accumulated amortization of $23,821 in 2013 and $12,814 in 2012		490,503			501,380
Goodwill		99,596			95,031
Goodwill		95,031			95,031
Investment in unconsolidated affiliate		127,651			—
Deferred financing costs, net		2120,~~134~~719			22,528
Other assets		21,~~107~~018			1,321
Total assets	$	1,~~679~~883,~~930~~983		$	1,610,469
LIABILITIES AND PARTNERS’ CAPITAL
Current liabilities
Accrued additions to property, plant and equipment	$	3641,~~173~~248		$	9,213
Capital leases		32,~~408~~945			3,862
Deferred revenue		2,426			2,634
Accounts payable—related party		24,~~997~~517			3,088
Accounts payable, accrued expenses and other liabilities		3441,~~056~~035			29,717
Total current liabilities		7992,~~060~~171			48,514
Long-term debt		~~778~~899,~~944~~386			685,161
Long-term capital leases		1,~~509~~252			3,161
Asset retirement obligations		14,~~425~~633			14,024
Commitments and contingent liabilities (Note 7)
Commitments and contingent liabilities (Note 9)
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
Crestwood Midstream Partners LP partners’ capital
Common unitholders (53,765,676 and 41,164,737 units issued and outstanding at September 30, 2013 and December 31, 2012)		653,441			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			—
Class D unitholder (6,483,129 units issued and outstanding at September 30, 2013)		127,116			—
General partner (1,112,674 and 979,614 units issued and outstanding at June 30, 2013 and December 31, 2012)		3,134			257,353
General partner (1,112,674 and 979,614 units issued and outstanding at September 30, 2013 and December 31, 2012)		(2,012	)		257,353
Total partners’ capital		805,992			859,609
Total Crestwood Midstream Partners LP partners’ capital		778,545			859,609
Total liabilities and partners’ capital	$	1,679,930		$	1,610,469
Noncontrolling interests—preferred equity of subsidiary		97,996			—
Total partners’ capital		876,541			859,609
Total liabilities and partners’ capital	$	1,883,983		$	1,610,469

See accompanying notes.

CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CASH FLOWS

(In thousands)

(Unaudited)

	Six Months Ended
	Nine Months Ended
	June 30,
	September 30,
	2013			2012(1)
Cash flows from operating activities
Net income	$	1320,~~828~~216		$	1630,~~603~~984
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion		3549,~~061~~618			2435,~~341~~909
Equity-based compensation		1,378			994
Goodwill impairment		4,053			—
Other non-cash income items		2,067			2,546
Gain on sale of asset		(4,392	)		—
Equity-based compensation		2,138			1,528
Loss from unconsolidated affiliate		447			—
Other non-cash income items		3,203			3,743
Changes in assets and liabilities:
Accounts receivable		(~~136~~6,030	)		~~245~~(4,985	)
Accounts receivable—related party		~~2,904~~(295	)		4,~~010~~689
Insurance receivable		(~~576~~152	)		—
Prepaid expenses and other assets		~~(321~~1,453	)		~~(560~~783	)
Accounts payable—related party		~~(91~~1,429	)		(~~1,046~~900	)
Accounts payable, accrued expenses and other liabilities		39,~~415~~665			(46,~~919~~117	)
Net cash provided by operating activities		5781,~~529~~353			4277,~~214~~868
Cash flows from investing activities
Capital expenditures		(80164,~~297~~596	)		(2234,~~373~~346	)
Acquisitions, net of cash acquired		—			(~~376~~468,~~805~~987	)
Proceeds from sale of asset		11,000			—
Investment in unconsolidated affiliate		(128,098	)		—
Other		20			—
Net cash used in investing activities		(80281,~~277~~674	)		(~~399~~503,~~178~~333	)
Cash flows from financing activities
Proceeds from credit facilities		~~316~~483,~~900~~400			~~244~~377,700
Repayments of credit facilities		(~~223~~269,000	)		(~~176~~337,~~250~~500	)
Payments on capital leases		(23,~~248~~015	)		(12,~~375~~155	)
Deferred financing costs paid		(8285	)		(6,~~486~~489	)
Proceeds from issuance of common units, net		118,562			~~103~~217,~~034~~508
Contributions from partners		—			247,163
Proceeds from issuance of preferred equity of subsidiary, net		96,073			—
Contributions from partners		—			249,680
Distribution to General Partner for additional interest in CMM		(129,000	)		—
Distributions to partners		(5790,~~709~~357	)		(4573,~~471~~653	)
Taxes paid for equity-based compensation vesting		(~~676~~700	)		(~~402~~406	)
Net cash provided by financing activities		22205,~~747~~878			~~364~~424,~~913~~685
Change in cash and cash equivalents		(15,557	)		~~7,949~~(780	)
Cash and cash equivalents at beginning of period		111			797
Cash and cash equivalents at end of period	$	~~110~~5,668		$	~~8,746~~17

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

See accompanying notes.

CRESTWOOD MIDSTREAM PARTNERS LP

CONSOLIDATED STATEMENTS OF CHANGES IN PARTNERS’ CAPITAL

(In thousands)

(Unaudited)

	Limited Partners
	Common			Class CUnitholders			Class DUnitholder		General Partner			~~Total~~NoncontrollingInterest			Total
Partners’ capital as of December 31, 2012	$	442,348		$	159,908		$	—	$	257,353		$	~~859,609~~—		$	859,609
Issuance of units, net of offering costs		118,562			—			—		—			~~118,562~~—			118,562
Issuance of units		—			—			126,286		(126,286	)		—			—
Conversion of Class C units to Common units		159,908			(159,908	)		—		—			—
Issuance of preferred equity of subsidiary		—			—			—		—			96,073			96,073
Net income		3,077			—			358		10,393			13,828
Conversion of Class C units to common units		159,908			(159,908	)		—		—			—			—
Equity-based compensation		1,378			—			—		—			1,378
Net income		6,989			—			830		10,474			1,923			20,216
Taxes paid for equity-based compensation vesting		(676	)		—			—		—			(676	)
Equity-based compensation		2,138			—			—		—			—			2,138
Distributions to partners		(48,383	)		—			—		(9,326	)		(57,709	)
Taxes paid for equity-based compensation vesting		(700	)		—			—		—			—			(700	)
Distribution to General Partner for additional interest in CMM		—			—			—		(129,000	)		(129,000	)
Distributions to partners		(75,804	)		—			—		(14,553	)		—			(90,357	)
Partners’ capital as of June 30, 2013	$	676,214		$	—		$	126,644	$	3,134		$	805,992
Distribution to General Partner for additional interest in CMM		—			—			—		(129,000	)		—			(129,000	)
	Limited Partners
Partners’ capital as of September 30, 2013	$	653,441		$	—		$	127,116	$	(2,012	)	$	97,996		$	876,541
	Common			Class CUnitholders			Class DUnitholder		General Partner			Total
	Limited Partners
Partners’ capital as of December 31, 2011	$	286,945		$	157,386		$	—	$	11,292		$	455,623
	Common			Class CUnitholders			Class DUnitholder		General Partner			NoncontrollingInterest			Total
Issuance of units, net of offering costs		103,034			—			—		—			103,034
Partners’ capital as of December 31, 2011	$	286,945		$	157,386		$	—	$	11,292		$	—		$	455,623
Contributions from partners		—			—			—		247,163			247,163
Issuance of units, net of offering costs		217,508			—			—		—			—			217,508
Net income		7,664			1,417					7,522			16,603
Contributions from partners		—			—			—		249,680			—			249,680
Equity-based compensation		994			—			—		—			994
Net income		13,532			2,414			—		15,038			—			30,984
Taxes paid for equity-based compensation vesting		(402	)		—			—		—			(402	)
Equity-based compensation		1,528			—			—		—			—			1,528
Distributions to partners		(36,172	)		—			—		(9,299	)		(45,471	)
Taxes paid for equity-based compensation vesting		(406	)		—			—		—			—			(406	)
Partners’ capital as of June 30, 2012(1)	$	362,063		$	158,803		$	—	$	256,678		$	777,544
Distributions to partners		(56,730	)		—			—		(16,923	)		—			(73,653	)
Partners’ capital as of September 30, 2012(1)	$	462,377		$	159,800		$	—	$	259,087		$	—		$	881,264

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

See accompanying notes.

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

UNAUDITED

1. ORGANIZATION AND DESCRIPTION OF BUSINESS

Organization

Prior to the Crestwood Midstream Partners LP (CMLP) ismerger with Inergy Midstream, L.P. (NRGM) on October 7, 2013 discussed below, CMLP was a publicly traded Delaware limited partnership formed for the purpose of acquiring and operating midstream assets. ~~Our~~CMLP’s common units ~~are~~were listed on the New York Stock Exchange (NYSE) under the symbol “CMLP.” ~~Prior to June 19, 2013,~~ Crestwood Gas Services GP LLC, ~~our~~was the CMLP general partner (General Partner), ~~was~~until ~~owned~~the byeffective ~~Crestwood~~date ~~Holdings~~of ~~Partners~~our ~~LLC~~Merger ~~and~~described ~~its affiliates (Crestwood Holdings)~~below. 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 Partners LLC and its affiliates (Crestwood Holdings). Prior to June 19, 2013, the General Partner was owned by 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~~October 57, 2013, CMLP wecompleted ~~entered~~the ~~into~~merger (the Merger) with a ~~definitive~~subsidiary of NRGM pursuant to a merger agreement ~~under~~dated ~~which~~as weof ~~will~~May 5, be2013. Immediately following the Merger, CMLP merged with aand ~~subsidiary~~into ofNRGM, ~~Inergy~~with NRGM continuing as the surviving entity and changing its name to Crestwood Midstream, ~~L.P.~~Partners LP (~~NRGM~~Crestwood Midstream). inThe acommon ~~merger~~units inof ~~which~~the ~~our~~combined partnership are listed on the NYSE under the symbol “CMLP.” Under the merger agreement, CMLP unitholders ~~receive~~received 1.07 units of NRGM units for each unit of CMLP they ~~own. Additionally~~owned and as a result, ~~under~~ there were no CMLP common or Class D units outstanding immediately following the ~~merger~~Merger. ~~agreement~~Additionally, ~~our~~CMLP unitholders (other than Crestwood Holdings), ~~will~~received ~~receive~~ a one-time approximately $35 million cash payment at the closing of the ~~merger transaction~~Merger, or $1.03 per unit, $25 million of which ~~will~~was bepaid ~~payable~~ by NRGM and approximately $10 million of which ~~will~~was bepaid ~~payable~~ by Crestwood Holdings. ~~The~~ ~~merger~~Also ofin ~~NRGM~~conjunction ~~and~~with ~~CMLP is conditioned upon~~ the ~~approval~~Merger, ofCMLP ~~the~~was ~~holders~~delisted ofon ~~a majority of~~ the ~~limited partner interests of CMLP and other customary closing conditions~~NYSE.

Organizational Structure – Will be updated to reflect Preferred Units in Crestwood Niobrara

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

LOGO

10(1) Concurrent with the October 7, 2013 merger discussed above, NRGY changed its name from Inergy, L.P. to Crestwood Equity Partners LP and changed its NYSE listing symbol from “NRGY” to “CEQP.”

~~Table~~10 ~~of Contents~~

	CrestwoodHoldings			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

~~Description~~We ofare ~~Business~~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.

We2. ~~are~~BASIS aOF ~~growth-oriented~~PRESENTATION ~~midstream~~AND ~~master~~SUMMARY ~~limited~~OF ~~partnership~~SIGNIFICANT ~~which~~ACCOUNTING ~~owns~~POLICIES 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 ~~BASIS~~of OFPresentation ~~PRESENTATION AND SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES~~

~~Basis~~We prepared this Quarterly Report on Form 10-Q under the rules and regulations of ~~Presentation~~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 ~~prepared~~accounted for this ~~Quarterly~~transaction ~~Report~~as ona ~~Form~~reorganization ~~10-Q~~of entities under common control and the ~~rules~~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 ~~regulations~~liabilities. Earnings related to the recast of our historical results due to the ~~SEC~~acquisition ~~and~~of the 65% membership interest in ~~accordance~~CMM ~~with~~were ~~accounting~~allocated ~~principles~~to ~~generally~~the ~~accepted~~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 ~~United~~issuance ~~States~~of 6,190,469 Class D units, representing limited partner interests in us to Crestwood Holdings, and the issuance of ~~America~~133,060 ~~(GAAP)~~general ~~for~~partner ~~interim consolidated~~units ~~financial~~to ~~statements~~our General Partner. ~~Accordingly,~~For ~~they~~accounting dopurposes, ~~not~~because ~~include~~of ~~all~~the consolidation of CMM, we reflected the ~~disclosures~~$129 ~~required~~million bycash ~~GAAP.~~paid to acquire the 65% interest in CMM and the issuance of Class D units as a reduction of our General Partner’s capital.

~~On March 26,~~You ~~2012,~~should ~~Crestwood~~read ~~Holdings~~this ~~contributed~~Quarterly ~~approximately~~Report ~~$244~~on ~~million~~Form ~~for~~10-Q aalong ~~65%~~with ~~membership~~our ~~interest~~Form in8-K ~~Crestwood~~filed ~~Marcellus~~with ~~Midstream~~the ~~LLC~~SEC ~~(CMM)~~on ~~and we contributed approximately $131 million for a 35% membership interest in CMM. On January~~May 810, 2013,. weThe ~~acquired~~financial statements ~~Crestwood Holdings’ 65% membership interest in CMM and~~ as aof ~~result~~September 30, we2013 ~~now~~and ~~own~~for ~~100%~~the ofthree ~~CMM~~ and ~~have~~nine ~~the~~months ~~ability~~ended toSeptember 30, ~~control~~2013 ~~the operating~~ and ~~financial~~2012 ~~decisions~~are ~~of CMM~~unaudited. WeThe ~~accounted~~consolidated ~~for~~balance ~~this~~sheet ~~transaction~~ as ~~a reorganization~~ of ~~entities~~December 31, ~~under~~2012, ~~common~~was ~~control~~derived ~~and~~from the ~~accounting~~audited ~~standards~~balance ~~related~~sheet tofiled ~~such~~in ~~transactions require us to retroactively adjust~~ our Form ~~historical~~8-K ~~results.~~filed ~~Accordingly,~~with the ~~consolidated~~SEC ~~balance~~on ~~sheets~~May 10, ~~reflect~~2013. ~~the~~In ~~historical carrying value of CMM~~management’s ~~assets~~opinion, ~~and~~all ~~liabilities.~~necessary ~~Earnings~~adjustments ~~related~~ to ~~the~~fairly ~~recast~~present of our ~~historical~~ results ~~due to the acquisition~~ of ~~the~~operations, ~~65%~~financial ~~membership~~position ~~interest~~and incash ~~CMM~~flows ~~were~~for ~~allocated to~~ the ~~General~~periods ~~Partner.~~presented Ashave abeen ~~result,~~made ~~there~~and ~~was~~all ~~no impact to our 2012 reported~~such ~~basic~~adjustments orare ~~diluted~~of ~~earnings~~a ~~per~~normal ~~limited~~and ~~partner~~recurring ~~unit~~nature. WeInformation ~~funded the purchase price~~ for ~~the~~interim ~~65%~~periods ~~membership~~may ~~interest~~not inbe ~~CMM~~indicative of ~~approximately $258 million through $129 million of borrowings under~~ our ~~CMLP~~operating ~~credit~~results ~~facility,~~for the ~~issuance~~entire ofyear. ~~6,190,469~~Our ~~Class D~~disclosures ~~units,~~in ~~representing~~this ~~limited~~Form ~~partner~~10-Q ~~interests~~are inan usupdate to ~~Crestwood~~those ~~Holdings,~~provided ~~and~~in ~~the issuance of 133,060 general partner units to~~ our ~~General~~Form ~~Partner.~~8-K ~~For~~filed ~~accounting~~with ~~purposes, because of~~ the ~~consolidation of CMM, we reflected the $129 million cash~~ ~~paid~~SEC toon ~~acquire the 65% interest in CMM and the issuance of Class~~May D10, ~~units as a reduction of our General Partner’s capital~~2013.

~~You~~Significant ~~should~~Accounting ~~read~~Policies 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~~There ~~Accounting~~were ~~Policies~~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.

~~There~~Revenues ~~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 separate from other services provided under our contracts. For the three and nine months ended September 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). The majority of our processing revenues are generated from contracts under which we charge a fixed-fee. Under certain of 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.

~~Our~~Goodwill 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

11Our goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. We have assigned our goodwill to four of our operating segments (Marcellus, Granite Wash, Fayetteville and Haynesville) which, based on management’s judgment, we also consider reporting units for goodwill assessment purposes.

~~Table~~We evaluate goodwill for impairment, at a minimum, annually on December 31, or whenever events or changes indicate that it is more likely than not that the fair value of ~~Contents~~a reporting unit could be less than its carrying amount. This evaluation requires us to compare the fair value of each of the three reporting units above to its carrying value (including goodwill). If the fair value exceeds the carry amount, goodwill of the reporting unit is not considered impaired.

~~separate~~11 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.

~~Acquisitions~~We estimate the fair value of our reporting units based on a number of factors, including the potential value we would receive if we sold the reporting unit, discount rates and projected cash flows. Projected cash flows of the reporting unit are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

~~Antero~~During ~~Acquisition~~the three months ended September 30, 2013, we recorded an impairment of goodwill of approximately $4 million on our Haynesville/Bossier Shale system as a result of a decrease in anticipated revenues to be generated from those operations due primarily to our inability to renew and extend a significant revenue contract that expired in mid-2013.

OnInvestment ~~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~~Unconsolidated ~~Marcellus~~Affiliate 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~~We ~~GGA~~apply ~~with~~the ~~Antero~~equity ~~provides~~method ~~for~~of anaccounting ~~area~~where ofwe ~~dedication~~can atexert ~~the~~significant ~~time~~influence ofover, ~~acquisition~~but ofdo ~~approximately~~not ~~127,000 gross~~control ~~acres,~~ or ~~104~~direct,~~000~~ ~~net~~the ~~acres~~policies, ~~largely~~decisions or ~~located~~activities inof the ~~rich~~entity. ~~gas~~We ~~corridor~~use of the ~~southwestern~~cost ~~core~~method of ~~the~~accounting ~~Marcellus~~where ~~Shale~~we ~~play.~~are Asunable ~~part~~to ofexert ~~the~~significant ~~GGA,~~influence ~~Antero~~over ~~committed~~the toentity. ~~deliver~~The ~~minimum~~Financial ~~annual~~Accounting ~~throughput~~Standards ~~volumes~~Board’s toaccounting usstandards ~~for~~related ato ~~seven~~equity ~~year~~method ~~period~~investments ~~from~~and joint ~~January 1,~~ventures ~~2012~~requires entities to ~~January 1,~~periodically ~~2019,~~review ~~ranging~~their ~~from~~equity anmethod ~~average~~investments ofto ~~300 million~~determine ~~cubic~~whether ~~feet~~current ~~per~~events ~~day~~or ~~(MMcf/d)~~circumstances inindicate ~~2012~~that tothe ancarrying ~~average~~value of ~~450~~the ~~MMcf/d~~equity inmethod ~~2018.~~investment ~~During~~may ~~the~~be ~~period~~impaired. ~~ended~~We ~~December 31,~~evaluate ~~2012,~~our ~~Antero~~equity ~~delivered~~method investment ~~less~~for ~~than~~impairment ~~the~~when ~~minimum annual~~there ~~throughput~~are ~~volumes~~indicators ~~and~~of atimpairment. ~~December 31,~~If ~~2012,~~indicators suggest impairment we ~~recorded~~will aperform ~~receivable~~an ~~and~~impairment ~~deferred~~test ~~revenue~~to ofassess ~~approximately~~whether $2an adjustment is necessary.6 ~~million~~The ~~due~~impairment totest ~~Antero’s~~considers ~~potential~~whether ~~ability~~the tofair ~~recover~~value ~~this~~of ~~amount~~our equity method investment has declined and if ~~Antero’s~~any ~~2013~~such ~~throughput~~decline ~~volumes~~is ~~exceed~~other ~~the minimum~~than ~~annual~~temporary. ~~throughput~~If ~~volumes~~a ~~included~~decline in fair value is determined to be other than temporary, the ~~GGA~~investment’s ~~for~~carrying ~~2013~~value is written down to fair value.

~~The~~3. ~~final~~ACQUISITIONS ~~purchase~~AND ~~price~~DIVESTITURES ~~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

Acquisitions

~~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~~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.

OnThe ~~August 24,~~GGA ~~2012,~~with weAntero ~~completed~~provides for an area of dedication at the time of acquisition of ~~certain~~approximately ~~gathering~~127,000 ~~and~~gross ~~processing~~acres, ~~assets~~or 104,000 net acres, largely located in the ~~NGL~~ rich gas ~~region~~corridor of the ~~Barnett~~ southwestern core of the Marcellus Shale ~~from~~play. ~~Devon~~As ~~Energy~~part ~~Corporation~~of ~~(Devon)~~the GGA, Antero committed to deliver minimum annual throughput volumes to us for ~~approximately~~a ~~$87~~seven year period from January 1, 2012 to January 1, 2019, ranging from an average of 300 million ~~(Devon~~cubic ~~Acquisition~~feet per day (MMcf/d). ~~The~~in ~~final~~2012 ~~purchase~~to ~~price~~an ~~allocation~~average isof ~~pending~~450 MMcf/d in 2018. During the ~~completion~~period ofended December 31, 2012, Antero delivered less than the ~~valuation~~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 ~~assets~~minimum ~~acquired~~annual throughput ~~and~~volumes ~~liabilities~~included ~~assumed~~in the GGA for 2013.

12The 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

~~The~~12 ~~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~~Antero Acquisition relate to the 20GGA ~~year fixed-fee gathering, processing and compression agreement~~ with ~~Devon~~ Antero. These intangible assets will be amortized over the life of the contract. For the period from the acquisition date (March 26, 2012) to September 30, 2012, we recorded approximately $15 million of operating revenues and $7 million of operating expenses related to the operations of the assets acquired from Antero.

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~~Acquisition ~~significantly different terms than the historical intercompany relationships between the acquired assets and Devon.~~

~~EMAC~~On August 24, 2012, we completed the acquisition of certain gathering and processing assets in the NGL rich gas region of the Barnett Shale (Devon Acquisition) from Devon Energy Corporation (Devon). We paid approximately $88 million for these assets. During the three months ended September 30, 2013, we finalized the purchase price allocation of the assets acquired and liabilities assumed, and as a result, we reduced our depreciation, amortization and accretion expense by approximately $2 million.

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~~as ~~the~~follows ~~completion~~(In ofthousands): ~~the valuation of the assets acquired and liabilities assumed.~~

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


Cash	$	87,943

Total purchase price	$	87,943

Purchase price allocation:
Property, plant and equipment	$	88,626

Total assets	$	88,626

Asset retirement obligation	$	483
Environmental liability		200

Total liabilities	$	683

Total	$	87,943

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

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.

~~Our intangible assets recorded as a result of the~~ EMAC ~~acquisition~~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.

13On December 28, 2012, CMM acquired all of the membership interest of E. Marcellus Asset Company, LLC (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.

~~Table~~During the three months ended September 30, 2013, we finalized the purchase price allocation of ~~Contents~~the assets acquired and liabilities assumed, and as a result, we reduced our depreciation, amortization and accretion expense by approximately $1 million. In addition, we recognized goodwill of approximately $9 million, primarily related to anticipated operating synergies between the assets acquired and our existing assets.

~~Divestitures~~13

4.The ~~NET~~final ~~INCOME~~purchase ~~PER~~price ~~LIMITED~~allocation ~~PARTNER~~is ~~UNIT~~as ~~AND~~follows ~~DISTRIBUTIONS~~(In thousands):

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.


Cash	$	94,979

Total purchase price	$	94,979

Purchase price allocation:
Property, plant and equipment	$	53,357
Intangible assets		33,909
Goodwill		8,618

Total assets	$	95,884

Asset retirement obligation	$	755
Environmental liability		150

Total liabilities	$	905

Total	$	94,979

~~The~~Our ~~tables~~intangible ~~below~~assets ~~show~~recorded ~~the~~as ~~(i) allocation~~a result of ~~net~~the ~~income~~EMAC ~~attributable~~acquisition relate to ~~limited~~the ~~partners~~compression ~~and~~services agreements ~~the~~with ~~(ii) net~~Antero. ~~income~~These ~~per~~intangible ~~limited partner~~assets ~~unit~~will ~~based~~be onamortized over the ~~number~~life of ~~basic~~the ~~and~~contract. ~~diluted~~Pro ~~limited~~forma ~~partner~~information ~~units~~has ~~outstanding~~not been provided for the ~~three~~acquisition ~~and~~of ~~six~~the ~~months~~EMAC ~~ended~~assets ~~June 30,~~as ~~2013~~the ~~and~~impact ~~2012~~is immaterial to our financial statements.

~~Allocation~~Divestitures ~~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

On July 25, 2013, we sold a cryogenic plant and associated equipment for approximately $11 million (net of fees) and recognized a gain of approximately $4 million during the three months ended September 30, 2013.

144. EARNINGS PER LIMITED PARTNER UNIT AND DISTRIBUTIONS

~~Table~~Earnings Per Limited Partner Unit. Our net income attributable to CMLP 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 attributable to CMLP, 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 ~~Contents~~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 attributable to CMLP and limited partner units from the potential issuance of limited partner units.

~~Net~~The ~~Income~~tables ~~Per~~below ~~Limited~~show ~~Partner~~the ~~Unit~~(i) allocation of net income attributable to limited partners and the (ii) net income attributable to CMLP per limited partner unit based on the number of basic and diluted limited partner units outstanding for the three and nine months ended September 30, 2013 and 2012.

	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

Allocation of Net Income Attributable to CMLP to General Partner and Limited Partners

(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.


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
	(In thousands)
Net income attributable to CMLP	$	4,465		$	14,381		$	18,293		$	30,984
General Partner’s incentive distributions ⁽¹⁾		—			(4,101	)		(10,140	)		(10,636	)

Net income attributable to CMLP after incentive distributions		4,465			10,280			8,153			20,348
General Partner’s interest in net income attributable to CMLP after incentive distributions		(81	)		(3,415	)		(334	)		(4,402	)

Limited Partners’ interest in net income attributable to CMLP after distributions	$	4,384		$	6,865		$	7,819		$	15,946

~~There~~(1) ~~were~~As ~~274~~a ~~unvested~~result ~~phantom~~of ~~units~~the ~~excluded~~Merger ~~from~~on ~~our~~October ~~diluted~~7, ~~earnings~~2013 ~~per~~described ~~unit~~in asNote ~~our~~1. ~~limited~~Organization ~~partners’~~and ~~interest~~Description inof ~~net~~Business, ~~income~~there ~~was~~were ano ~~loss~~distributions to CMLP’s unitholders for the three months ended ~~June~~ September 30, 2013.; ~~There~~therefore, ~~were no units excluded from~~ our ~~diluted~~General ~~earnings~~Partner ~~per~~did ~~unit as we do~~ not ~~have~~receive any ~~anti-dilutive~~incentive ~~units~~distributions ~~for~~attributable ~~the~~to ~~six~~that ~~months ended June 30, 2013 and the three and six months ended June 30, 2012~~period.

~~Distributions.~~14 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.

				Distributions Paid
				Limited Partner						General Partner
Payment Date	Attributable to the Quarter Ended	Per UnitDistribution		Cash paidto common(1)		Paid-In-Kind Value toClass Cunitholders		Paid-In-Kind Value toClass Dunitholder		Cash paidto GeneralPartnerand IDR		Paid-In-Kind Value toClass Cunitholder		Paid-In-Kind Value toClass Dunitholder		TotalCash		TotalDistribution
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

Earnings Per Limited Partner Unit

~~(1)~~Three ~~Distributions~~Months ~~for~~Ended ~~the quarter ended June~~ September 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.


	2013		2012
	(In thousands, except per unit data)
Limited partners’ interest in net income attributable to CMLP	$	4,384	$	6,865
Weighted-average limited partner units—basic ⁽¹⁾		60,188		46,564
Effect of dilutive units		260		203

Weighted-average limited partner units—diluted ⁽¹⁾		60,448		46,767

Basic and diluted net income attributable to CMLP per limited partner unit	$	0.07	$	0.15

15(1) The three months ended September 30, 2013 includes 6,421,641 Class D units. The three months ended September 30, 2012 includes 6,929,763 Class C units.

~~Table~~Nine ofMonths ~~Contents~~Ended September 30,

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.


	2013		2012
	(In thousands, except per unit data)
Limited partners’ interest in net income attributable to CMLP	$	7,819	$	15,946
Weighted-average limited partner units—basic ⁽¹⁾		58,339		44,206
Effect of dilutive units		269		189

Weighted-average limited partner units—diluted ⁽¹⁾		58,608		44,395

Basic and diluted net income attributable to CMLP per limited partner unit	$	0.13	$	0.36

~~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~~1) ~~providing~~The ~~net~~nine ~~proceeds~~months ofended ~~approximately~~September ~~$103.5 million. We granted the underwriters a~~ 30~~-day option to purchase up to 675~~,~~000~~ ~~additional common~~2013 ~~units~~includes ~~if the underwriters sold more than 4~~8,~~500~~536,~~000~~178 ~~common~~Class ~~units~~C inand ~~the~~Class ~~offering.~~D ~~The underwriters exercised this option on April 5, 2013 providing net proceeds of approximately $15~~units.5 ~~million.~~ The ~~unitholders~~nine ofmonths ~~these common units received a quarterly distribution for the period~~ ended ~~March 31~~September 30, ~~2013.~~2012 Inincludes ~~connection with the issuance of the common units~~6,795,130 ~~our~~Class ~~General~~C ~~Partner did not make an additional capital contribution to us resulting in a reduction in their general partner interest in us to approximately 1~~units.~~8% at June 30, 2013.~~

~~See~~We ~~our~~exclude ~~2012~~potentially ~~Annual~~dilutive ~~Report~~securities from the determination of diluted earnings per unit (as well as their related income statement impacts) when their impact on ~~Form~~net 10income attributable to CMLP per limited partner unit is anti-Kdilutive. ~~for~~For ~~additional~~the three and nine months ended September 30, 2013, we excluded 3,262,275 and 1,099,375 preferred security units issued by our ~~information~~consolidated ~~regarding~~subsidiary, Crestwood Niobrara LLC (Crestwood Niobrara), from our ~~distributions~~diluted earnings per unit. There were no units excluded from our diluted earnings per unit as we did not have any anti-dilutive units for the three and nine months ended September 30, 2012. Our potentially dilutive securities for the three and nine months ended September 30, 2013 and 2012 consist of unvested phantom units.

5Distributions. ~~FINANCIAL~~Our ~~INSTRUMENTS~~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. As a result of the Merger on October 7, 2013 described in Note 1. Organization and Description of Business, there were no distributions to CMLP’s unitholders for the three months ended September 30, 2013. Under the merger agreement, CMLP unitholders received 1.07 units of NRGM units for each unit of CMLP they owned and such unitholders will receive a distribution for the three months ended September 30, 2013 as determined by Crestwood Midstream’s board of directors.

~~Fair~~15 ~~Values~~

~~Cash~~The ~~and~~following ~~Cash~~table ~~Equivalents,~~presents ~~Accounts~~distributions ~~Receivable~~for ~~and Accounts Payable. As of June 30,~~ 2013 and ~~December 31,~~ 2012, ~~the carrying~~(In ~~amounts of cash and cash equivalents~~millions, ~~accounts~~except ~~receivable~~per ~~and~~unit ~~accounts payable represent fair value based on the short-term nature of these instruments.~~ data):

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.


				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	$	27.4	$	—	$	3.2	$	5.2	$	—	$	0.5	$	32.6	$	36.3
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

~~Senior Notes. We estimated the fair value of our 7.75% Senior Notes due April 2019~~ (~~Senior Notes~~1) ~~(representing~~Distributions ~~a Level 2 fair value measurement) primarily based on quoted market prices~~ for the ~~same~~quarters orended ~~similar~~June ~~issuances.~~30, ~~The~~2012 ~~following~~and ~~table~~September ~~reflects~~30, ~~the~~2012 ~~carrying~~exclude ~~value~~approximately $3 million and ~~fair value~~$4 ofmillion ~~our~~paid ~~Senior~~by ~~Notes~~CMM ~~(In~~to ~~millions):~~Crestwood Holdings.

	June 30, 2013				December 31, 2012
	CarryingAmount		FairValue		CarryingAmount		FairValue
Senior Notes	$	351	$	362	$	351	$	365

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 and 141,422 additional Class D units in lieu of paying cash quarterly distributions on our Class D units attributable to the quarters ended March 31, 2013 and June 30, 2013.

~~Debt~~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 option to pay distributions to our Class C unitholders with cash or by issuing additional Paid-In-Kind Class C units, based upon the volume weighted-average price of our common units for the 10 trading days immediately preceding the date the distribution is declared. 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, 138,731 and 174,230 additional Class C units in lieu of paying cash quarterly distributions on our Class C units attributable to the quarters ended March 31, 2012, June 30, 2012 and September 30, 2012.

~~Our~~On ~~long-term~~March 22, ~~debt~~2013, ~~consists~~we completed a public offering of ~~the~~4,500,000 ~~following~~common units, representing limited partner interests in us, at a price of $23.90 per common unit (In$23.00 ~~thousands~~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.

	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

5. INVESTMENT IN UNCONSOLIDATED AFFILIATE

16On July 19, 2013, Crestwood Niobrara acquired RKI Exploration and Production, LLC’s (RKI) 50% interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) for approximately $108 million. RKI is a privately-owned, independent exploration and production company in which an affiliate of our General Partner owns a significant minority ownership interest, and therefore is considered our related party. Access Midstream Partners, L.P. (Access) owns the remaining 50% interest in and operates Jackalope. Crestwood Niobrara manages the commercial operations of the Jackalope system. We account for our investment in Jackalope under the equity method of accounting.

~~Table~~The Jackalope gathering and processing system is currently comprised of ~~Contents~~approximately 100 miles of gathering pipelines and 9,400 horsepower of compression equipment located in Converse County, Wyoming. The existing Jackalope assets and planned future development are supported by a 20-year gathering and processing agreement with Chesapeake Energy Corporation and RKI under which Jackalope 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. During the three months ended September 30, 2013, Crestwood Niobrara contributed an additional $20 million to Jackalope to fund its construction projects.

~~Credit~~16 ~~Facilities~~

~~Borrowings~~We ~~under~~have reflected the ~~CMM~~earnings ~~Credit~~from ~~Facility~~our ~~bear~~investment ~~interest~~in atJackalope ~~the~~in ~~London~~our ~~Interbank~~consolidated ~~Offered~~statements ~~Rate~~of income, ~~(LIBOR)~~which ~~plus~~includes anour ~~applicable~~share ~~margin~~of ornet ~~base~~earnings ~~rate~~based ason ~~defined~~our inownership ~~the~~interest ~~CMM~~and ~~Credit~~other ~~Facility~~adjustments recorded by us as discussed below. ~~Under~~During the ~~terms~~three ofand ~~the~~nine ~~CMM Credit~~months ~~Facility~~ended September 30, ~~the~~2013, ~~applicable~~our ~~margin~~share ~~under~~of ~~LIBOR~~Jackalope’s net earnings was approximately $0.2 million.5% atAs ~~both~~of ~~June~~September 30, 2013 ~~and December 31~~, ~~2012.~~our ~~The~~investment ~~weighted-average~~balance ~~interest~~in ~~rate~~Jackalope atexceeded ~~both~~our ~~June 30,~~equity ~~2013~~in ~~and~~the ~~December 31,~~underlying ~~2012~~net ~~was~~assets ~~2.8%.~~of ~~Based~~Jackalope onby ~~our~~approximately ~~results~~$57 ~~through June 30,~~million. ~~2013,~~We ~~our~~amortize ~~remaining~~and ~~available~~generally ~~capacity~~assess ~~under~~ the ~~CMM~~recoverability ~~Credit~~of ~~Facility~~this amount ~~was~~based ~~$73~~on ~~million. For~~ the ~~three~~life ~~and~~of ~~six~~Jackalope’s ~~months~~gathering ~~ended~~agreement. ~~June 30,~~The ~~2013,~~amortization ~~our~~is ~~average~~reflected ~~outstanding~~as ~~borrowings~~a ~~were~~reduction ~~approximately~~of ~~$102~~our ~~million~~earnings ~~and~~from ~~$112~~unconsolidated ~~million.~~affiliate, ~~For~~and during the three and ~~six~~nine months ended ~~June~~September 30, 2013, ~~our~~we ~~maximum~~recorded amortization ~~outstanding~~expense ~~borrowings~~of ~~were~~ approximately $~~127~~0.6 million ~~and $130 million~~.

~~The~~In ~~CMM~~accordance ~~Credit~~with ~~Facility~~the ~~requires~~Jackalope ~~CMM~~limited liability company agreement, Jackalope is required to ~~maintain:~~make quarterly distributions of its available cash to its members based on their respective ownership percentage.

•6. aPREFERRED ~~ratio~~EQUITY ofOF ~~trailing~~SUBSIDIARY ~~12-month EBITDA (as defined in the CMM Credit Facility) to net interest expense of not less than 2.0 to 1.0; and~~

•In conjunction with Crestwood Niobrara’s acquisition discussed in Note 5. Investment in Unconsolidated Affiliate, Crestwood Niobrara issued a ~~ratio~~preferred interest of ~~total~~approximately ~~indebtedness~~$81 million to ~~trailing~~a ~~12-month~~subsidiary ~~EBITDA~~of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE EFS). The preferred interest is reflected as noncontrolling ~~defined~~interest in ~~the~~our ~~CMM~~consolidated ~~Credit~~financial ~~Facility)~~statements. ofDuring ~~not~~the ~~more~~three ~~than~~and ~~4.5~~nine tomonths ~~1.0~~ended September 30, or2013, ~~not~~we ~~more~~allocated ~~than~~approximately ~~5.0~~$2 tomillion ~~1.0~~of ~~for~~net upincome to ~~nine~~the ~~months~~noncontrolling ~~following~~interest, ~~certain~~which ~~acquisitions~~was based on the overall return attributable to the preferred security.

~~CMLP~~Crestwood ~~Credit~~Niobrara ~~Facility.~~will ~~Our~~fund ~~amended~~75% ~~and restated~~of ~~senior~~future ~~secured~~capital ~~credit~~contributions ~~agreement,~~to ~~dated~~Jackalope ~~November 16,~~through additional ~~2012~~preferred ~~(CMLP~~interest ~~Credit~~issuances ~~Facility),~~to ~~allows~~GE ~~for~~EFS ~~revolving~~(up ~~loans,~~to ~~letters~~a maximum of ~~credit~~an ~~and~~additional ~~swingline~~$69 ~~loans~~million), inwith anthe ~~aggregate~~remainder ~~amount~~to ofbe upfunded through our capital contributions to ~~$550~~Crestwood ~~million~~Niobrara. ~~The~~During ~~CMLP~~the ~~Credit~~three ~~Facility~~and isnine ~~secured~~months byended September 30, ~~substantially~~2013, ~~all~~GE EFS contributed approximately $96 million (which consisted of ~~CMLP’s~~the ~~assets~~initial contribution of $81 million and ~~those~~additional ofcapital ~~certain~~contributions of ~~its~~approximately ~~subsidiaries.~~$15 Asmillion) to Crestwood Niobrara in exchange for an equivalent number of ~~June 30,~~preferred units. ~~2013,~~The ~~the~~proceeds ~~CMLP~~from ~~Credit~~the ~~Facility~~initial isGE ~~guaranteed~~EFS bycontribution ~~our~~were ~~100%~~used ~~owned~~to ~~subsidiaries~~purchase ~~except~~the ~~for~~investment ~~CMM~~in Jackalope and ~~its~~the ~~consolidated~~proceeds ~~subsidiaries~~from the subsequent contributions were used to fund capital contributions to the Jackalope investment.

~~Borrowings~~In ~~under~~accordance with the ~~CMLP~~Crestwood ~~Credit~~Niobrara ~~Facility~~limited ~~bear~~liability ~~interest~~company atagreement, ~~LIBOR~~Crestwood ~~plus~~Niobrara anhas ~~applicable~~the ~~margin~~option orto apay ~~base~~distributions ~~rate~~to asGE EFS ~~defined~~with incash ~~the~~or ~~CMLP~~by ~~Credit Facility.~~issuing ~~Under~~additional ~~the~~preferred ~~terms~~units ofthrough the ~~CMLP~~January ~~Credit~~2015 ~~Facility, the applicable margin under LIBOR borrowings was 2~~distribution.8% ~~and~~On ~~2.5% at June~~October 30, 2013 ~~and December 31~~, ~~2012.~~Crestwood ~~The~~Niobrara ~~weighted-average~~issued ~~interest~~GE ~~rate~~EFS asapproximately ~~of June 30~~2, ~~2013 and December 31~~161, ~~2012~~657 million ~~was~~units ~~3.0%~~in ~~and~~lieu ~~2.8%.~~of ~~Based~~paying ona ~~our~~cash ~~results~~distribution. ~~through~~We ~~June 30,~~serve ~~2013, our remaining available capacity under~~ as the ~~CMLP~~managing ~~Credit~~member ~~Facility~~of ~~was~~Crestwood ~~$111~~Niobrara ~~million. For the three~~ and, ~~six~~subject ~~months~~to ~~ended~~certain ~~June 30~~restrictions, ~~2013,~~we ~~our~~have ~~average~~the ~~outstanding~~ability ~~borrowings~~to ~~were $312~~redeem ~~million~~GE ~~and~~EFS’ ~~$324~~preferred ~~million.~~security ~~For~~in ~~the~~either ~~three~~cash ~~and~~or ~~six~~CMLP ~~months~~common ~~ended~~units ~~June 30,~~of ~~2013,~~the ~~our~~combined ~~maximum~~partnership ~~outstanding~~as ~~borrowings~~discussed ~~were~~in ~~$328~~Note ~~million~~1. Organization and Description ~~$373~~of ~~million~~Business.

~~Our~~7. ~~CMLP~~FINANCIAL ~~Credit~~INSTRUMENTS ~~Facility requires us to maintain:~~

•Fair aValues ~~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~~

•We separate athe ~~ratio~~fair values of ~~total~~our ~~indebtedness~~financial toinstruments ~~consolidated~~into ~~trailing~~three ~~12-month~~levels ~~EBITDA~~ (asLevels ~~defined~~1, in2 ~~the~~and ~~CMLP~~3) ~~Credit~~based ~~Facility)~~on our assessment of ~~not~~the ~~more~~availability ~~than~~of ~~5.0~~observable market data and the significance of non-observable data used to 1determine fair value.0, Our assessment and classification of an instrument within a level can change over time based on the maturity or ~~not~~liquidity ~~more~~of ~~than~~the 5instrument and would be reflected at the end of the period in which the change occurs.5 At September 30, 2013 and December 31, 2012, there have been no changes to ~~1.0~~the ~~for~~inputs upand valuation techniques used to ~~nine~~measure ~~months~~fair ~~following~~value, ~~certain~~the ~~acquisitions~~types of instruments, or the levels in which they are classified.

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable. As of ~~June~~September 30, 2013 and December 31, we2012, the ~~were~~carrying inamounts ~~compliance~~of ~~with~~cash ~~the~~and ~~financial~~cash ~~covenants~~equivalents, ~~under~~accounts ~~each~~receivable ofand accounts payable represent fair value based on the ~~CMM~~short-term ~~and~~nature ~~CMLP~~of ~~Credit~~these ~~Facilities~~instruments.

~~Our~~Credit ~~credit~~Facilities. ~~facilities contain~~The ~~restrictive~~fair ~~covenants~~value ~~that prohibit the declaration or payment~~ of ~~distributions~~our bycredit usfacilities ifapproximates atheir ~~default~~carrying ~~then~~amounts ~~exists~~as orof ~~would~~September 30, ~~result~~2013 ~~therefrom~~and December 31, ~~and~~2012 ~~otherwise~~due ~~limits~~primarily to the ~~amount~~variable ofnature ~~distributions that we can make. An event~~ of ~~default may result in~~ the ~~acceleration~~interest ofrate ~~our repayment~~ of ~~outstanding~~the ~~borrowings under our credit facilities~~instrument, ~~the~~which ~~termination~~is ofconsidered ~~our~~a ~~credit~~Level ~~facilities~~2 ~~and~~fair ~~foreclosure~~value ~~on collateral~~measurement.

~~Senior~~17 ~~Notes~~

17Senior 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):


	September 30, 2013				December 31, 2012
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Senior Notes	$	351	$	369	$	351	$	365

6.Debt ~~ACCOUNTS PAYABLE, ACCRUED EXPENSES AND OTHER LIABILITIES~~

~~Accounts~~Our long-term ~~payable,~~debt ~~accrued~~consists ~~expenses and other liabilities consist~~ of the following (In thousands):

	June 30,2013		December 31,2012
	September 30,2013		December 31,2012
Accrued expenses	$	9,232	$	9,608
CMM Credit Facility, due March 2017	$	191,900	$	127,000
Accrued property taxes		4,713		5,638
CMLP Credit Facility, due November 2017		356,200		206,700
Accrued product purchases payable		2,014		2,450
Senior Notes, due April 2019		350,000		350,000
Tax payable		1,297		2,159
		898,100		683,700
Interest payable		7,791		7,505
Plus: Unamortized premium on Senior Notes		1,286		1,461
Accounts payable		8,914		2,278
Total long-term debt	$	899,386	$	685,161
Other		95		79
Total accounts payable, accrued expenses and other liabilities	$	34,056	$	29,717

7.Credit ~~COMMITMENTS~~Facilities ~~AND CONTINGENT LIABILITIES~~

~~Legal~~CMM ~~Proceedings~~Credit Facility. In conjunction with the Merger discussed in Note 1. Organization and Description of Business, we terminated the CMM credit agreement (CMM Credit Facility). No amounts were outstanding under the CMM Credit Facility following the consummation of the Merger. The CMM credit agreement allowed for revolving loans, letters of credit and swingline loans in an aggregate principal amount of up to $200 million. The CMM Credit Facility was secured by substantially all of CMM’s assets.

~~Class~~Borrowings ~~Action~~under ~~Lawsuits. Five putative class action lawsuits challenging~~ the ~~Crestwood-Inergy~~CMM ~~merger~~Credit ~~have~~Facility ~~been~~bore ~~filed,~~interest ~~four~~at ~~in federal court in~~ the ~~United~~London ~~States~~Interbank ~~District~~Offered ~~Court~~Rate ~~for the Southern District of Texas:~~ (iLIBOR) ~~Abraham~~ ~~Knoll~~plus v.an ~~Robert~~applicable G.margin ~~Phillips,~~or etbase ~~al.~~rate ~~(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.~~as ~~Crestwood~~defined ~~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~~the ~~Chancery~~CMM ~~Court,~~Credit ~~Hawley v~~Facility. ~~Crestwood~~Under ~~Midstream Partners~~the ~~LP,~~terms ~~et al. (Case No. 8689-VCL). All~~ of the ~~cases~~CMM ~~name~~Credit ~~Crestwood~~Facility, ~~Crestwood Gas Services GP LLC, Crestwood Holdings LLC,~~ the ~~current~~applicable ~~and~~margin ~~former~~under ~~directors~~LIBOR ofwas ~~Crestwood Gas Services GP LLC, Inergy, L~~2.~~P.,~~8% ~~Inergy Midstream, L.P., NRGM GP, LLC,~~ and ~~Intrepid Merger Sub, LLC as defendants~~2. ~~All~~5% ofat ~~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.~~September ~~The lawsuits generally allege~~30, ~~among~~2013 ~~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.~~December ~~The lawsuits further allege that Inergy~~31, L2012.~~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~~weighted-average ~~seek,~~interest inrate ~~general,~~at ~~(i)~~September ~~injunctive relief enjoining the merger~~30, ~~(ii) in the event the merger is consummated, rescission or an award of rescissory damages, (iii) an award of plaintiffs’ costs,~~2013 ~~including reasonable attorneys’~~ and ~~experts’ fees, (iv)~~December ~~the accounting by the defendants to plaintiffs for all damages caused by the defendants~~31, ~~and~~2012 ~~(v) such~~was ~~further equitable relief as the court deems just and proper~~3. ~~Certain~~0% ~~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~~2. ~~as an alleged aider and abettor~~8%. ~~The~~ ~~plaintiff~~For in the ~~Hawley~~three ~~action in Delaware filed a motion for expedited proceedings but subsequently withdrew that motion~~ and ~~then~~nine ~~filed~~months aended ~~stipulation~~September 30, ~~voluntarily dismissing the action without prejudice~~2013, ~~which~~our ~~has~~average ~~been~~outstanding ~~granted~~borrowings ~~by the~~were ~~Court,~~approximately ~~such~~$157 ~~that~~million ~~the~~and ~~Hawley~~$126 ~~action has now been dismissed~~million. ~~The~~ ~~plaintiffs~~For in the ~~Knoll,~~three ~~Podell, Cooper,~~ and ~~Elliot~~nine ~~actions~~months ~~filed~~ended ~~an unopposed motion to consolidate these four cases, which the Court granted.~~September ~~The plaintiff in the Elliot~~30, ~~action filed a motion for expedited discovery~~2013, ~~which~~our ~~remains~~maximum ~~pending.~~outstanding ~~These~~borrowings ~~lawsuits~~were ~~are~~approximately at$192 ~~a preliminary stage~~million. ~~Crestwood, Inergy Midstream and the other defendants believe that these lawsuits are without merit and intend to defend against them vigorously.~~

~~From~~CMLP ~~time~~Credit toFacility. ~~time,~~In weconjunction ~~are~~with ~~party~~the toMerger discussed ~~certain legal or administrative proceedings that arise~~ in ~~the~~Note ~~ordinary~~1. ~~course~~ Organization and ~~are~~Description ~~incidental~~of toBusiness, ~~our~~we ~~business.~~terminated ~~There~~the ~~are~~CMLP ~~currently~~amended noand ~~such~~restated ~~pending~~senior ~~proceedings~~secured tocredit ~~which~~agreement we(CMLP ~~are~~Credit aFacility). ~~party~~No ~~that~~amounts ~~our~~were ~~management~~outstanding ~~believes~~under ~~will~~the ~~have~~CMLP aCredit ~~material~~Facility ~~adverse~~following ~~effect~~the consummation ~~on our results~~ of ~~operations,~~the ~~cash~~Merger. ~~flows~~The orCMLP ~~financial~~Credit ~~condition.~~Facility ~~However, future~~allowed ~~events~~for orrevolving ~~circumstances~~loans, ~~currently~~letters ~~unknown~~of tocredit ~~management,~~and ~~will~~swingline ~~determine~~loans ~~whether~~in ~~the~~an ~~resolution~~aggregate amount of ~~any~~up ~~litigation~~to or$550 ~~claims~~million. ~~will~~The ~~ultimately~~CMLP ~~have~~Credit aFacility ~~material~~was ~~effect~~secured onby ~~our~~substantially ~~results~~all of ~~operations,~~CMLP’s ~~cash~~assets ~~flows~~and those orof ~~financial~~certain ~~condition~~of inits ~~any future reporting periods~~subsidiaries. As of ~~June~~September 30, 2013, wethe ~~had~~CMLP noCredit ~~amounts~~Facility ~~accrued~~was ~~for~~guaranteed by our ~~legal~~100% ~~proceedings.~~owned Atsubsidiaries ~~December 31,~~except ~~2012,~~for weCrestwood ~~had~~Niobrara ~~less~~and ~~than~~CMM ~~$0.1~~and ~~million~~its ~~accrued~~consolidated ~~for our legal proceedings~~subsidiaries.

~~Regulatory~~Borrowings ~~Compliance~~under the CMLP Credit Facility bore 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 September 30, 2013 and December 31, 2012. The weighted-average interest rate as of September 30, 2013 and December 31, 2012 was 3.0% and 2.8%. For the three and nine months ended September 30, 2013, our average outstanding borrowings were $343 million and $330 million. For the three and nine months ended September 30, 2013, our maximum outstanding borrowings were $365 million and $373 million.

InSenior ~~the~~Notes 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~~In ~~Compliance~~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. In conjunction with the Merger discussed in Note 1. Organization and Description of Business, CMLP entered into a supplemental indenture governing the 7.75% Senior Notes. Pursuant to the supplemental indenture, Crestwood Midstream Partners LP (formerly NRGM) and Crestwood Midstream Finance Corp (formerly NRGM Finance Corp.), which we refer to together as the Successor Issuers, have unconditionally assumed all of the obligations under the 7.75% Senior Notes due April 2019. In addition, certain subsidiaries have entered into financial guarantees pursuant to which they unconditionally guarantee the obligations under the indenture and Senior Notes.

~~Our~~18 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

~~Table~~8. ofACCOUNTS ~~Contents~~PAYABLE, ACCRUED EXPENSES AND OTHER LIABILITIES

~~management~~Accounts ~~and disposal and other environmental matters. The cost of planning~~payable, 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~~expenses ~~million~~ and ~~$0.2~~other ~~million~~liabilities ~~for~~consist ~~environmental matters, which is based on our undiscounted estimate~~ of ~~amounts~~the wefollowing ~~will~~(In ~~spend~~thousands): 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


	September 30, 2013		December 31, 2012
Accrued expenses	$	11,305	$	9,608
Accrued property taxes		5,843		5,638
Accrued product purchases payable		1,818		2,450
Tax payable		1,353		2,159
Interest payable		14,054		7,505
Accounts payable		6,653		2,278
Other		9		79

Total accounts payable, accrued expenses and other liabilities	$	41,035	$	29,717

~~No provision for federal or state income taxes is included in our results of operations as such income is taxable directly to the partners~~9. ~~Accordingly,~~COMMITMENTS ~~each~~AND ~~partner~~CONTINGENT isLIABILITIES 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.

WeLegal ~~are~~Proceedings 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.

9Class Action Lawsuits. ~~EQUITY~~Five ~~PLAN~~putative class action lawsuits challenging the Merger were 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, filed May 23, 2013); (ii) Greg Podell v. Crestwood Midstream Partners, LP, et al. (Case No. 4:13-cv-01599, filed May 30, 2013); (iii) Johnny Cooper v. Crestwood Midstream Partners LP, et al. (Case No. 4:13-cv-01660, filed June 7, 2013), subsequently replaced as named plaintiff in this action by Linda Giaimo; and (iv) Steven Elliot LLC v. Robert G. Phillips, et al. (Case No. 4:13-cv-01763, filed June 17, 2013), and one in the Delaware Court of Chancery; Hawley v. Crestwood Midstream Partners LP, et al. (Case No. 8689-VCL, filed June 27, 2013). All 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 were 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 alleged, 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 alleged 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 sought, 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. The four federal actions also asserted claims of inadequate disclosure under Sections 14(a) and 20(a) of the Securities Exchange Act of 1934, and the Elliot case also named 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 was granted by the Court, such that the Hawley action was dismissed. The plaintiff in the Elliot action filed a motion for expedited discovery, which was denied by the Court. The plaintiffs in the Knoll, Podell, Cooper, and Elliot actions filed an unopposed motion to consolidate these four cases, which the Court granted and captioned the consolidated matters as In re: Crestwood Midstream Partners Unitholder Litigation, Lead Case No. 4:12-cv-01528 (the Consolidated Action). The plaintiffs entered into a Memorandum of Understanding (MOU) on September 24, 2013 to settle the Consolidated Action whereby the defendants denied liability. The settlement contemplated by the MOU is subject to a number of conditions, including notice to the class and final court approval following completion of a settlement hearing. The defendants expect the Court to approve the terms of the MOU by the end of the first quarter of 2014. The anticipated settlement of the MOU will not have a material impact to our consolidated financial statements.

~~Awards~~From oftime ~~phantom~~to time, we are party to certain legal or administrative proceedings that arise in the ordinary course and ~~restricted~~are ~~units~~incidental ~~have~~to ~~been~~our ~~granted~~business. ~~under~~There are currently no such pending proceedings to which we are a party that our ~~Fourth~~management ~~Amended~~believes ~~and~~will ~~Restated~~have ~~2007~~a ~~Equity~~material ~~Plan~~adverse ~~(2007~~effect on our results of operations, cash flows ~~Equity~~or ~~Plan)~~financial condition. ~~The~~However, ~~following~~future ~~table~~events ~~summarizes~~or ~~information~~circumstances, ~~regarding~~currently ~~phantom~~unknown ~~and~~to ~~restricted~~management, ~~unit~~will ~~activity~~determine ~~during~~whether the ~~six~~resolution ~~months~~of ~~ended~~any ~~June~~litigation or claims will ultimately have a material effect on our results of operations, cash flows or financial condition in any future reporting periods. At September 30, 2013: and December 31, 2012, we had $0.4 million and less than $0.1 million accrued for our legal proceedings.

	Payable In Cash					Payable In Units
	Units			Weighted-Average GrantDate FairValue		Units			Weighted-Average GrantDate FairValue
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

~~Under~~Regulatory ~~the~~Compliance 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.

19In 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.

~~Table~~Environmental ofCompliance ~~Contents~~

10Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. ~~TRANSACTIONS~~We ~~WITH~~are ~~RELATED~~subject ~~PARTIES~~to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At September 30, 2013 and December 31, 2012, we had accrued approximately $0.3 million and $0.2 million for environmental matters, which are 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 $0.5 million.

~~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~~INCOME ~~from~~TAXES 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 EndedJune 30,				Six Months EndedJune 30,
	2013		2012		2013		2012
Operating revenues	$	24	$	28	$	50	$	59
Operating expenses		13		5		26		10

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.

11We are responsible for our portion of the Texas Margin tax that is included in Crestwood Holdings’ consolidated Texas franchise tax return. ~~SEGMENT~~Our ~~INFORMATION~~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.

~~We conduct our operations in the midstream sector with eight operating segments, four of which are reportable segments~~11. ~~These~~ ~~operating~~EQUITY ~~segments~~PLAN 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~~In ~~reportable segments~~conjunction ~~reflect~~with the ~~primary~~Merger ~~geographic~~discussed ~~areas~~ in ~~which~~Note we1. ~~operate~~Business and ~~consist~~Description of ~~Marcellus~~Business, ~~Barnett,~~we ~~Fayetteville~~terminated our Fourth Amended and ~~Granite~~Restated ~~Wash,~~2007 ~~all~~Equity ofPlan ~~which~~(2007 ~~are~~Equity ~~located~~Plan). ~~within~~All ~~the~~of ~~United~~our ~~States.~~unvested ~~Our~~phantom ~~reportable~~and ~~segments~~restricted ~~are~~units ~~engaged~~became invested ~~the~~upon ~~gathering,~~consummation ~~processing, treating,~~of ~~compression,~~the ~~transportation~~Merger and ~~sales~~all ofunamortized ~~natural~~compensation ~~gas~~expense ~~and~~related ~~delivery~~to ofthose ~~NGLs.~~units ~~Our~~was ~~Other~~recognized ~~operating~~on ~~segment~~that ~~consists~~date. ofThe following ~~those~~table ~~operating~~summarizes ~~segments~~information orregarding ~~reporting~~phantom ~~units~~and ~~that~~restricted ~~did~~unit ~~not~~activity ~~meet~~during ~~quantitative~~the ~~reporting~~nine ~~thresholds.~~months ended September 30, 2013:

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.


	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		(3,013	)	$	27.22		(71,006	)	$	28.70
Vested—restricted units		—			—		(11,349	)	$	26.40
Granted—phantom units		—			—		161,807		$	24.33
Granted—restricted units		—			—		27,900		$	24.86
Canceled—phantom units I		(354	)	$	25.81		(7,114	)	$	27.96

Unvested—September 30, 2013		4,945		$	26.02		322,230		$	26.01

~~The~~As ~~following~~of September 30, 2013 and December 31, 2012, we had total unamortized compensation expense of ~~table~~approximately is$4 amillion ~~reconciliation~~and $3 million related to phantom and restricted units. As discussed above, the vesting period of ~~net~~our phantom and restricted units were accelerated upon consummation of the Merger. We recognized compensation expense of approximately $2.1 million and $1.5 million during the nine months ended September 30, 2013 and 2012, included in operating expenses on our consolidated statements of income. We togranted ~~EBITDA~~phantom ~~(In~~and ~~thousands):~~restricted units with a grant date fair value of approximately $5 million during the nine months ended September 30, 2013.

	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

~~Table~~Under the 2007 Equity Plan, participants who were granted restricted units could elect to have us withhold common units to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of ~~Contents~~non-vested common units. Any such common units withheld were returned to the 2007 Equity Plan on the applicable vesting dates, which corresponded to the times at which income was recognized by the employee. When we withhold these common units, we were 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 was determined based on the closing price per common unit as reported on the NYSE on such dates. During the nine months ended September 30, 2013 and 2012, we withheld 3,341 common units and 414 common units to satisfy employee tax withholding obligations.

~~The~~12. ~~following~~TRANSACTIONS ~~tables~~WITH ~~summarize~~RELATED ~~the~~PARTIES ~~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		GraniteWash		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

We enter into transactions with our affiliates within the ordinary course of business. Concurrent with the Merger described in Note 1. Organization and Description of Business, Quicksilver Resources, Inc. is no longer a related party. For a further discussion of our related party transactions during the three and nine months ended September 30, 2013, see Note 5. Investment in Unconsolidated Affiliate. For a description of our affiliated transactions, see our 2012 Annual Report on Form 10-K.

	Three Months Ended June 30, 2012
	Marcellus		Barnett		Fayetteville		GraniteWash		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

Reimbursements from our affiliates were approximately $1 million and $2 million for the three and nine months September 30, 2013, and less than $1 million for the three and nine months ended September 30, 2012. The following table shows revenues and expenses from our affiliates for the three and nine months ended September 30, 2013 and 2012 (In millions):


	Three Months Ended September 30,				Nine Months Ended September 30,
	2013		2012		2013		2012
Operating revenues	$	24	$	28	$	74	$	87
Operating expenses		13		5		39		15

~~Table~~13. ofSEGMENT ~~Contents~~INFORMATION

	Six Months Ended June 30, 2013
	Marcellus		Barnett		Fayetteville		GraniteWash		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

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.

	Six Months Ended June 30, 2012
	Marcellus		Barnett		Fayetteville		GraniteWash		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

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. In conjunction with the Merger described in Note 1, we revised our segments to reflect the new operations of the combined entities.

22For the nine months ended September 30, 2013 and 2012, one of our customers in the Barnett segment accounted for approximately 34% and 50% of our total revenues. In each of our Marcellus and Granite Wash segments, one customer accounted for approximately 21% and 10%, respectively, of our revenues for the nine months ended September 30, 2013. In addition, in our Fayetteville segment, one customer accounted for approximately 10% of our total revenues for the nine months ended September 30, 2012.

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

12. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Net income	$	6,388	$	14,381	$	20,216	$	30,984
Add:
Interest and debt expense		11,625		8,905		34,260		25,425
Income tax expense		347		306		1,024		884
Depreciation, amortization and accretion expense		14,557		11,568		49,618		35,909

EBITDA	$	32,917	$	35,160	$	105,118	$	93,202

~~The~~21 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.

	For the Three Months Ended June 30, 2013
	Issuer			Co-Issuer		GuarantorSubsidiaries			Non-GuarantorSubsidiaries			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	)

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

	For the Three Months Ended June 30, 2012
	Three Months Ended September 30, 2013
	Issuer			Co-Issuer		GuarantorSubsidiaries			Non-GuarantorSubsidiaries			Eliminations			Consolidated
	Marcellus			Barnett		Fayetteville			GraniteWash			Other			Corporate			Total
	(In thousands)
Operating revenues	$	15,914		$	8,257	$	7,799		$	12,733		$	2,288		$	—		$	46,991
Operating revenues	$	—		$	—	$	48,202		$	7,027		$	—		$	55,229
Operating revenues—related party		74			23,624		—			449			—			—			24,147
Operating expenses		179			—		33,923			5,091			—			39,193
Product purchases		—			157		249			3,872			1,017			—			5,295
Operating income (loss)		(179	)		—		14,279			1,936			—			16,036
Product purchases—related party		—			—		—			7,556			—			—			7,556
Interest and debt expense		(8,242	)		—		(44	)		(677	)		—			(8,963	)
Operations and maintenance expense		2,832			7,717		2,303			810			1,233			—			14,895
Income (loss) before income tax		(8,421	)		—		14,235			1,259			—			7,073
General and administrative expense		—			—		—			—			—			10,367			10,367
Income tax expense		—			—		275			—			—			275
Goodwill impairment		—			—		—			—			(4,053	)		—			(4,053	)
Income (loss) before earnings from consolidated subsidiaries		(8,421	)		—		13,960			1,259			—			6,798
Gain on sale of asset		—			—		—			4,392			—			—			4,392
Earnings (loss) from consolidated subsidiaries		15,219			—		—			—			(15,219	)		—
Loss from unconsolidated affiliate		—			—		—			—			(447	)		—			(447	)
Net income (loss)		6,798			—		13,960			1,259			(15,219	)		6,798
EBITDA	$	13,156		$	24,007	$	5,247		$	5,336		$	(4,462	)	$	(10,367	)	$	32,917
General partner’s interest in net income		4,154			—		—			—			—			4,154
Goodwill	$	8,618		$	—	$	76,767		$	14,211		$	—		$	—		$	99,596
Limited partner’s interest in net income (loss)	$	2,644		$	—	$	13,960		$	1,259		$	(15,219	)	$	2,644
Total assets	$	672,627		$	604,569	$	297,064		$	77,719		$	204,053		$	27,951		$	1,883,983
Capital expenditures	$	71,124		$	156	$	4,106		$	3,958		$	4,794		$	161		$	84,299
	Three Months Ended September 30, 2012
	Marcellus			Barnett		Fayetteville			GraniteWash			Other			Corporate			Total
Operating revenues	$	7,976		$	5,390	$	7,174		$	10,702		$	3,815		$	—		$	35,057
Operating revenues—related party		—			27,956		—			—			—			—			27,956
Product purchases		—			60		137			9,481			663			—			10,341
Operations and maintenance expense		815			6,963		1,855			560			749			—			10,942
General and administrative expense		—			—		—			—			—			6,570			6,570
EBITDA	$	7,161		$	26,323	$	5,182		$	661		$	2,403		$	(6,570	)	$	35,160
Goodwill	$	—		$	—	$	76,767		$	14,211		$	4,053		$	—		$	95,031
Total assets	$	396,634		$	619,768	$	304,669		$	77,611		$	83,701		$	17,097		$	1,499,480
Capital expenditures	$	4,540		$	4,719	$	1,086		$	448		$	955		$	225		$	11,973

2322

	For the Six Months Ended June 30, 2013
	Nine Months Ended September 30, 2013
	Issuer			Co-Issuer		GuarantorSubsidiaries			Non-GuarantorSubsidiaries			Eliminations			Consolidated
	Marcellus			Barnett		Fayetteville			GraniteWash			Other			Corporate			Total
	(In thousands)
Operating revenues	$	45,497		$	26,647	$	21,383		$	39,368		$	7,441		$	—		$	140,336
Operating revenues	$	—		$	—	$	113,932		$	29,583		$	—		$	143,515
Operating revenues—related party		162			72,856		—			1,299			—			—			74,317
Operating expenses		394			—		89,815			16,166			—			106,375
Product purchases		—			558		732			13,936			2,971			—			18,197
Operating income (loss)		(394	)		—		24,117			13,417			—			37,140
Product purchases—related party		—			—		—			22,191			—			—			22,191
Interest and debt expense		(20,213	)		—		(133	)		(2,289	)		—			(22,635	)
Operations and maintenance expense		7,774			21,284		6,747			2,103			2,595			—			40,503
Income (loss) before income tax		(20,607	)		—		23,984			11,128			—			14,505
General and administrative expense		—			—		—			—			—			28,536			28,536
Income tax expense		—			—		677			—			—			677
Goodwill impairment		—			—		—			—			(4,053	)		—			(4,053	)
Income (loss) before earnings from consolidated subsidiaries		(20,607	)		—		23,307			11,128			—			13,828
Gain on sale of asset		—			—		—			4,392			—			—			4,392
Earnings (loss) from consolidated subsidiaries		34,435			—		—			—			(34,435	)		—
Loss from unconsolidated affiliate		—			—		—			—			(447	)		—			(447	)
Net income (loss)		13,828			—		23,307			11,128			(34,435	)		13,828
EBITDA	$	37,885		$	77,661	$	13,904		$	6,829		$	(2,625	)	$	(28,536	)	$	105,118
General partner’s interest in net income		10,393			—		—			—			—			10,393
Goodwill	$	8,618		$	—	$	76,767		$	14,211		$	—		$	—		$	99,596
Limited partner’s interest in net income (loss)	$	3,435		$	—	$	23,307		$	11,128		$	(34,435	)	$	3,435
Total assets	$	672,627		$	604,569	$	297,064		$	77,719		$	204,053		$	27,951		$	1,883,983
Capital expenditures	$	135,845		$	8,925	$	6,818		$	6,481		$	5,954		$	573		$	164,596
	Nine Months Ended September 30, 2012
	Marcellus			Barnett		Fayetteville			GraniteWash			Other			Corporate			Total
Operating revenues	$	15,003		$	12,053	$	20,368		$	28,021		$	9,791		$	—		$	85,236
Operating revenues—related party		—			86,739		—			—			—			—			86,739
Product purchases		—			60		343			24,514			1,838			—			26,755
Operations and maintenance expense		1,328			18,438		6,399			1,619			2,269			—			30,053
General and administrative expense		—			—		—			—			—			21,965			21,965
EBITDA	$	13,675		$	80,294	$	13,626		$	1,888		$	5,684		$	(21,965	)	$	93,202
Goodwill	$	—		$	—	$	76,767		$	14,211		$	4,053		$	—		$	95,031
Total assets	$	396,634		$	619,768	$	304,669		$	77,611		$	83,701		$	17,097		$	1,499,480
Capital expenditures	$	5,378		$	10,718	$	10,040		$	2,411		$	5,140		$	659		$	34,346

	For the Six Months Ended June 30, 2012
	Issuer			Co-Issuer		GuarantorSubsidiaries			Non-GuarantorSubsidiaries			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

14. CONDENSED CONSOLIDATING FINANCIAL STATEMENTS

24In conjunction with the Merger discussed in Note 1. Organization and Description of Business, CMLP entered into a supplemental indenture governing the 7.75% Senior Notes. Pursuant to the supplemental indenture, Crestwood Midstream Partners LP (formerly NRGM) and Crestwood Midstream Finance Corp (formerly NRGM Finance Corp.), which we refer to together as the Successor Issuers, have unconditionally assumed all of the obligations under the 7.75% Senior Notes due April 2019. In addition, certain subsidiaries have entered into financial guarantees pursuant to which they unconditionally guarantee the obligations under the indenture and Senior Notes. Prior to the Merger, the CMLP Credit Facility and our Senior Notes were fully and unconditionally guaranteed, jointly and severally, by CMLP’s present and future direct and indirect 100% owned subsidiaries (the Guarantor Subsidiaries), except for Crestwood Niobrara and 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 that were related to its service as co-issuer of our Senior Notes. Accordingly, it had no ability to service obligations on our debt securities.

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

	As of June 30, 2013
	Issuer		Co-Issuer		GuarantorSubsidiaries		Non-GuarantorSubsidiaries		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


	For the Three Months Ended September 30, 2013
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Operating revenues	$	—		$	—	$	55,457		$	15,681		$	—		$	71,138
Operating expenses		245			—		46,077			6,348			—			52,670
Goodwill impairment		—			—		(4,053	)		—			—			(4,053	)
Gain on sale of asset		—			—		4,392			—			—			4,392

Operating income (loss)		(245	)		—		9,719			9,333			—			18,807
Loss from unconsolidated affiliate		—			—		—			(447	)		—			(447	)
Interest and debt expense		(10,518	)		—		42			(1,149	)		—			(11,625	)

Income (loss) before income tax		(10,763	)		—		9,761			7,737			—			6,735
Income tax expense		—			—		347			—			—			347

Income (loss) before earnings from consolidated subsidiaries		(10,763	)		—		9,414			7,737			—			6,388
Earnings (loss) from consolidated subsidiaries		17,151			—		—			—			(17,151	)		—

Net income (loss)		6,388			—		9,414			7,737			(17,151	)		6,388
Net income attributable to noncontrolling interest		—			—		—			1,923			—			1,923

Net income (loss) attributable to Crestwood Midstream Partners LP		6,388			—		9,414			5,814			(17,151	)		4,465
General partner’s interest in net income		81			—		—			—			—			81

Limited partner’s interest in net income (loss)	$	6,307		$	—	$	9,414		$	5,814		$	(17,151	)	$	4,384


	For the Three Months Ended September 30, 2012
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Operating revenues	$	—		$	—	$	55,037		$	7,976		$	—		$	63,013
Operating expenses		179			—		37,009			2,233			—			39,421

Operating income (loss)		(179	)		—		18,028			5,743			—			23,592
Interest and debt expense		(8,147	)		—		(55	)		(703	)		—			(8,905	)

Income (loss) before income tax		(8,326	)		—		17,973			5,040			—			14,687
Income tax expense		—			—		306			—			—			306

Income (loss) before earnings from consolidated subsidiaries		(8,326	)		—		17,667			5,040			—			14,381
Earnings (loss) from consolidated subsidiaries		22,707			—		—			—			(22,707	)		—

Net income (loss)		14,381			—		17,667			5,040			(22,707	)		14,381
General partner’s interest in net income		7,516			—		—			—			—			7,516

Limited partner’s interest in net income (loss)	$	6,865		$	—	$	17,667		$	5,040		$	(22,707	)	$	6,865

	As of December 31, 2012
	Issuer		Co-Issuer		GuarantorSubsidiaries		Non-GuarantorSubsidiaries		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


	For the Nine Months Ended September 30, 2013
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Operating revenues	$	—		$	—	$	169,389		$	45,264		$	—		$	214,653
Operating expenses		640			—		135,891			22,514			—			159,045
Goodwill impairment		—			—		(4,053	)		—			—			(4,053	)
Gain on sale of asset		—			—		4,392			—			—			4,392

Operating income (loss)		(640	)		—		33,837			22,750			—			55,947
Loss from unconsolidated affiliate		—			—		—			(447	)		—			(447	)
Interest and debt expense		(30,731	)		—		(91	)		(3,438	)		—			(34,260	)

Income (loss) before income tax		(31,371	)		—		33,746			18,865			—			21,240
Income tax expense		—			—		1,024			—			—			1,024

Income (loss) before earnings from consolidated subsidiaries		(31,371	)		—		32,722			18,865			—			20,216
Earnings (loss) from consolidated subsidiaries		51,587			—		—			—			(51,587	)		—

Net income (loss)		20,216			—		32,722			18,865			(51,587	)		20,216
Net income attributable to noncontrolling interest		—			—		—			1,923			—			1,923

Net income (loss) attributable to Crestwood Midstream Partners LP		20,216			—		32,722			16,942			(51,587	)		18,293
General partner’s interest in net income		10,474			—		—			—			—			10,474

Limited partner’s interest in net income (loss)	$	9,742		$	—	$	32,722		$	16,942		$	(51,587	)	$	7,819


	For the Nine Months Ended September 30, 2012
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Operating revenues	$	—		$	—	$	156,972		$	15,003		$	—		$	171,975
Operating expenses		397			—		106,961			7,324			—			114,682

Operating income (loss)		(397	)		—		50,011			7,679			—			57,293
Interest and debt expense		(23,896	)		—		(149	)		(1,380	)		—			(25,425	)

Income (loss) before income tax		(24,293	)		—		49,862			6,299			—			31,868
Income tax expense		—			—		884			—			—			884

Income (loss) before earnings from consolidated subsidiaries		(24,293	)		—		48,978			6,299			—			30,984
Earnings (loss) from consolidated subsidiaries		55,277			—		—			—			(55,277	)		—

Net income (loss)		30,984			—		48,978			6,299			(55,277	)		30,984
General partner’s interest in net income		15,038			—		—			—			—			15,038

Limited partner’s interest in net income (loss)	$	15,946		$	—	$	48,978		$	6,299		$	(55,277	)	$	15,946

	For the Six Months Ended June 30, 2013
	Issuer			Co-Issuer		GuarantorSubsidiaries			Non-GuarantorSubsidiaries			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


	As of September 30, 2013
	Issuer		Co-Issuer		Guarantor Subsidiaries		Non-Guarantor Subsidiaries		Eliminations			Consolidated
	(In thousands)
ASSETS
Current assets
Cash and cash equivalents	$	4,506	$	—	$	—	$	1,162	$	—		$	5,668
Accounts receivable		1,626		—		15,024		11,016		—			27,666
Accounts receivable—related party		399,755		1		23,783		12		(399,501	)		24,050
Insurance receivable		—		—		3,072		—		—			3,072
Prepaid expenses and other		174		—		595		22		—			791

Total current assets		406,061		1		42,474		12,212		(399,501	)		61,247
Investment in unconsolidated affiliate		—		—		—		127,651		—			127,651
Investment in consolidated affiliates		1,186,766		—		—		—		(1,186,766	)		—
Property, plant and equipment—net		3,069		—		861,728		280,075		—			1,144,872
Intangible assets—net		—		—		112,178		316,702		—			428,880
Goodwill		—		—		90,978		8,618		—			99,596
Deferred financing costs, net		16,290		—		—		4,429		—			20,719
Other assets		25		—		993		—		—			1,018

Total assets	$	1,612,211	$	1	$	1,108,351	$	749,687	$	(1,586,267	)	$	1,883,983

LIABILITIES AND PARTNERS’ CAPITAL/MEMBERS’ EQUITY
Current liabilities
Accrued additions to property, plant and equipment	$	—	$	—	$	24,786	$	16,462	$	—		$	41,248
Capital leases		389		—		2,556		—		—			2,945
Deferred revenue		—		—		—		2,426		—			2,426
Accounts payable—related party		1,887		—		401,460		671		(399,501	)		4,517
Accounts payable, accrued expenses and other liabilities		25,229		—		9,180		6,626		—			41,035

Total current liabilities		27,505		—		437,982		26,185		(399,501	)		92,171
Long-term debt		707,486		—		—		191,900		—			899,386
Long-term capital leases		679		—		573		—		—			1,252
Asset retirement obligations		—		—		13,759		874		—			14,633
Partners’/members’ equity		876,541		1		656,037		530,728		(1,186,766	)		876,541

Total liabilities and partners’ capital/members’ equity	$	1,612,211	$	1	$	1,108,351	$	749,687	$	(1,586,267	)	$	1,883,983

	For the Six Months Ended June 30, 2012
	Issuer			Co-Issuer		GuarantorSubsidiaries			Non-GuarantorSubsidiaries			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

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).


	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

~~Crestwood~~27 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.


	For the Nine Months Ended September 30, 2013
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	(18,629	)	$	—	$	102,271		$	31,506		$	(33,795	)	$	81,353

Investing activities:
Capital expenditures		(573	)		—		(52,464	)		(111,559	)		—			(164,596	)
Capital contribution to consolidated affiliate		(82,025	)		—		—			—			82,025			—
Proceeds from sale of asset		—			—		11,000			—			—			11,000
Investment in unconsolidated affiliate		—			—		—			(128,098	)		—			(128,098	)
Other		—			—		—			20			—			20
Change in advances to affiliates, net		57,413			—		—			—			(57,413	)		—

Net cash provided by (used in) investing activities		(25,185	)		—		(41,464	)		(239,637	)		24,612			(281,674	)

Financing activities:
Proceeds from credit facilities		343,500			—		—			139,900			—			483,400
Repayments of credit facilities		(194,000	)		—		—			(75,000	)		—			(269,000	)
Payments on capital leases		(321	)		—		(2,694	)		—			—			(3,015	)
Deferred financing costs paid		(85	)		—		—			—			—			(85	)
Proceeds from issuance of common units, net		118,562			—		—			—			—			118,562
Proceeds from issuance of preferred equity of subsidiary		—			—		—			96,073			—			96,073
Contributions received		—			—		—			82,025			(82,025	)		—
Distributions to General Partner for additional interest in CMM		(129,000	)		—		—			—			—			(129,000	)
Distributions paid		(90,357	)		—		—			(33,795	)		33,795			(90,357	)
Change in advances from affiliates, net		—			—		(57,413	)		—			57,413			—
Taxes paid for equity-based compensation vesting		—			—		(700	)		—			—			(700	)

Net cash provided by (used in) financing activities		48,299			—		(60,807	)		209,203			9,183			205,878

Change in cash and cash equivalents		4,485			—		—			1,072			—			5,557
Cash and cash equivalents at beginning of period		21			—		—			90			—			111

Cash and cash equivalents at end of period	$	4,506		$	—	$	—		$	1,162		$	—		$	5,668

~~Item 2.~~28 ~~Management’s Discussion and Analysis of Financial Condition and Results of Operations~~

Overview and Performance Metrics


	For the Nine Months Ended September 30, 2012
	Issuer			Co-Issuer		Guarantor Subsidiaries			Non-Guarantor Subsidiaries			Eliminations			Consolidated
	(In thousands)
Net cash provided by (used in) operating activities	$	(16,014	)	$	—	$	86,153		$	9,934		$	(2,205	)	$	77,868

Investing activities:
Acquisitions, net of cash acquired		—			—		(87,269	)		(381,718	)		—			(468,987	)
Capital expenditures		(659	)		—		(28,309	)		(5,378	)		—			(34,346	)
Acquisition of interests in CMM		(131,250	)		—		—			—			131,250			—
Capital contribution to consolidated affiliate		1,647			—		—			—			(1,647	)		—
Change in advances to affiliates, net		(31,730	)		—		—			—			31,730			—

Net cash provided by (used in) investing activities		(161,992	)		—		(115,578	)		(387,096	)		161,333			(503,333	)

Financing activities:
Proceeds from credit facilities		350,200			—		—			27,500			—			377,700
Repayments of credit facilities		(329,500	)		—		—			(8,000	)		—			(337,500	)
Payments on capital leases		(256	)		—		(1,899	)		—			—			(2,155	)
Deferred financing costs paid		(161	)		—		—			(6,328	)		—			(6,489	)
Proceeds from issuance of common units, net		217,508			—		—			—			—			217,508
Contributions received		5,930			—		—			375,000			(131,250	)		249,680
Distributions paid		(66,500	)		—		—			(11,005	)		3,852			(73,653	)
Change in advances from affiliate, net		—			—		31,730			—			(31,730	)		—
Taxes paid for equity-based compensation vesting		—			—		(406	)		—			—			(406	)

Net cash provided by (used in) financing activities		177,221			—		29,425			377,167			(159,128	)		424,685

Change in cash and cash equivalents		(785	)		—		—			5			—			(780	)
Cash and cash equivalents at beginning of period		797			—		—			—			—			797

Cash and cash equivalents at end of period	$	12		$	—	$	—		$	5		$	—		$	17

We29 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.

~~The results of our operations are significantly influenced by the volumes of natural gas gathered and processed through our systems~~15. WeSUBSEQUENT ~~gather,~~EVENTS 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~~As wediscussed doin ~~not~~Note ~~have~~1. ~~significant~~Organization ~~direct~~and ~~commodity~~Description ~~price~~of ~~exposure~~Business, ~~lower~~on ~~natural~~October 7, ~~gas~~2013, ~~prices~~CMLP ~~could~~merged ~~have~~with aand ~~potential negative impact on~~into ~~the~~NRGM ~~pace~~with ofNRGM ~~drilling~~continuing ~~in dry gas areas – such~~ as ~~areas in~~ the ~~Barnett~~surviving ~~Shale~~entity. ~~(gathered~~The byMerger ~~the~~was ~~Alliance~~accounted ~~and~~for ~~Lake~~as ~~Arlington~~a ~~Systems),~~reverse ~~the~~acquisition ~~Fayetteville~~of ~~Systems~~NRGM ~~and~~under the ~~Sabine~~purchase ~~System~~method ~~(part~~ of ~~the~~accounting ~~Haynesville/Bossier Shale). We operate five systems located~~ in ~~basins~~accordance ~~that~~with ~~include NGL rich gas shale plays: (i)~~ the ~~Cowtown~~accounting ~~System~~standards inrelated ~~the~~to ~~Barnett~~business ~~Shale;~~combinations. ~~(ii) the~~The ~~Granite~~accounting ~~Wash~~for a ~~System;~~reverse ~~(iii) the~~merger ~~Las~~results ~~Animas Systems~~ in the ~~Avalon~~legal ~~Shale;~~acquiree ~~and~~ (ivCMLP) ~~two~~ ~~systems~~being in the ~~Marcellus~~acquirer ~~segment. For~~for ~~the~~accounting ~~three~~purposes. ~~and six months ended June 30~~Therefore, ~~2013,~~CMLP ~~our~~will ~~systems~~account ~~located~~for inthe ~~NGL~~merger ~~rich~~as ~~gas~~if ~~basins~~CMLP ~~contributed~~acquired ~~approximately 72% and 71% of our total revenues and 65% and 64% of our total gathering volumes~~NRGM. AFor ~~prolonged~~additional ~~decrease~~information inrelated to the ~~commodity~~Merger, ~~price environment~~See ~~could~~Notes ~~result~~7, in9, ~~our~~11, ~~customers~~12 ~~reducing~~and ~~their production volumes which would result in a decrease in our revenues~~13.

~~Our~~The ~~management~~following ~~uses~~table arepresents ~~variety~~the ofpro ~~financial~~forma ~~and~~consolidated ~~operational~~statements ~~measures~~of tooperations ~~analyze our performance. We view these measures~~ as ~~important factors~~if ~~affecting~~the ~~our~~reverse ~~profitability~~acquisition ~~and~~had ~~unitholder~~been ~~value~~included ~~and~~in ~~therefore~~the consolidated weresults ~~review~~of ~~them~~CMLP ~~monthly~~on ~~for~~January 1, ~~consistency~~2012 ~~and~~(In tomillions, ~~identify~~except ~~trends~~per inunit ~~our~~data): ~~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:


	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2013		2012		2013		2012
Revenues	$	140	$	114	$	418	$	318

Net income (loss)	$	12	$	24	$	40	$	63

Net income (loss) per limited partner unit:
Basic	$	0.02	$	0.15	$	0.17	$	0.40

Diluted:	$	0.02	$	0.15	$	0.17	$	0.40

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

•Item ~~our~~2. ~~pursuit~~Management’s Discussion and Analysis of ~~new~~Financial ~~acquisition~~Condition ~~opportunities.~~and Results of Operations

29On 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 October 7, 2013, CMLP completed the merger (the Merger) with a subsidiary of Inergy Midstream, L.P. (NRGM) pursuant to a merger agreement dated as of May 5, 2013. Immediately following the Merger, NRGM and CMLP merged, with NRGM continuing as the surviving entity and changing its name to Crestwood Midstream Partners LP. The common units of the combined partnership are listed on the NYSE under the symbol “CMLP.” Under the merger agreement, CMLP unitholders received 1.07 units of NRGM units for each unit of CMLP they owned and as a result, there were no CMLP common or Class D units outstanding immediately following the Merger. Additionally, CMLP unitholders (other than Crestwood Holdings), received a one-time approximately $35 million cash payment at the closing of the Merger, or $1.03 per unit, $25 million of which was paid by NRGM and approximately $10 million of which was paid by Crestwood Holdings. Also in conjunction with the Merger, CMLP was delisted on the NYSE.

~~Table~~The Management’s Discussion and Analysis of ~~Contents~~Financial Condition and Results of Operations should be read keeping in mind that we became a wholly-owned subsidiary of NRGM subsequent to the periods covered hereby. Except as otherwise specifically provided, this discussion and analysis relates to the business and operations of Crestwood Midstream Partners LP, a Delaware limited partnership and its consolidated subsidiaries for the periods prior to the closing of the Merger.

~~Operations~~Overview and ~~Maintenance~~Performance ~~Expenses~~Metrics — 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~~a ~~accepted~~growth-oriented ~~financial~~midstream ~~indicators~~master oflimited ~~a company’s~~partnership ~~operational~~which ~~performance~~owns and ~~its~~operates ~~ability~~predominately tofee-based ~~incur~~gathering, ~~and service debt~~processing, ~~fund capital expenditures~~ treating and ~~make~~compression ~~distributions.~~assets ~~EBITDA~~servicing ~~and~~producers ~~Adjusted EBITDA are not measures calculated~~ in ~~accordance~~the ~~with~~Marcellus ~~accounting~~Shale ~~principles generally accepted~~ in ~~the~~ ~~United~~northern ~~States~~West ~~of America (GAAP)~~Virginia, asthe ~~they~~Barnett doShale ~~not~~in ~~include~~north ~~deductions for items such as depreciation~~Texas, ~~amortization~~the ~~and~~Fayetteville ~~accretion,~~Shale ~~interest~~in ~~and~~northwestern ~~income taxes~~Arkansas, ~~which~~the ~~are~~Granite ~~necessary~~Wash toin ~~maintain~~the ~~our~~Texas ~~business. In addition~~Panhandle, ~~Adjusted EBITDA considers~~ the ~~impact~~ ofAvalon ~~certain~~Shale/Bone ~~significant~~Spring ~~items,~~in southeastern ~~such~~New asMexico ~~third party costs incurred related to potential~~ and ~~completed~~the ~~acquisitions~~Haynesville/Bossier ~~and~~Shale ~~other transactions identified~~ in awestern ~~specific reporting period~~Louisiana. ~~EBITDA~~We ~~and~~provide ~~Adjusted~~midstream ~~EBITDA~~services ~~should not be considered an alternative~~ to ~~net~~oil ~~income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA~~ and ~~Adjusted~~gas ~~EBITDA~~producers ~~calculations~~that ~~may~~focus ~~vary~~on ~~among~~developing ~~entities,~~unconventional soresources ~~our~~across ~~computation~~the ~~may~~United ~~not be comparable to measures used by other companies~~States.

~~See~~We conduct all of our ~~reconciliation~~operations in the midstream sector in eight operating segments, four of ~~Net~~which ~~Income~~are toreportable. ~~EBITDA~~Our operating segments reflect how we manage our operations and ~~Adjusted~~are ~~EBITDA~~generally reflective of the geographic areas in ~~Results~~which we operate. Our reportable segments consist of ~~Operations~~Marcellus, Barnett, Fayetteville and Granite Wash. Our operating segments are engaged in gathering, ~~below~~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.

~~Current~~The ~~Year~~results ~~Highlights~~of our operations are significantly influenced by the volumes of natural gas gathered and processed through our systems. We gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and percent-of-proceeds contracts. Under our fixed-fee contracts, we do not take title to the natural gas or associated NGLs. For the nine months ended September 30, 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 nine months ended September 30, 2013, the net revenues from percent-of-proceeds contracts accounted for approximately 2% of our gross margin.

~~Below~~Although iswe do not have significant direct commodity price exposure, lower natural gas prices could have a ~~discussion~~potential negative impact on the pace of ~~events~~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 or have an interest in six systems located in basins that ~~highlight~~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; (iv) two systems in the Marcellus segment; and (v) the Jackalope Gas Gathering Services, L.L.C. (Jackalope) system (our ~~core~~unconsolidated ~~business~~affiliate). For both the three and ~~financing~~nine ~~activities~~months ended September 30, 2013, our systems located in NGL rich gas basins contributed approximately 71% of our total revenues and 65% 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.

~~Operational~~Our management uses a variety of financial and ~~Industry~~operational ~~Highlights~~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.

~~Shale~~31 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.

~~Our~~Volumes ~~systems~~— ~~gathered~~We ~~993~~must ~~MMcf/d~~continually ~~and~~obtain ~~984~~new ~~MMcf/d~~supplies ~~during~~of ~~the~~natural ~~three~~gas ~~and~~to ~~six~~maintain ~~months~~or ~~ended June 30, 2013, which is an~~ increase ofthroughput ~~21%~~volumes ~~and~~on ~~37% from the same periods in 2012. During the three and six months ended June 30, 2013,~~ our ~~Marcellus~~gathering ~~systems’ compression volumes were 284 MMcf/d~~ and ~~277~~processing ~~MMcf/d~~systems. ~~Additionally,~~We ~~our processed~~routinely ~~volumes~~monitor ~~were~~producer ~~217~~activity ~~MMcf/d~~in ~~and 221 MMcf/d for~~ the ~~three~~areas ~~and~~we ~~six~~serve ~~months ended June 30, 2013, an increase of 51% compared~~ to ~~the~~identify ~~same~~new ~~periods~~supply ~~in 2012, respectively~~opportunities. ~~The~~Our ~~increase~~ability ~~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~~achieve ~~same~~these ~~periods~~objectives inis ~~2012.~~impacted by:

~~Distribution Growth~~• ~~— For~~ the ~~three~~level ~~months ended June 30, 2013, we declared a distribution~~ of ~~$0.51~~successful ~~per~~drilling ~~limited~~and ~~partner~~production ~~unit~~activity ~~compared~~in toareas ~~$0.50~~where ~~per~~our ~~limited~~systems ~~partner~~are ~~unit during the same period in 2012.~~ located;

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

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~~pursuit ~~year right~~ of ~~first~~new ~~offer~~acquisition 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 2013opportunities.

30Operations 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.

~~Table~~EBITDA and Adjusted EBITDA — We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of ~~Contents~~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. Adjusted EBITDA also considers the adjusted earnings impact of our unconsolidated affiliate by adjusting our equity earnings or losses from our unconsolidated affiliate for our proportionate share of its depreciation and interest. 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.

~~The~~See ~~West~~our ~~Union~~reconciliation ~~compressor station to be constructed under the Compression Services Agreement will be a two phase project adding approximately 120 MMcf/d~~ of ~~flow~~Net ~~capacity~~Income ~~at an estimated cost of $35 million. Phase I will add 55 MMcf/d of capacity and is expected~~ to beEBITDA ~~in service during the third quarter of 2013. Phase II will add 65 MMcf/d~~ and isAdjusted ~~expected~~EBITDA ~~to be~~ in ~~service~~Results ~~by the end~~ of ~~2013.~~Operations ~~The Victoria compressor station to be constructed will add approximately 120 MMcf/d of flow capacity at an estimated cost of $41 million~~below. 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.

InCurrent ~~December~~Year ~~2012,~~Highlights 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~~Below ~~Exploration~~is ~~and~~a discussion ~~Production~~of ~~(RKI)~~events ~~Agreement~~that highlight our core business and financing activities.

OnOperational 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~~Industry ~~agreements~~Highlights 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~~Shale ~~Activities~~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.

~~Equity~~Growth ~~Offering~~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.

OnOur ~~March 22,~~systems ~~2013,~~gathered we993 ~~completed~~MMcf/d aand ~~public~~987 ~~offering~~MMcf/d ~~of 4,500,000~~during ~~common~~the ~~units,~~three ~~representing~~and ~~limited~~nine ~~partner~~months ~~interests~~ended inSeptember 30, us2013, atwhich ais ~~price~~an increase of ~~$23.90~~11% ~~per~~and 27% ~~common~~from ~~unit~~the ~~($23.00~~same ~~per~~periods ~~common~~in ~~unit,~~2012. ~~net~~This ofincrease ~~underwriting~~was ~~discounts)~~largely ~~providing~~due ~~net~~to ~~proceeds~~a of47% ~~approximately~~increase ~~$103.5~~in ~~million.~~our WeMarcellus ~~granted~~segment ~~the~~volumes, ~~underwriters~~partially ~~a 30~~offset ~~day~~by ~~option~~a to4% ~~purchase~~decrease upin toour ~~675,000~~Barnett ~~additional~~segment ~~common~~volumes ~~units~~during if the ~~underwriters~~three ~~sold~~months ~~more~~ended ~~than 4~~September 30,~~500,000~~ ~~common~~2013 ~~units~~compared in to the ~~offering~~same period in 2012. ~~The~~During ~~underwriters~~the ~~exercised~~three ~~this~~and ~~option~~nine onmonths ~~April~~ended September 530, 2013, ~~providing~~our ~~net~~Marcellus ~~proceeds~~systems’ ofcompression ~~approximately~~volumes ~~$15.5 million.~~were ~~The~~267 ~~net~~MMcf/d ~~proceeds~~and ~~from~~274 ~~these~~MMcf/d. ~~transactions~~Additionally, ~~were~~our ~~used~~processed tovolumes ~~reduce~~were ~~indebtedness~~202 ~~under~~MMcf/d ~~each~~and of214 ~~the~~MMcf/d ~~CMM~~for the three and ~~CMLP~~nine ~~Credit~~months ~~Facilities.~~ended InSeptember 30, ~~connection~~2013, ~~with~~an ~~the~~increase ~~issuance~~ of ~~the~~12% ~~common~~and ~~units,~~36% ~~our~~compared ~~General~~to ~~Partner~~the ~~did~~same ~~not~~periods ~~make~~in an2012, ~~additional~~respectively. ~~capital contribution~~The toincrease usin ~~resulting~~volumes resulted in a ~~reduction~~13% and 25% increase in ~~their~~our ~~general~~overall ~~partner~~revenues ~~interest~~for inthe usthree and nine months ended September 30, 2013 compared to ~~approximately~~the 1same periods in 2012.~~8%.~~

~~Unit~~32 ~~Issuances~~

~~Preferred~~Marcellus ~~Interest~~Segment ~~Issuance~~Update

In ~~July~~March 2013, Crestwood ~~Niobrara~~Marcellus ~~acquired~~Midstream aLLC ~~50%~~(CMM) ~~interest~~entered ininto a ~~joint~~seven ~~venture~~year ~~which~~agreement ~~was~~with ~~funded~~Antero ~~through~~Resources ~~our~~Appalachian ~~contribution~~Corporation (Antero) ofto ~~approximately~~provide ~~$27 million~~natural ~~(which~~gas ~~was~~compression ~~borrowed~~services ~~under~~on ~~the~~developing ~~CMLP~~rich ~~Credit~~gas ~~Facility~~acreage in Doddridge County, West Virginia (Compression Services Agreement). ~~and~~The anCompression ~~additional~~Services ~~$81~~Agreement ~~million~~provides ~~obtained~~for ~~through~~the ~~Crestwood~~construction ~~Niobrara~~and operation of compressor stations on Antero’s ~~issuance~~Western ofArea aacreage ~~preferred~~(Western ~~interest~~Area) towhich ais ~~subsidiary~~not ofdedicated ~~General~~to ~~Electric~~us ~~Capital~~under ~~Corporation~~the ~~and~~existing GEGas ~~Structured~~Gathering ~~Finance, Inc.~~and ~~(collectively,~~Compression GEAgreement ~~EFS~~(GGA). ~~Crestwood~~which ~~Niobrara~~covers ~~will~~the ~~fund~~Eastern ~~75%~~Area of ~~future~~Dedication ~~capital~~(Eastern ~~contributions~~AOD). toWe ~~the~~will ~~gathering~~provide ~~system~~fixed-fee compression ~~joint~~services ~~venture~~to ~~through~~Antero ~~additional~~under ~~preferred~~the ~~interest~~Compression ~~issuances~~Services toAgreement, GEwhich ~~EFS~~provides ~~(up~~for tominimum afees ~~maximum~~based ofon ~~$69~~the ~~million),~~capacity ~~with~~of the ~~remainder~~compressor tostations ~~be funded~~constructed ~~through~~under ~~our~~the ~~capital~~agreement. ~~contributions~~The toCompression ~~Crestwood~~Services ~~Niobrara.~~Agreement Wedoes ~~serve~~not asimpact ~~the~~our ~~managing~~seven year ~~member~~right of ~~Crestwood~~first ~~Niobrara~~offer ~~and~~to weacquire ~~have~~midstream infrastructure from Antero in the ~~ability~~Western Area and is in addition to ~~redeem~~the GEpreviously ~~EFS’s~~announced ~~preferred~~construction ~~security~~of intwo ~~either~~compressor ~~cash~~stations orwe ~~CMLP~~are ~~common~~constructing ~~units,~~in ~~subject~~the toEastern ~~certain restrictions~~AOD during 2013.

31On August 1, 2013, we placed the initial phase of the Tichenal to Trent low pressure trunkline system in service. This new pipeline system is a 12-mile, 20 inch diameter pipeline located in Harrison County, West Virginia. The system is located in the Eastern AOD under the existing GGA with Antero and has a capacity of approximately 400 MMcf/d and extends our low pressure gathering into the Greenbrier area of our AOD. The pipeline system is expected to result in approximately 80 MMcf/d to 100 MMcf/d of incremental throughput during the remainder of 2013, with gathering volumes continuing to increase as additional wells and compressor stations are connected to the system.

~~Table~~Additionally, on August 8, 2013, we completed phase I of ~~Contents~~the West Union compressor station, adding 55 MMcf/d of capacity to serve Antero’s rich gas production to Doddridge County, West Virginia. Phase II of the West Union compressor station 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. 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 second 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.

~~Results~~In December 2012, CMM completed the acquisition of ~~Operations~~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, 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.

~~Three~~Powder ~~and~~River ~~Six~~Basin/Niobrara ~~Months~~Update ~~Ended June 30, 2013 Compared with Three and Six Months Ended June 30, 2012~~

~~The~~On ~~following~~July 19, ~~table~~2013, ~~summarizes~~Crestwood Niobrara LLC (Crestwood Niobrara), our ~~results~~consolidated subsidiary, paid approximately $108 million to acquire a 50% interest in a gathering system located in the Powder River Basin of ~~operations~~the Niobrara Shale play from RKI Exploration and Production, LLC (RKI). During the three months ended September 30, 2013, we contributed an additional $20 million to our unconsolidated affiliate to fund its construction projects. During 2014, we intend to expand the gathering system from the current capacity of 60 MMcf/d to 180 MMcf/d. In ~~thousands):~~addition, the joint venture is constructing a 120 MMcf/d gas processing facility. Both of these expansions are targeted to be completed during the third quarter of 2014.

	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

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.

32This acquisition further diversifies our portfolio and positions us to participate in additional greenfield development opportunities in the liquids rich core of the Powder River Basin Niobrara Shale which currently has limited midstream infrastructure.

~~Table~~Financing ofActivities ~~Contents~~

~~EBITDA~~On inJanuary 8, ~~the~~2013, ~~table~~we ~~above~~acquired ~~includes~~Crestwood ~~operating~~Holdings’ ~~results~~65% ~~from~~membership ~~our~~interest ~~Marcellus,~~in ~~Barnett, Fayetteville~~CMM ~~and~~for ~~Granite~~approximately ~~Wash~~$258 ~~segments~~million. ~~and~~We ~~other~~funded ~~operations,~~the purchase ~~and~~price ~~general~~through ~~and~~$129 ~~administrative~~million ~~expenses.~~of ~~The~~borrowings ~~following~~under ~~table~~our ~~summarizes~~CMLP credit facility, the ~~results~~issuance of ~~our Barnett~~6,190,469 ~~Marcellus~~Class D units, ~~Fayetteville~~representing ~~and~~limited ~~Granite~~partner ~~Wash~~interests ~~segments~~in us to Crestwood Holdings, and ~~other~~the ~~operations~~issuance ~~(In~~of ~~thousands):~~133,060 general partner units to our General Partner.

	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

33On 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.

~~Table~~In July 2013, Crestwood Niobrara acquired a 50% interest in a joint venture which was funded through our contribution of ~~Contents~~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 an additional $69 million), with the remainder to be funded through our capital contributions to Crestwood Niobrara. During the three months ended September 30, 2013, GE EFS contributed an additional $15 million to Crestwood Niobrara in exchange for an equivalent number of preferred units. We serve as the managing member of Crestwood Niobrara and, subject to certain restrictions, we have the ability to redeem GE EFS’s preferred security in either cash or CMLP common units of the combined partnership.

	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

Results of Operations

	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

Three and Nine Months Ended September 30, 2013 Compared with Three and Nine Months Ended September 30, 2012

~~EBITDA~~The ~~and~~following ~~Adjusted~~table ~~EBITDA~~summarizes —our ~~EBITDA~~results ~~for the three and six months ended June 30, 2013 was approximately $34 million and $72 million, an increase~~ of ~~approximately~~operations ~~$4 million and $14 million compared to same periods in 2012.~~ (In ~~the~~thousands): 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.


	Three Months Ended September 30,					Nine Months Ended September 30,
	2013			2012		2013			2012
Operating revenues	$	71,138		$	63,013	$	214,653		$	171,975
Product purchases		12,851			10,341		40,388			26,755
Operations and maintenance expense		14,895			10,942		40,503			30,053
General and administrative expense		10,367			6,570		28,536			21,965
Depreciation, amortization and accretion expense		14,557			11,568		49,618			35,909
Goodwill impairment		(4,053	)		—		(4,053	)		—
Gain on sale of asset		4,392			—		4,392			—

Operating income		18,807			23,592		55,947			57,293
Loss from unconsolidated affiliate		(447	)		—		(447	)		—
Interest and debt expense		11,625			8,905		34,260			25,425
Income tax expense		347			306		1,024			884

Net income	$	6,388		$	14,381	$	20,216		$	30,984
Add:
Interest and debt expense		11,625			8,905		34,260			25,425
Income tax expense		347			306		1,024			884
Depreciation, amortization and accretion expense		14,557			11,568		49,618			35,909

EBITDA	$	32,917		$	35,160	$	105,118		$	93,202
Expenses associated with significant items		5,143			954		10,660			3,300
Goodwill impairment		4,053			—		4,053			—
Gain on sale of asset		(4,392	)		—		(4,392	)		—
Loss from unconsolidated affiliate		447			—		447			—
EBITDA from unconsolidated affiliate		573			—		573			—

Adjusted EBITDA	$	38,741		$	36,114	$	116,459		$	96,502

~~Marcellus:~~34

~~Revenues~~EBITDA ~~and Volumes — Revenues~~ in ~~our Marcellus segment increased by approximately $8 million and $23 million during~~ the ~~three~~table ~~and~~above ~~six~~includes ~~months~~operating ~~ended~~results ~~June 30,~~from ~~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~~Barnett, ~~however we have several projects with anticipated in-service dates~~Fayetteville ~~during the third~~ and ~~fourth~~Granite ~~quarters~~Wash ofsegments ~~2013~~and ~~that~~other ~~we believe will mitigate those capacity constraints~~operations, ~~which we anticipate will result in higher gathering volumes during the last half of 2013. For the three~~ and ~~six~~general ~~months ended June 30, 2013, we gathered 415 MMcf/d~~ and ~~396~~administrative ~~MMcf/d in our Marcellus segment compared to 257 MMcf/d for the three months ended June 30, 2012~~expenses. InThe ~~addition,~~following wetable ~~recognized~~summarizes ~~gathering revenues for~~ the ~~entire~~results ~~first half~~ of ~~2013~~our ~~versus three months during the same period in 2012. During the three and six months ended June 30~~Barnett, ~~2013~~Marcellus, weFayetteville ~~connected 15~~ and 30Granite ~~new~~Wash ~~wells~~segments inand ~~our~~other ~~Marcellus~~operations ~~segment~~(In ~~which~~thousands): ~~contributed to the increase in gathering volumes and revenues.~~


	For the Three Months Ended September 30, 2013
	Marcellus		Barnett		Fayetteville		Granite Wash		Other			Total
Gathering revenues	$	11,913	$	22,687	$	7,548	$	495	$	1,271		$	43,914
Processing revenues		—		8,968		—		1		—			8,969
Compression revenues		4,075		—		—		—		—			4,075
Product sales		—		226		251		12,686		1,017			14,180

Total operating revenues	$	15,988	$	31,881	$	7,799	$	13,182	$	2,288		$	71,138
Product purchases		—		157		249		11,428		1,017			12,851
Operations and maintenance expense		2,832		7,717		2,303		810		1,233			14,895
Goodwill impairment		—		—		—		—		(4,053	)		(4,053	)
Gain on sale of asset		—		—		—		4,392		—			4,392
Loss from unconsolidated affiliate		—		—		—		—		(447	)		(447	)

EBITDA	$	13,156	$	24,007	$	5,247	$	5,336	$	(4,462	)

Gathering volumes (in MMcf)		39,041		38,643		9,538		1,829		2,286			91,337
Processing volumes (in MMcf)		—		16,710		—		1,831		—			18,541
Compression volumes (in MMcf)		24,569		—		—		—		—			24,569

	For the Three Months Ended September 30, 2012
	Marcellus		Barnett		Fayetteville		Granite Wash		Other			Total
Gathering revenues	$	7,976	$	24,737	$	7,043	$	465	$	3,152		$	43,373
Processing revenues		—		8,540		—		29		—			8,569
Product sales		—		69		131		10,208		663			11,071

Total operating revenues	$	7,976	$	33,346	$	7,174	$	10,702	$	3,815		$	63,013
Product purchases		—		60		137		9,481		663			10,341
Operations and maintenance expense		815		6,963		1,855		560		749			10,942

EBITDA	$	7,161	$	26,323	$	5,182	$	661	$	2,403

Gathering volumes (in MMcf)		26,585		40,252		8,403		1,856		5,041			82,137
Processing volumes (in MMcf)		—		14,671		—		1,859		—			16,530

~~Table~~35 ~~of Contents~~

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.


	For the Nine Months Ended September 30, 2013
	Marcellus		Barnett		Fayetteville		Granite Wash		Other			Total
Gathering revenues	$	33,785	$	70,597	$	20,647	$	1,487	$	4,470		$	130,986
Processing revenues		—		28,136		—		4		—			28,140
Compression revenues		11,874		—		—		—		—			11,874
Product sales		—		770		736		39,176		2,971			43,653

Total operating revenues	$	45,659	$	99,503	$	21,383	$	40,667	$	7,441		$	214,653
Product purchases		—		558		732		36,127		2,971			40,388
Operations and maintenance expense		7,774		21,284		6,747		2,103		2,595			40,503
Goodwill impairment		—		—		—		—		(4,053	)		(4,053	)
Gain on sale of asset		—		—		—		4,392		—			4,392
Loss from unconsolidated affiliate		—		—		—		—		(447	)		(447	)

EBITDA	$	37,885	$	77,661	$	13,904	$	6,829	$	(2,625	)

Gathering volumes (in MMcf)		110,715		118,849		24,679		5,734		9,401			269,378
Processing volumes (in MMcf)		—		52,945		—		5,540		—			58,485
Compression volumes (in MMcf)		74,726		—		—		—		—			74,726

	For the Nine Months Ended September 30, 2012
	Marcellus		Barnett		Fayetteville		Granite Wash		Other			Total
Gathering revenues	$	15,003	$	74,568	$	20,037	$	873	$	7,952		$	118,433
Processing revenues		—		24,156		—		128		—			24,284
Product sales		—		68		331		27,020		1,839			29,258

Total operating revenues	$	15,003	$	98,792	$	20,368	$	28,021	$	9,791		$	171,975
Product purchases		—		60		343		24,514		1,838			26,755
Operations and maintenance expense		1,328		18,438		6,399		1,619		2,269			30,053

EBITDA	$	13,675	$	80,294	$	13,626	$	1,888	$	5,684

Gathering volumes (in MMcf)		50,009		117,434		23,049		4,576		17,149			212,217
Processing volumes (in MMcf)		—		38,493		—		4,566		—			43,059

~~Barnett:~~EBITDA and Adjusted EBITDA — EBITDA decreased approximately $2 million for the three months ended September 30, 2013 compared to the same period in 2012. However, we experienced an increase of approximately $12 million for the nine months ended September 30, 2013 compared to same period in 2012. In the same manner, Adjusted EBITDA for the three and nine months ended September 30, 2013 was approximately $39 million and $116 million, an increase of approximately $3 million and $20 million compared to the same periods in 2012. Adjusted EBITDA includes expenses for merger-related costs and evaluating certain investment opportunities, which were approximately $5 million and $11 million for the three and nine months ended September 30, 2013 compared to costs of approximately $1 million and $3 million for the same periods in 2012, respectively. Additionally, Adjusted EBITDA includes approximately $1 million of net earnings adjustments related to adding back our proportionate share of our unconsolidated affiliate’s depreciation and interest for the three and nine months ended September 30, 2013. Also impacting our Adjusted EBITDA during the three and nine months ended September 30, 2013 was a gain of approximately $4 million on the sale of a cryogenic plant and associated equipment and a loss on the impairment of goodwill of approximately $4 million on our Haynesville/Bossier Shale system.

~~For~~Below ~~the~~is ~~three~~a discussion ~~and~~of ~~six~~the ~~months~~factors ~~ended~~that ~~June 30,~~impacted ~~2013,~~EBITDA ~~our~~by ~~Barnett~~ segment’s ~~EBITDA~~for ~~was~~the ~~relatively~~three ~~consistent~~and ~~with~~nine ~~the~~months ~~same~~ended ~~periods in 2012~~September 30, ~~primarily~~2013 ~~due~~compared to ~~higher~~the ~~processing~~same ~~revenues~~periods ~~being~~in ~~offset by lower gathering revenues and higher operations and maintenance expenses~~2012.

~~Revenues~~Marcellus: 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~~EBITDA for ~~and Maintenance Expense — Operations and maintenance expenses in~~ our ~~Barnett~~Marcellus segment ~~increased~~was by approximately $113 million and $238 million for the three and ~~six~~nine months ended ~~June~~September 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~~On ~~the three and six months ended June~~March 3026, ~~2013~~2012, ~~operations~~CMM ~~and~~acquired ~~maintenance~~gathering ~~expenses~~assets ~~related~~from toAntero, ~~the~~which ~~West~~contributed ~~Johnson County system were~~ approximately $~~0.3~~8 million and $115 million, ~~which reflects the full synergies~~ of ~~the~~revenues ~~integration~~to ~~of the system with~~ our ~~Cowtown~~Marcellus ~~system~~segment ~~completed~~EBITDA infor ~~December~~the ~~2012.~~three Asand anine ~~result~~months ofended ~~the integration~~September 30, ~~the West Johnson County plant that was acquired in the Devon Acquisition is now available for redeployment or other uses~~2012.

~~Fayetteville:~~Revenues and Volumes — Revenues in our Marcellus segment increased by approximately $8 million and $31 million during the three and nine months ended September 30, 2013 compared to the same periods in 2012, primarily due to the increase in gathering volumes. For the three and nine months ended September 30, 2013, we gathered 424 MMcf/d and 406 MMcf/d in our Marcellus segment compared to 289 MMcf/d and 273 MMcf/d for the three and nine months ended September 30, 2012. In addition, we recognized gathering revenues for the full nine months of 2013 versus six months during the same period in 2012. During the three

~~Our~~36 ~~Fayetteville segment EBITDA was relatively flat during the three and six months ended June 30, 2013 compared to the same periods in 2012.~~

~~Operations~~ and ~~Maintenance~~nine ~~Expense~~months —ended ~~Operations~~September 30, 2013, we connected 14 and ~~maintenance~~44 ~~expenses~~new wells in our ~~Fayetteville~~Marcellus segment ~~for~~which contributed to the ~~three~~increase in gathering volumes and ~~six~~revenues. In addition, we placed several gathering and compression projects in service during the three months ended ~~June~~September 30, 2013, ~~were~~which ~~relatively~~also ~~flat~~contributed ~~compared~~ to the ~~same~~ ~~periods~~increase in ~~2012~~our gathering volumes.

~~Granite~~In ~~Wash:~~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 nine months ended September 30, 2013, our compression volumes under this agreement were 267 MMcf/d and 274 MMcf/d. In addition, we anticipate an increase in our compression revenues during the fourth quarter of 2013 and into 2014 as a result of a compressor station that was placed in service during the third quarter of 2013.

~~During~~Operations ~~the~~and ~~six~~Maintenance ~~months~~Expense ~~ended June~~— ~~30,~~Operations ~~2013,~~and ~~our~~maintenance ~~Granite~~expenses ~~Wash~~in our Marcellus segment’s ~~EBITDA~~increased ~~was~~by ~~relatively~~approximately ~~flat~~$2 ~~during~~million and $6 million for the three and ~~six~~nine months ended ~~June~~September 30, 2013 when compared to the same periods in 2012, primarily due to ~~slightly~~the ~~higher~~acquisition ~~gathering~~of ~~revenues~~the ~~offset~~Enerven byassets ~~slightly~~discussed ~~higher~~above and ~~operations~~the ~~and~~additional ~~maintenance~~assets ~~expense~~placed in service during the three months ended September 30, 2013.

~~Revenues/Margin~~Barnett: 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.

35For the three and nine months ended September 30, 2013, our Barnett segment’s EBITDA decreased by approximately $2 million and $3 million compared to the same periods in 2012, primarily due to lower gathering revenues and higher operations and maintenance expenses, partially offset by higher processing revenues.

~~Table~~Revenues and Volumes — Our gathering revenues decreased by approximately $2 million and $4 million during the three and nine months ended September 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 September 30, 2013. Partially offsetting the decline in Quicksilver volumes were three new wells we connected from other producers during the three months ended September 30, 2013 and eight new wells connected during the nine months ended September 30, 2013. Partially offsetting the decrease in gathering revenues was an increase in processing revenues of ~~Contents~~$0.4 million and $4.0 million for the three and nine months ended September 30, 2013 compared to the same periods in 2012, primarily due to the Devon Acquisition, which was completed on August 24, 2012.

Operations and Maintenance Expense — Operations and maintenance expenses in our ~~Granite~~ ~~Wash~~Barnett segment ~~were~~increased by approximately $0.1 million and $~~0.2~~3 million ~~higher~~for ~~during~~ the three and ~~six~~nine months ended ~~June~~September 30, 2013 when compared to the same periods in 2012, primarily due to the ~~increase~~operation of the West Johnson County system acquired in ~~volumes~~the ~~gathered~~Devon Acquisition during August 2012. During the three and ~~processed~~nine ~~under~~months ~~our~~ended September 30, 2013, operations and maintenance expenses related to the West Johnson County system were approximately $1 million and $2 million, which reflects the full synergies of the integration of the ~~agreement~~system with ~~Sabine~~our ~~described~~Cowtown ~~above~~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.

~~Other~~Fayetteville:

Our Fayetteville ~~other~~segment ~~operations~~EBITDA ~~include~~was ~~our~~relatively ~~assets~~flat induring the ~~Haynesville/Bossier Shale (Sabine System) and our assets in the Avalon Shale (Las Animas System). For the~~ three and ~~six~~nine months ended ~~June~~September 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~~During ~~Sabine System had 27 MMcf/d and 31 MMcf/d in gathered volumes for~~ the three and ~~six~~nine months ended ~~June~~ September 30, 2013, ~~compared~~gathering torevenues ~~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~~Fayetteville ~~Holdings,~~segment ~~LLC~~increased ~~(USI)~~by ~~which~~approximately ~~expired in June 2013~~$0.5 ~~Our~~million ~~gathering volumes from other producers on our Sabine System was lower for the three~~ and ~~six~~$0.6 ~~months~~million ~~ended June 30, 2013~~ compared to the same periods in 2012, ~~which~~primarily ~~also~~due ~~contributed~~ to ~~the~~an ~~$0.6 million~~increase ~~and $1.4 million decrease~~ in ~~revenues~~volumes ~~period~~due ~~over period. EBITDA related~~ to ~~our~~18 ~~Las~~new ~~Animas~~wells ~~System~~connected ~~remained~~during ~~relatively unchanged for~~ the ~~three~~nine ~~and six~~ months ended ~~June~~September 30, 2013~~, compared to the same periods in 2012~~.

Operations and Maintenance Expense — Operations and maintenance expenses ~~decreased~~in byour ~~approximately~~Fayetteville ~~$0.2~~segment ~~million~~for ~~during~~ the ~~six~~ ~~months~~three and nine months ended ~~June~~September 30, 2013 were relatively flat compared to the same ~~period~~periods in 2012 ~~due to decreased gathering activity on our Sabine System~~.

~~Below~~Granite isWash: ~~a discussion of items impacting our EBITDA that are not allocated to our segments.~~

~~General~~Our ~~and~~Granite ~~Administrative~~Wash ~~Expenses~~segment —EBITDA ~~During~~increased by approximately $5 million during the three and ~~six~~nine months ended ~~June~~September 30, 2013, ~~general and administrative expenses increased by approximately $2 million and $3 million when~~ compared to the same periods in 2012~~. General~~, ~~and~~primarily ~~administrative~~due ~~expenses include costs related~~ to ~~legal~~the ~~and~~gain ~~other~~of ~~consulting services to evaluate certain transaction opportunities and other non-recurring matters. We incurred~~ approximately $5 ~~million and~~ $64 million ofrecorded ~~these~~on ~~costs during~~ the ~~three~~sale ~~and~~of ~~six~~a ~~months~~cryogenic ~~ended~~plant ~~June 30,~~and ~~2013~~associated ~~compared~~equipment toand $2slightly ~~million~~higher ofgathering ~~these costs in the same periods in 2012~~revenues, ~~respectively,~~partially ~~which~~offset ~~was~~by ~~the~~slightly ~~primary~~higher ~~driver~~operations ~~for the increase in general~~ and ~~administrative~~maintenance expense ~~compared to June 30, 2012~~.

~~Items~~37 ~~not affecting EBITDA include the following:~~

~~Interest~~Revenues/Margin and ~~Debt~~Volumes ~~Expense~~ — ~~Interest~~For the nine months ended September 30, 2013, we experienced a $0.6 million increase in gathering revenues due to a gathering and ~~debt~~processing ~~expense~~agreement ~~increased~~entered ~~for~~into during the ~~three~~third quarter of 2012 with Sabine Oil and ~~six~~Gas LLC and its affiliates (Sabine), an affiliate of our General Partner. During the nine months ended ~~June~~September 30, 2013, we gathered 21 MMcf/d in the Granite Wash compared to 17 MMcf/d during the same ~~periods~~period in 2012,. ~~primarily~~Granite ~~due~~Wash’s tomargins ~~(i) higher outstanding~~earned ~~balances~~ on our ~~credit~~percent-of-proceeds ~~facilities;~~contracts ~~and~~were ~~(ii)~~ relatively flat for the ~~issuance~~three and ofnine anmonths ~~additional~~ended ~~$150~~September 30, ~~million~~2013 ofcompared ~~7.75%~~to ~~Senior~~the ~~Notes~~same periods in ~~November~~ 2012.

~~The~~Operations ~~following~~and ~~table~~Maintenance ~~provides~~Expense a— Operations ~~summary~~and ofmaintenance ~~interest~~expenses in our Granite Wash segment were approximately $0.3 million and ~~debt~~$0.5 ~~expense~~million ~~(In~~higher ~~thousands):~~during the three and nine months ended September 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.

	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

Other:

36Our other operations include our assets in the Haynesville/Bossier Shale (Sabine System) and our assets in the Avalon Shale (Las Animas System). For the three and nine months ended September 30, 2013, our other operations’ EBITDA decreased by approximately $7 million and $8 million compared to the same periods in 2012, which primarily relates to the operations of our Sabine System. During the three months ended September 30, 2013, we recorded an impairment of goodwill of approximately $4 million on our Sabine system as a result of a decrease in anticipated revenues to be generated from those operations due primarily to our inability to renew and extend a significant revenue contract that expired in mid-2013.

~~Table~~Revenues and Volumes — The Sabine System had 15 MMcf/d and 26 MMcf/d in gathered volumes for the three and nine months ended September 30, 2013 compared to 45 MMcf/d and 53 MMcf/d during the same periods in 2012. The decrease in volumes was primarily due to lower volumes transported under our gathering contract with a subsidiary of ~~Contents~~US Infrastructure Holdings, LLC which expired in June 2013. Our gathering volumes from other producers on our Sabine System was lower for the three and nine months ended September 30, 2013 compared to the same periods in 2012, which also contributed to the $2 million and $3 million decrease in revenues period over period. EBITDA related to our Las Animas System remained relatively unchanged for the three and nine months ended September 30, 2013, compared to the same periods in 2012.

~~Liquidity~~Operations and ~~Capital~~Maintenance ~~Resources~~Expense — Operations and maintenance expenses increased by approximately $0.5 million and $0.3 million during the three and nine months ended September 30, 2013 compared to the same period in 2012, primarily due to the write-off of costs associated with the construction of a lateral on our Las Animas System.

~~Our~~Investment ~~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~~Jackalope 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.

WeOn ~~regularly~~July 19, ~~review~~2013, ~~opportunities~~Crestwood ~~for~~Niobrara ~~both~~acquired ~~acquisitions~~RKI’s ~~and~~50% ~~greenfield~~interest ~~growth~~in ~~projects~~Jackalope ~~that~~for ~~will~~approximately ~~enhance~~$108 million. ~~our~~Access ~~financial~~Midstream Partners, ~~performance~~L.P. ~~Since~~(Access) weowns ~~distribute~~the ~~most~~remaining of50% ~~our~~interest ~~available~~in ~~cash~~and tooperates ~~our~~Jackalope. ~~unitholders,~~Crestwood ~~we depend~~Niobrara onwill amanage ~~combination~~the ofcommercial ~~borrowings~~operations ~~under each~~ of the ~~CMM~~Jackalope ~~and~~system. ~~CMLP~~We ~~Credit~~account ~~Facilities~~for ~~and~~our ~~debt~~investment orin ~~equity~~Jackalope ~~offerings~~under ~~to finance~~ the ~~majority~~equity method of ~~our long-term growth capital expenditures or acquisitions~~accounting.

~~Management~~For ~~continuously~~the ~~monitors~~three ~~our~~months ~~leverage~~ended ~~position~~September 30, ~~and~~2013, ~~our~~we ~~anticipated~~recorded ~~capital~~a ~~expenditures~~loss ~~relative~~from to our ~~expected~~consolidated ~~cash~~affiliate ~~flows~~of approximately $0.4 Wemillion, ~~continue~~which primarily related to ~~evaluate~~(i) our ~~funding~~proportionate ~~alternatives,~~share ~~including~~of ~~additional~~Jackalope’s ~~borrowings~~net income and (ii) the ~~issuance~~amortization of ~~debt~~the orexcess ~~equity~~of ~~securities,~~our investment balance compared to ~~secure~~Jackalope’s ~~funds~~net asassets ~~needed~~which orwas ~~refinance~~approximately ~~outstanding~~$0.6 ~~debt~~million ~~balances~~for ~~with~~the three ~~longer~~months ~~term~~ended ~~notes~~September 30, 2013.

~~Known~~For ~~Trends~~the three and ~~Uncertainties~~nine ~~Impacting~~months ~~Liquidity~~ended September 30, 2013, Jackalope gathered 60 MMcf/d through its assets. Jackalope anticipates an increase in its gathering volumes as a result of several gathering and compression construction projects. During 2014, we intend to expand the gathering system from the current capacity of 60 MMcf/d to 180 MMcf/d. In addition, the joint venture is constructing a 120 MMcf/d gas processing facility. Both of these expansions are targeted to be completed during the third quarter of 2014.

~~Our~~Below ~~financial~~is ~~condition~~a ~~and~~discussion ~~results~~ of ~~operations,~~items ~~including~~impacting our ~~liquidity~~EBITDA ~~and~~that ~~profitability,~~are ~~can~~not beallocated ~~significantly~~to ~~affected~~our bysegments. ~~the following:~~

•General ~~Concentration~~and ofAdministrative ~~Gathering~~Expenses ~~Revenues~~— ~~from~~During ~~Quicksilver: We depend on Quicksilver for a substantial percentage of our current business. For~~ the three and ~~six~~nine months ended ~~June~~ September 30, 2013, ~~services~~general toand ~~Quicksilver~~administrative expenses ~~accounted~~increased ~~for~~by approximately ~~34%~~$4 ofmillion ~~our~~and ~~total~~$7 ~~revenues~~million inwhen ~~each~~compared ~~period.~~to Inthe ~~April~~same ~~2013,~~periods ~~Quicksilver sold approximately 25% of its interest~~ in ~~its~~2012. General ~~Barnett~~and ~~Shale~~administrative ~~assets~~expenses toinclude ~~TG Barnett Resources LP, a wholly~~merger-~~owned~~related ~~U.S.~~costs ~~subsidiary~~as ofwell ~~Tokyo~~as ~~Gas~~other ~~Co.,~~costs ~~Ltd.~~related ~~Quicksilver~~to ~~will~~legal ~~remain~~and ~~the~~other ~~operator~~consulting ofservices ~~the~~to evaluate ~~assets.~~certain ~~The~~transaction ~~risk~~opportunities ofand ~~revenue~~other ~~fluctuations~~non-recurring ~~from~~matters. We ~~Quicksilver~~incurred inapproximately ~~the~~$5 ~~near~~million ~~term~~and is$11 ~~mitigated~~million ~~by the use~~ of ~~fixed-fee~~these ~~contracts~~costs ~~for~~during ~~providing~~the ~~gathering,~~three ~~processing, treating~~ and ~~compression~~nine ~~services;~~months ~~however~~ended September 30, ~~our~~2013 ~~revenues~~compared ~~may~~to be$1 ~~impacted~~million byand ~~volume~~$3 ~~fluctuations.~~million of ~~While~~these ~~our~~costs ~~acquisitions~~in ~~reduce~~ the ~~concentration~~same ofperiods ~~risk~~in ~~associated~~2012, ~~with our dependency on one producer and one geographic area~~respectively, wewhich ~~continue~~was tothe ~~regularly~~primary ~~review~~driver ~~opportunities~~ for ~~both~~the ~~acquisitions~~increase ~~and~~in ~~greenfield~~general ~~growth~~and ~~projects~~administrative inexpense ~~other~~compared ~~producing~~to ~~basins~~the ~~and~~same ~~with~~periods ~~other producers~~ in ~~the future~~2012.

•38 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.

37Items not affecting EBITDA include the following:

~~Table~~Depreciation, Amortization and Accretion Expense — We have experienced increases in our depreciation, amortization and accretion expense primarily due to assets acquired during 2012, partially offset by a decrease of ~~Contents~~approximately $3 million related to the finalization of the purchase price allocation for Devon and EMAC acquisitions. For a further discussion of our asset acquisitions during 2012, see our 2012 Annual Report on Form 10-K.

•Interest ~~Regulatory Requirements: Our operations~~ and ~~the~~Debt ~~operations~~Expense of— ~~our~~Interest ~~customers are subject to complex~~ and ~~evolving~~debt ~~federal,~~expense increased ~~state,~~for ~~local~~the ~~and~~three ~~other laws~~ and ~~regulations.~~nine Inmonths ~~April~~ended ~~2012~~September 30, ~~the~~2013 ~~United~~compared ~~States~~to ~~Environmental~~the ~~Protection~~same ~~Agency~~periods ~~issued~~in a2012, ~~final~~primarily ~~rule~~due ~~establishing~~to ~~new emission limitations for certain oil and gas facilities. These rules establish emission standards for gas wells that are hydraulically fractured~~ (~~or re-fractured~~i). higher ~~These~~outstanding ~~rules~~balances ~~also~~on ~~establish~~our ~~emissions~~credit ~~standards~~facilities; ~~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~~ (ii) the ~~extent~~issuance of ~~our~~an ~~operations and/or give rise to or accelerate the need for~~ additional ~~capital~~$150 ~~projects~~million of 7.75% InSenior ~~addition,~~Notes ~~any further changes~~ in ~~laws~~November ~~or regulations, or delays in the issuance of required permits, may further impact the volumes on our systems~~2012.

•The ~~Impact~~following oftable ~~Inflation~~provides ~~and Interest Rates: Although inflation in the United States has been relatively low in recent years, the United States economy may experience~~ a ~~significant~~summary ~~inflationary effect in the future. Although inflation would negatively impact the cost~~ of ~~our~~interest ~~operations~~ and ~~cash~~debt ~~flows~~expense 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,~~thousands): 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


	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2013			2012			2013			2012
Credit Facilities	$	4,957		$	4,875		$	13,610		$	12,981
Senior Notes		7,118			4,070			21,133			12,124
Capital lease interest		47			55			189			149
Other debt-related costs		2			—			(52	)		462

Gross interest and debt expense		12,124			9,000			34,880			25,716
Less capitalized interest		(499	)		(95	)		(620	)		(291	)

Interest and debt expense	$	11,625		$	8,905		$	34,260		$	25,425

~~The~~Liquidity ~~following~~and ~~table~~Capital ~~provides~~Resources ~~a summary of our cash flows by category (In thousands):~~

	Six Months EndedJune 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

Prior to the Merger discussed above, our sources of liquidity included 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 subsequent to the Merger will be sufficient to fund our short-term working capital requirements and capital expenditures for the remainder of 2013. We regularly review opportunities for both acquisitions and greenfield growth projects that will enhance our financial performance. Management continuously monitors 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.

~~Operating~~Known ~~Activities~~Trends and Uncertainties Impacting Liquidity

~~During~~Our ~~the~~financial ~~six~~condition ~~months~~and ~~ended~~results ~~June 30,~~of ~~2013~~operations, weincluding ~~experienced an increase in~~ our ~~operating~~liquidity ~~cash~~and ~~flows~~profitability, ~~compared~~can tobe ~~the~~significantly ~~same~~affected ~~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~~following: ~~outstanding balances on our credit facilities and Senior Notes.~~

~~Investing~~• ~~Activities~~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 operate or have an interest in six 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; (iv) two systems in the Marcellus segment; and (v) the Jackalope System (our unconsolidated affiliate). For three and nine months ended September 30, 2013, these rich gas systems accounted for approximately 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.

~~The~~• ~~midstream~~Regulatory ~~energy~~Requirements: ~~business~~Our isoperations ~~capital~~and ~~intensive~~the operations of our customers are subject to complex and evolving federal, ~~requiring~~state, ~~significant~~local ~~investments~~and ~~for~~other laws and regulations. In April 2012, the ~~acquisition~~United orStates ~~development~~Environmental ofProtection Agency issued a final rule establishing new emission limitations for certain oil and gas facilities. WeThese ~~categorize~~rules ~~our~~establish ~~capital~~emission ~~expenditures~~standards asfor ~~either:~~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

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

38other 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.

~~Table~~• Impact of ~~Contents~~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.

~~The~~Cash ~~following~~Flows 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

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

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


	Nine Months Ended September 30,
	2013			2012
Net cash provided by operating activities	$	81,353		$	77,868
Net cash used in investing activities		(281,674	)		(503,333	)
Net cash provided by financing activities		205,878			424,685

InOperating ~~July~~Activities 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~~During ~~Activities~~the nine months ended September 30, 2013, we experienced an increase in our operating revenues compared to the same period in 2012, primarily due to our asset acquisitions during 2012, partially offset by higher operations and maintenance expenses and general and administrative costs related to the acquired assets and higher general and administrative costs primarily related to the Merger discussed above. In addition, our interest costs increased during the nine months of 2013 compared to the same period in 2012 as a result of higher outstanding balances on our credit facilities and Senior Notes.

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

•The ~~Net~~midstream ~~borrowings~~energy ~~under~~business ~~our~~is ~~credit~~capital ~~facilities~~intensive, requiring significant investments for the acquisition or development of ~~approximately~~new ~~$94~~facilities. ~~million;~~We categorize ~~and~~our capital expenditures as either:

• ~~$103.5~~expansion ~~million~~capital inexpenditures, ~~proceeds~~which ~~from~~are ~~the~~made ~~issuance~~to ofconstruct 4additional assets,~~500~~ expand and upgrade existing systems,~~000~~ ~~common~~or ~~units~~acquire inadditional ~~March~~assets; ~~2013.~~or

• ~~$15.5~~maintenance ~~million~~capital inexpenditures, ~~proceeds~~which ~~from~~are made to replace partially or fully depreciated assets, to maintain the ~~issuance~~existing operating capacity of ~~675~~our assets,~~000~~ ~~common~~extend ~~units~~their inuseful ~~April~~lives ~~2013~~or comply with regulatory requirements.

~~During~~The ~~the~~following ~~six~~table ~~months~~summarizes ~~ended June 30, 2013, we paid distributions to~~ our ~~unitholders~~capital ofexpenditures ~~approximately~~for ~~$58 million, which increased by $11 million when compared to~~ the ~~same~~nine ~~period~~months inended ~~2012. On April~~September 130, 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 thousands)
Expansion capital	$	154,267
Maintenance capital		5,761
Other⁽¹⁾		4,568

Total	$	164,596

~~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~~1) ~~and~~Represents 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~~expenditures tothat ~~the~~are ~~gathering~~primarily ~~system~~reimbursable ~~joint~~from ~~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~~insurers. ~~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.~~

39In July 2013, Crestwood Niobrara paid approximately $108 million to acquire a 50% interest in a gathering system located in the Powder River Basin of the Niobrara Shale play from RKI. In addition, during the three months ended September 30, 2013, we contributed an additional $20 million to our unconsolidated affiliate to fund its construction projects.

~~Table~~40 ~~of Contents~~

~~There~~Financing ~~are~~Activities ~~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~~Significant items impacting our financing activities during the nine months ended September 4.30, ~~Controls~~2013 ~~and~~included ~~Procedures~~the following:

~~Disclosure~~• ~~Controls~~Net ~~and~~borrowings ~~Procedures~~under our credit facilities of approximately $214 million; and

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))$103.5 ~~This~~million ~~evaluation considered the various processes carried out under the direction of our disclosure committee~~ in anproceeds ~~effort~~from ~~to ensure that information required to be disclosed in~~ the ~~SEC~~issuance ~~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~~4, ~~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~~500,000 nocommon ~~matter~~units ~~how~~in ~~well~~March 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~~• $15.5 million in ~~Internal~~proceeds ~~Control~~from ~~Over~~the ~~Financial~~issuance ~~Reporting~~of 675,000 common units in April 2013.

~~There~~In ~~were no changes~~January in2013, ~~our~~we ~~internal~~acquired ~~control~~Crestwood ~~over~~Holdings’ ~~financial~~65% ~~reporting~~membership ~~(as~~interest ~~defined~~ in ~~Exchange~~CMM ~~Act~~for ~~Rules~~$258 ~~13a-15(f)~~million, ~~and~~which ~~15d-15(f))~~was ~~during~~funded ~~the~~through ~~three~~$129 ~~months~~million ~~ended~~of ~~June 30,~~borrowings ~~2013~~under ~~that~~the ~~have~~CMLP ~~materially~~Credit ~~affected,~~Facility orand ~~are~~the ~~reasonably~~issuance ~~likely~~of toapproximately ~~materially~~$129 ~~affect~~million ~~our~~of ~~internal control~~equity ~~over~~to ~~financial reporting~~Crestwood Holdings.

40In 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 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. During the three months ended September 30, 2013, GE EFS contributed an additional $15 million to Crestwood Niobrara in exchange for an equivalent number of preferred units. 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 common units, subject to certain restrictions.

~~Table~~Item of3. ~~Contents~~Quantitative and Qualitative Disclosures About Market Risk

~~PART~~There IIare —no ~~OTHER~~material ~~INFORMATION~~changes in our quantitative and qualitative disclosures about market risks from those reported in our 2012 Annual Report on Form 10-K.

Item 1 4. ~~Legal~~Controls ~~Proceedings~~and Procedures

~~See~~Disclosure ~~Part~~Controls I,and ~~Item 1.~~Procedures ~~Financial Statements, Note 7, which is incorporated herein by reference.~~

~~Item~~As of September 1A30, 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)). ~~Risk~~This ~~Factors~~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 accumulated and communicated to our management, including our Chief Executive Officer and Interim Chief Financial Officer of our General Partner, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. 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 September 30, 2013.

~~Important~~Changes ~~factors that could cause actual results to differ materially from estimates or projections contained~~ in ~~our~~Internal ~~forward-looking~~Control ~~statements~~Over ~~are~~Financial ~~described~~Reporting 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~~There towere ~~complete~~no ~~the~~changes ~~merger~~in orour ~~delays~~internal incontrol ~~completing~~over ~~the~~financial ~~merger~~reporting ~~with~~(as ~~Inergy~~defined ~~Midstream,~~in ~~L.P.~~Exchange ~~could~~Act ~~negatively~~Rules ~~impact~~13a-15(f) ~~our~~and ~~unit~~15d-15(f)) ~~price~~during the three months ended September 30, ~~future~~2013 ~~business~~that ~~and~~have ~~operation~~materially affected, ~~and~~or are reasonably likely to materially affect our internal control over financial ~~results~~reporting.

On41 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:

•PART ~~the~~II ~~pending~~— ~~merger,~~OTHER ~~its~~INFORMATION 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;

•Item ~~in specified circumstances, if the merger is not completed, we may be required to pay NRGM a termination fee of $50~~1.8 ~~million;~~Legal Proceedings

•See wePart ~~will~~I, ~~not~~Item 1. ~~realize~~Financial ~~the~~Statements, ~~benefits~~Note ~~expected~~9, ~~from~~which ~~being~~is ~~part~~incorporated ofherein aby ~~larger~~reference. ~~combined organization; and~~

•Item ~~some~~1A. ~~costs~~Risk ~~related to the merger, such as legal, accounting and financial advisor fees, must be paid even if the merger is not completed.~~Factors

~~While~~Important ~~the~~factors ~~merger~~that iscould ~~pending~~cause weactual ~~may~~results beto ~~subject~~differ tomaterially ~~restrictions~~from onestimates ~~the~~or ~~conduct~~projections ofcontained in our ~~business~~forward-looking statements are described in our 2012 Annual Report on Form 10-K under Part I, Item 1A. Risk Factors.

~~The~~Item ~~merger agreement restricts us from taking specified actions without NRGM’s approval~~2. ~~These~~Unregistered ~~restrictions~~Sales ~~could adversely affect our ability to execute certain~~ of ~~our~~Equity ~~business~~Securities 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~~Use ~~prior to the completion~~ of ~~the merger.~~ Proceeds

~~Item 2~~None. ~~Unregistered Sales of Equity Securities and Use of Proceeds~~

~~None~~Item 3. Defaults Upon Senior Securities

~~Item 3~~None. ~~Defaults Upon Senior Securities~~

~~None~~Item 4. Mine Safety Disclosures

~~Item 4~~Not Applicable. ~~Mine Safety Disclosures~~

~~Not~~Item ~~Applicable~~5. Other Information

~~Item 5~~None. ~~Other Information~~

~~None~~Item 6. Exhibits

~~Item 6.~~The ~~Exhibits~~exhibit index is incorporated herein by reference into this Quarterly Report on Form 10-Q.

~~The~~42 ~~exhibit index is incorporated herein by reference into this Quarterly Report on Form 10-Q.~~

~~Table~~SIGNATURES ~~of Contents~~

~~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.

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
	(formerly known as Inergy Midstream, L.P.)
	By: CRESTWOOD MIDSTREAM GP LLC,
	(its General Partner)

Date: November 7, 2013	By:	/s/ Michael J. Campbell
		Michael J. Campbell
		Senior Vice President and Chief Financial Officer
		(Duly Authorized Officer and Principal Financial Officer)

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if smaller reporting company)

Smaller Reporting company

~~Table~~EXHIBIT ofINDEX ~~Contents~~

~~EXHIBIT~~Exhibits ~~INDEX~~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.

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

3.1		Third Amended and Restated Partnership Agreement of Crestwood Midstream Partners LP (filed as Exhibit 3.1 to Crestwood Midstream Partners LP’s Form 8-K/A filed October 9, 2013, and included herein by reference).

3.2		Certificate of Limited Partnership of Quicksilver Gas Services LP (incorporated by reference to Exhibit 3.1 to Crestwood Midstream Partners LP’s Form S-1, File No. 33-140599, filed on February 12, 2007).

3.3		Certificate of Amendment to the Certificate of Limited Partnership of Quicksilver Gas Services LP (incorporated by reference to Exhibit 3.1 to Crestwood Midstream Partners LP’s Form 8-K, filed on October 7, 2010).

4.1		Supplemental Indenture No. 5, dated as of October 7, 2013, among Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.), Crestwood Midstream Finance Corp (f/k/a NRGM Finance Corp.), Crestwood Midstream Partners, LP, as original issuer, Crestwood Midstream Finance Corporation, as original co-issuer and The Bank of New York Mellon Trust Company, N.A. and the guarantor parties thereto (filed as Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 8-K/A filed October 8, 2013, and included herein by reference).

10.1		Amended and Restated Limited Liability Company Agreement of Crestwood Niobrara LLC, dated July 19, 2013 (filed as Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed July 22, 2013, and incorporated herein by reference).***

10.2		Registration Rights Agreement by and between Crestwood Midstream Partners LP and Aircraft Services Corporation, dated July 19, 2013 (filed as Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed July 22, 2013, and incorporated 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

ExhibitNo.		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

***	Confidential treatment has been requested for certain portions which are omitted in the copy of the exh

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