10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

ý	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 2014

OR

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the transition period from to .

COMMISSION FILE NUMBER: 001-35377

Crestwood Midstream Partners LP

(Exact name of registrant as specified in its charter)

Delaware	20-1647837
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

700 Louisiana Street, Suite 2550 Houston, Texas	77002
(Address of principal executive offices)	(Zip code)

(832) 519-2200

(Registrant’s telephone number, including area code)

Inergy Midstream, L.P.	Two Brush Creek Blvd., Suite 200 Kansas City, Missouri, 64112	September 30
(Former name)	(Former address)	(Former fiscal year)

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 website, 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 definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.

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

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

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

INDEX TO FORM 10-Q

	Page
Part I – Financial Information
Item 1 - Financial Statements of Crestwood Midstream Partners LP (Unaudited):
Consolidated Balance Sheets as of June 30, 2014 and December 31, 2013	3
Consolidated Statements of Operations for the Three and Six Months Ended June 30, 2014 and 2013	4
Consolidated Statement of Partners’ Capital for the Six Months Ended June 30, 2014	5
Consolidated Statements of Cash Flows for the Six Months Ended June 30, 2014 and 2013	6
Notes to Consolidated Financial Statements	7
Item  2 – Management’s Discussion and Analysis of Financial Condition and Results of Operations	31
Item 3 – Quantitative and Qualitative Disclosures About Market Risk	41
Item 4 – Controls and Procedures	41
Part II – Other Information
Item 1 – Legal Proceedings	42
Item 1A – Risk Factors	42
Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds	43
Item 3 – Defaults Upon Senior Securities	43
Item 4 – Mine Safety Disclosures	43
Item 5 – Other Information	43
Item 6 – Exhibits	44
Signature	46

2

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements of Crestwood Midstream Partners LP

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.) CONSOLIDATED BALANCE SHEETS (in millions, except unit information)
	June 30, 2014		December 31, 2013
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	17.3	$	2.7
Accounts receivable	290.4		205.1
Inventory	7.6		7.0
Prepaid expenses and other current assets	13.9		10.2
Total current assets	329.2		225.0
Property, plant and equipment (Note 3)	3,749.5		3,565.7
Less: accumulated depreciation and depletion	284.6		215.6
Property, plant and equipment, net	3,464.9		3,350.1
Intangible assets (Note 3)	1,034.4		1,025.1
Less: accumulated amortization	93.9		54.3
Intangible assets, net	940.5		970.8
Goodwill	1,681.4		1,682.8
Investment in unconsolidated affiliates (Note 5)	198.4		151.4
Other assets	21.2		21.7
Total assets	$	6,635.6	$	6,401.8
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	180.8	$	154.5
Accounts payable - related party (Note 11)	13.8		8.7
Accrued expenses and other liabilities	168.7		148.4
Current portion of long-term debt (Note 7)	24.9		2.9
Total current liabilities	388.2		314.5
Long-term debt, less current portion (Note 7)	1,846.3		1,867.9
Other long-term liabilities	29.4		26.3
Commitments and contingencies (Note 10)
Partners’ capital (Note 8):
Class A preferred units (11,952,191 units issued and outstanding at June 30, 2014)	294.8		—
Partners’ capital (187,925,968 and 187,243,989 limited partner units issued and outstanding at June 30, 2014 and December 31, 2013)	3,935.5		4,092.1
Total Crestwood Midstream Partners LP partners’ capital	4,230.3		4,092.1
Interest of non-controlling partners in subsidiary	141.4		101.0
Total partners’ capital	4,371.7		4,193.1
Total liabilities and partners’ capital	$	6,635.6	$	6,401.8

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

3

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.) CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, except unit and per unit data) (unaudited)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Revenues:
Gathering and processing	$	82.7		$	46.5		$	161.3		$	93.3
Storage and transportation	45.4			5.5			89.7			5.5
NGL and crude services	543.5			3.1			953.4			3.1
Related party (Note 11)	4.1			25.0			8.3			50.6
	675.7			80.1			1,212.7			152.5
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	7.8			6.2			15.5			12.9
Storage and transportation	3.8			0.4			7.0			0.4
NGL and crude services	497.7			0.9			873.9			0.9
Related party (Note 11)	9.8			7.8			20.8			14.6
	519.1			15.3			917.2			28.8
Expenses:
Operations and maintenance	32.7			13.4			60.7			26.4
General and administrative	21.3			11.0			45.4			18.8
Depreciation, amortization and accretion	54.9			20.9			105.7			38.3
	108.9			45.3			211.8			83.5
Other operating income (expense):
Gain on long-lived assets	1.1			—			1.6			—
Loss on contingent consideration (Note 10)	(6.5		)	—			(8.6		)	—
Operating income	42.3			19.5			76.7			40.2
Loss from unconsolidated affiliates, net	(1.5		)	—			(1.6		)	—
Interest and debt expense, net	(29.0		)	(12.5		)	(57.1		)	(23.9		)
Income before income taxes	11.8			7.0			18.0			16.3
Provision for income taxes	0.1			0.3			0.8			0.7
Net income	11.7			6.7			17.2			15.6
Net income attributable to non-controlling partners	(3.7		)	—			(6.8		)	—
Net income attributable to Crestwood Midstream Partners LP	8.0			6.7			10.4			15.6
Net income attributable to Class A preferred units	(1.1		)	—			(1.1		)	—
Net income attributable to partners	$	6.9		$	6.7		$	9.3		$	15.6
General partner's interest in net income	$	7.5		$	7.8		$	15.0		$	13.0
Limited partners’ interest in net income (loss)	$	(0.6	)	$	(1.1	)	$	(5.7	)	$	2.6
Net income (loss) per limited partner unit:
Basic	$	—		$	(0.01	)	$	(0.03	)	$	0.04
Diluted	$	—		$	(0.01	)	$	(0.03	)	$	0.04
Weighted-average limited partners’ units outstanding (in thousands):
Basic	187,998			75,986			187,920			70,352
Diluted	187,998			75,986			187,920			70,352

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

4

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.) CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (in millions) (unaudited)
	Crestwood Midstream Partners LP
	Class A Preferred Units		Partners			Non-Controlling Partners		Total Partners’ Capital
Balance at December 31, 2013	$	—	$	4,092.1		$	101.0	$	4,193.1
Change in invested capital from Legacy Inergy, net of debt (Note 4)	—		(5.0		)	—		(5.0		)
Distributions to general partner	—		(20.9		)	—		(20.9		)
Distributions to limited partners	—		(148.3		)	—		(148.3		)
Unit-based compensation charges	—		9.8			—		9.8
Issuance of Class A preferred units	293.7		—			—		293.7
Issuance of preferred equity of subsidiary	—		—			33.6		33.6
Taxes paid for unit-based compensation vesting	—		(1.5		)	—		(1.5		)
Net income	1.1		9.3			6.8		17.2
Balance at June 30, 2014	$	294.8	$	3,935.5		$	141.4	$	4,371.7

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

5

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.) CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) (unaudited)
	Six Months Ended
	June 30,
	2014			2013
Operating activities
Net income	$	17.2		$	15.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion	105.7			38.3
Amortization of debt-related deferred costs and premiums	3.6			2.0
Unit-based compensation charges	9.8			1.7
Gain on long-lived assets	(1.6		)	—
Loss on contingent consideration	8.6			—
Loss from unconsolidated affiliates, net	1.6			—
Deferred income taxes	0.5			—
Other	—			0.1
Changes in operating assets and liabilities, net of effects from acquisitions	(50.0		)	10.8
Net cash provided by operating activities	95.4			68.5
Investing activities
Acquisitions, net of cash acquired (Note 4)	(19.5		)	0.2
Purchases of property, plant and equipment	(164.7		)	(83.5		)
Investment in unconsolidated affiliates	(48.6		)	—
Net cash used in investing activities	(232.8		)	(83.3		)
Financing activities
Proceeds from the issuance of long-term debt	860.6			326.7
Principal payments on long-term debt	(863.2		)	(238.5		)
Payments on capital leases	(1.9		)	(2.2		)
Payments for debt related deferred costs	—			(0.1		)
Distributions to limited partners	(148.3		)	(48.4		)
Distributions to general partner	(20.9		)	(9.3		)
Distributions for additional interest in Crestwood Marcellus Midstream LLC	—			(129.0		)
Net proceeds from issuance of limited partner units	—			118.5
Net proceeds from issuance of preferred equity of subsidiary	33.6			—
Net proceeds from the issuance of Class A preferred units	293.7			—
Taxes paid for unit-based compensation vesting	(1.5		)	(0.7		)
Other	(0.1		)	—
Net cash provided by financing activities	152.0			17.0
Net change in cash	14.6			2.2
Cash at beginning of period	2.7			0.1
Cash at end of period	$	17.3		$	2.3
Supplemental schedule of non-cash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	14.7		$	25.5

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

6

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 – Business Description

Crestwood Midstream Partners LP (the Company or Crestwood) is a publicly-traded (NYSE: CMLP) Delaware limited partnership that provides midstream solutions to customers in the crude oil, natural gas liquids (NGLs) and natural gas sectors of the energy industry. We are engaged primarily in the gathering, processing, storage and transportation of natural gas and NGLs and the gathering, storage and transportation of crude oil.

As of June 30, 2014, our general partner, Crestwood Equity Partners LP (CEQP), owns our non-economic general partnership interest, approximately 4% of our common units representing limited partnership interests and 100% of our incentive distribution rights (IDRs), which entitle CEQP to receive 50% of all distributions paid to our common unit holders in excess of our initial quarterly distributions of $0.37 per common unit. CEQP is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve) and which owns approximately 11% of our common units as of June 30, 2014.

Our financial statements reflect three operating and reporting segments, including:

• Gathering and Processing: our gathering and processing (G&P) operations provide natural gas gathering, processing, treating, compression, transportation services and sales of natural gas and the delivery of NGLs to producers in unconventional shale plays and tight-gas plays in West Virginia, Wyoming, Texas, Arkansas, New Mexico and Louisiana. This segment primarily includes our rich gas gathering systems and processing plants in the Marcellus, Powder River Basin (PRB) Niobrara, Barnett, and Permian Shale plays, and our dry gas gathering systems in the Barnett, Fayetteville, and Haynesville Shale plays;

• Storage and Transportation: our storage and transportation operations provide regulated natural gas storage and transportation services to producers, utilities and other customers. This segment primarily includes our natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake) and natural gas transmission facilities (the North-South Facilities, the MARC I Pipeline and the East Pipeline) in New York and Pennsylvania; and

• NGL and Crude Services: our NGL and crude services operations provide gathering, storage and transportation services to producers, refiners, marketers and other customers in or near unconventional shale plays in North Dakota and New York. This segment primarily includes our integrated Bakken crude oil footprint in North Dakota, which consists of (i) the COLT Hub, a crude oil rail loading and storage terminal, (ii) the Arrow crude oil, natural gas and water gathering systems, and (iii) our fleet of over-the-road crude and produced water transportation assets. This segment also includes our Bath storage facility, an NGL underground storage facility in New York, and US Salt, a solution-mining and salt production company in New York.

On October 7, 2013, we changed our name from Inergy Midstream, L.P. to Crestwood Midstream Partners LP. Unless otherwise indicated, references in this report to “we,” “us,” “our,” “ours,” “our company,” the “partnership,” the “Company,” “CMLP,” “Crestwood” and similar terms refer to either Crestwood Midstream Partners LP itself or Crestwood Midstream Partners LP and its consolidated subsidiaries, as the context requires. Unless otherwise indicated, references to (i) the Crestwood Merger refers to the October 7, 2013 merger of the Company’s wholly-owned subsidiary with and into Legacy Crestwood, with Legacy Inergy continuing as the surviving legal entity; (ii) Legacy Crestwood refers to either Crestwood Midstream Partners LP itself or Crestwood Midstream Partners LP and its consolidated subsidiaries prior to the Crestwood Merger; and (iii) Legacy Inergy refers to either Inergy Midstream, L.P. itself or Inergy Midstream, L.P. and its consolidated subsidiaries prior to the Crestwood Merger. See Note 4 for additional information on the Crestwood Merger.

7

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 2 – Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements were originally the financial statements of Legacy Crestwood, prior to the Crestwood Merger and the merger of Legacy Crestwood with and into Legacy Inergy on October 7, 2013 as discussed above. Crestwood Holdings acquisition of control of CEQP’s general partner on June 19, 2013 was accounted for as a reverse acquisition under the purchase method of accounting in accordance with accounting standards for business combinations.  CEQP’s accounting for this reverse acquisition resulted in the legal acquiree (Crestwood Gas Services GP LLC) being the acquirer for accounting purposes.  CEQP’s accounting acquiree (inclusive of Legacy Inergy) was subject to the purchase method of accounting and its balance sheet was adjusted to fair market value as of June 19, 2013.  Accordingly, the merger of Legacy Crestwood and Legacy Inergy on October 7, 2013 was accounted for as a reverse merger amongst entities under common control.  Although Legacy Crestwood was the surviving entity for accounting purposes, Legacy Inergy was the surviving entity for legal purposes, and consequently we changed our name from Inergy Midstream, L.P. to Crestwood Midstream Partners LP. As the reverse merger was amongst entities under common control, the financial statements have been recasted to reflect the operations of Legacy Inergy as being acquired by Legacy Crestwood on June 19, 2013, the date in which Legacy Inergy and Legacy Crestwood came under common control.  

The financial information as of June 30, 2014, and for the three-month and six-month periods endedJune 30, 2014 and 2013, is unaudited. The consolidated balance sheet as of December 31, 2013, was derived from the audited balance sheet filed in our 2013 Annual Report on Form 10-K. Our consolidated financial statements are prepared in accordance with US GAAP and include the accounts of all consolidated subsidiaries after the elimination of all intercompany accounts and transactions. In management’s opinion, all necessary adjustments to fairly present our results of operations, financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and recurring nature. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

Beginning in the first quarter of 2014, we began reflecting our operating and administrative expenses as operations and maintenance expenses and general and administrative expenses. In addition, we also reclassified our consolidated statements of operations for the three and six months endedJune 30, 2013 to reflect this change. This change had no impact on our previously reported net income, earnings per unit or partners' capital. The financial statements in our 2013 Annual Report on Form 10-K have not been recast to reflect this change. The following table summarizes the reclassification of the amounts previously reported in operating and administrative expenses for the periods presented (in millions):

	Year Ended December 31,
	2013		2012		2011
Operating and administrative expenses as previously reported	$	154.0	$	72.7	$	60.4
Operations and maintenance expenses	73.3		43.1		36.3
General and administrative expenses	80.7		29.6		24.1

In addition to the reclassification described above, our consolidated financial statements for prior periods include reclassifications that were made to conform to the current period presentation. None of our reclassifications had an impact on our previously reported net income, earnings per unit or partners' capital.

The accompanying consolidated financial statements should be read in conjunction with our 2013 Annual Report on Form 10-K filed with the Securities and Exchange Commission (SEC) on February 28, 2014.

8

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Significant Accounting Policies

There were no material changes in our significant accounting policies from those described in our 2013 Annual Report on Form 10-K and no significant accounting pronouncements issued but not yet adopted as of June 30, 2014.

New Accounting Pronouncement Issued But Not Yet Adopted

As of June 30, 2014, the following accounting standard has not yet been adopted by us.

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. We will adopt the provisions of this standard effective January 1, 2017 and present the retroactive application of this standard to our revenue for the quarterly and annual periods ended 2015 and 2016.  We are currently evaluating the impact that this standard will have on our financial statements.

Note 3 – Certain Balance Sheet Information

Property, Plant and Equipment

Property, plant and equipment consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Gathering systems and pipelines	1,250.2		1,231.1
Facilities and equipment	1,361.9		1,041.0
Buildings, land, rights-of-way, storage contracts and easements	780.2		766.2
Vehicles	13.7		4.1
Construction in process	180.9		360.5
Base gas	36.9		36.3
Salt deposits	120.5		120.5
Office furniture and fixtures	5.2		6.0
	3,749.5		3,565.7
Less: accumulated depreciation and depletion	284.6		215.6
Total property, plant and equipment, net	$	3,464.9	$	3,350.1

Capital Leases. We have a treating facility and certain auto leases which are accounted for as capital leases. Our treating facility lease is reflected in facilities and equipment in the above table. We had capital lease assets of $3.4 million and $5.0 million included in property, plant and equipment, net at June 30, 2014 and December 31, 2013.

9

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Intangible Assets

Intangible assets consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Customer accounts	$	483.2	$	476.4
Covenants not to compete	5.5		3.0
Gas gathering, compression and processing contracts	451.4		451.4
Acquired storage contracts	29.0		29.0
Trademarks	11.0		11.0
Deferred financing and other costs	54.3		54.3
	1,034.4		1,025.1
Less: accumulated amortization	93.9		54.3
Total intangible assets, net	$	940.5	$	970.8

Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Accrued expenses	$	23.3	$	20.0
Accrued property taxes	5.5		7.6
Accrued product purchases payable	0.2		1.6
Tax payable	1.2		10.6
Interest payable	21.7		14.9
Accrued additions to property, plant and equipment	68.7		58.1
Commitments and contingent liabilities (Note 10)	40.0		31.4
Capital leases	1.6		2.6
Deferred revenue	6.5		1.6
Total accrued expenses and other liabilities	$	168.7	$	148.4

Note 4 – Acquisitions

2014 Acquisitions

Crude Transportation Acquisitions (Bakken)

Red Rock. On March 21, 2014, we purchased substantially all of the operating assets of Red Rock Transportation Inc. (Red Rock) for approximately $13.8 million, comprised of $12.1 million paid at closing plus deferred payments of $1.7 million. Red Rock is a trucking operation located in Watford City, North Dakota which provides crude oil and produced water hauling services to the oilfields of western North Dakota and eastern Montana. The acquired assets include a fleet of approximately 56 trailer tanks, 22 double bottom body tanks and 44 tractors with 28,000 barrels per day of transportation capacity. In the first quarter of 2014, we finalized the purchase price and allocated approximately $10.6 million of the purchase price to property, plant and equipment and intangible assets and approximately $3.2 million to goodwill. Goodwill recognized relates primarily to anticipated operating synergies between the assets acquired and our existing assets. These assets are included in our NGL and crude services segment.

10

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

LT Enterprises. On May 9, 2014, we purchased substantially all of the operating assets of LT Enterprises, Inc. (LT Enterprises) for approximately $10.7 million, comprised of $9.0 million paid at closing plus deferred payments of $1.7 million. LT Enterprises is a trucking operation located in Watford City, North Dakota which provides crude oil and produced water hauling services primarily to the oilfields of western North Dakota. The acquired assets include a fleet of approximately 38 tractors, 51 crude trailers and 17 service vehicles with 20,000 barrels per day of transportation capacity. In addition, we acquired employee housing and 20 acres of greenfield real property located two miles south of Watford City. In the second quarter of 2014, we finalized the purchase price and allocated all of the purchase price to property, plant and equipment and intangible assets. These assets are included in our NGL and crude services segment.

The acquisitions of Red Rock and LT Enterprises were not material to our NGL and crude services segment's results of operations for the three and six months endedJune 30, 2014. In addition, transaction costs related to these acquisitions were not material for the three and six months ended June 30, 2014.

2013 Acquisitions

Crestwood Merger

As described in Note 2, the merger of Legacy Crestwood with and into Legacy Inergy was accounted for as a reverse merger amongst entities under common control. This accounting treatment requires the accounting acquiree (Legacy Inergy) to have its assets and liabilities stated at fair value as well as any other purchase accounting adjustments as of June 19, 2013, the date in which Legacy Crestwood and Legacy Inergy came under common control. The fair value of Legacy Inergy was calculated based on the consolidated enterprise fair value of Legacy Inergy as of June 19, 2013. This consolidated enterprise fair value considered the discounted future cash flows of Legacy Inergy's operations and Legacy Inergy's NYSE-listed stock price, the value of its outstanding senior notes based on quoted market prices for same or similar issuances and the value of its outstanding floating rate debt.

In June 2014, we finalized the Legacy Inergy purchase price allocation. Changes from our preliminary estimates as of December 31, 2013 were not material to our net assets at June 30, 2014. The following table summarizes the final valuation of the assets acquired and liabilities assumed at the merger date (in millions):

Current assets	$	49.1
Property, plant and equipment	1,677.8
Intangible assets	196.0
Other assets	2.9
Total identifiable assets acquired	1,925.8
Current liabilities	30.9
Long-term debt	745.0
Other long-term liabilities	5.3
Total liabilities assumed	781.2
Net identifiable assets acquired	1,144.6
Goodwill	1,532.7
Net assets acquired	$	2,677.3

Of the $1,532.7 million of goodwill, $806.4 million is reflected in our NGL and crude services segment and $726.3 million is reflected in our storage and transportation segment. Goodwill recognized relates primarily to synergies and new expansion opportunities expected to result from the combination of Legacy Inergy and Legacy Crestwood.  During the period from June 19, 2013 to June 30, 2013, we recognized $9.0 million of revenues and $1.8 million of net income related to this reverse merger.

11

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Arrow Acquisition

On November 8, 2013, we acquired Arrow Midstream Holdings, LLC (Arrow) for approximately $750 million, subject to customary capital expenditures and working capital adjustments of approximately $11.3 million, representations, warranties and indemnifications.  The acquisition was consummated by merging one of our wholly-owned subsidiaries with and into Arrow (the Arrow Acquisition), with Arrow continuing as the surviving entity and our wholly-owned subsidiary. The base merger consideration consisted of $550 million in cash and 8,826,125 common units issued to the sellers, subject to adjustment for standard working capital provisions.

In June 2014, we finalized the Arrow Acquisition purchase price allocation. Changes from our preliminary estimates as of December 31, 2013 were not material to our net assets at June 30, 2014. The following table summarizes the final valuation of the assets acquired and liabilities assumed at the acquisition date (in millions):

Current assets	$	192.7
Property, plant and equipment	400.5
Intangible assets	323.4
Other assets	19.5
Total identifiable assets acquired	936.1
Current liabilities	215.8
Assets retirement obligations	1.2
Other long-term liabilities	3.7
Total liabilities assumed	220.7
Net identifiable assets acquired	715.4
Goodwill	45.9
Net assets acquired	$	761.3

The $45.9 million of goodwill is reflected in our NGL and crude services segment. Goodwill recognized relates primarily to anticipated operating synergies between the assets acquired and our existing assets. During the six months endedJune 30, 2014, we also recognized approximately $5.2 million of transaction-related fees primarily related to services provided in 2013 related to this acquisition.

Unaudited Pro Forma Financial Information

The following table represents the pro forma consolidated statement of operations as if the Legacy Inergy reverse merger and the Arrow Acquisition had been included in our consolidated results for the full three and six months endedJune 30, 2013 (in millions, except per unit information):

	Three Months Ended			Six Months Ended
	June 30, 2013			June 30, 2013
Revenues	$	500.9		$	925.6
Net income	$	4.5		$	17.6
Net income per limited partner unit(a):
Basic	$	(0.02	)	$	0.03
Diluted	$	(0.02	)	$	0.03

(a) Basic and diluted net income per limited partner unit for the three and six months endedJune 30, 2013 were computed based on the number of Legacy Inergy common units outstanding plus the number of common units issued by Legacy Inergy to Legacy Crestwood unitholders as part of the Crestwood Merger and the number of units issued in conjunction with the Arrow Acquisition.

12

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

These amounts have been calculated after applying our accounting policies and adjusting the results of the acquisitions to reflect the depreciation and amortization based on the estimated fair value adjustments to property, plant and equipment and intangible assets.

Note 5 - Investments in Unconsolidated Affiliates

Jackalope Gas Gathering Services, L.L.C.

Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, owns a 50% ownership interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) which we account for under the equity method of accounting. During the six months endedJune 30, 2014, Crestwood Niobrara contributed $45.8 million to Jackalope to fund its construction projects.

Our investment in Jackalope was $172.7 million and $127.2 million at June 30, 2014 and December 31, 2013. We have reflected the earnings from our investment in Jackalope in our consolidated statements of income, which includes our share of net earnings based on our ownership interest and other adjustments recorded by us as discussed below. During the three and six months endedJune 30, 2014, our share of Jackalope’s net earnings was approximately $0.1 million and $1.2 million. As of June 30, 2014, our investment balance in Jackalope exceeded our equity in the underlying net assets of Jackalope by approximately $55.3 million. We amortize and generally assess the recoverability of this amount based on the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake) and RKI Exploration and Production, LLC (RKI). The amortization is reflected as a reduction of our earnings from unconsolidated affiliates, and during the three and six months endedJune 30, 2014, we recorded amortization expense of approximately $0.7 million and $1.5 million.

Jackalope is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the six months endedJune 30, 2014, Jackalope did not make any distributions to its members.

Our Jackalope investment is included in our gathering and processing segment.

Powder River Basin Industrial Complex, LLC

Crestwood Crude Logistics LLC (Crude Logistics), our consolidated subsidiary, owns a 50% ownership interest in Powder River Basin Industrial Complex, LLC (PRBIC) which we account for under the equity method of accounting. During the six months endedJune 30, 2014, Crude Logistics invested approximately $2.8 million in PRBIC to fund its construction projects.

Our investment in PRBIC was $25.7 million and $24.2 million at June 30, 2014 and December 31, 2013. During the three and six months endedJune 30, 2014, our share of PRBIC’s loss was approximately $0.9 million and $1.3 million. As of June 30, 2014, our investment balance in PRBIC approximated our equity in the underlying net assets of PRBIC.

PRBIC is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the six months endedJune 30, 2014, PRBIC did not make any distributions to its members.

Our PRBIC investment is included in our NGL and crude services segment.

Note 6 - Earnings Per Limited Partner Unit

Prior to the Crestwood Merger, net income attributable to Legacy Crestwood was allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after giving effect to incentive distributions earned by the general partner. To the extent cash distributions exceeded net income attributable to Legacy Crestwood, the excess distributions were allocated proportionately to all participating units outstanding based on their respective ownership percentages. As a result of the Crestwood Merger, CEQP, which owns our general partner, owns a non-economic general partner interest in us and 100% of our IDRs. We allocate net income attributable to CMLP to our limited partners after giving effect to the IDRs earned by CEQP and net income attributable to the Class A preferred units.

Basic earnings per unit are calculated using the two-class method. 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

13

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

issuance of limited partner units as discussed below. The weighted average number of units outstanding is calculated based on the presumption that the number of common units issued by Legacy Inergy to Legacy Crestwood unitholders as part of the Crestwood Merger were outstanding for the entire period prior to Crestwood Merger.

The tables below show the (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 six months endedJune 30, 2014 and 2013 (in millions):

Allocation of Net Income Attributable to CMLP to General Partner and Limited Partners
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Net income attributable to CMLP	$	8.0		$	6.7		$	10.4		$	15.6
Class A preferred units interest in net income attributable to CMLP	(1.1		)	—			(1.1		)	—
General partner’s incentive distributions	(7.5		)	(7.7		)	(15.0		)	(12.7		)
General partner’s interest in net income attributable to CMLP	—			(0.1		)	—			(0.3		)
Limited partners’ interest in net income (loss) attributable to CMLP	$	(0.6	)	$	(1.1	)	$	(5.7	)	$	2.6

Earnings Per Limited Partner Unit
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Limited partners’ interest in net income (loss)	$	(0.6	)	$	(1.1	)	$	(5.7	)	$	2.6
Weighted-average limited partner units - basic	188.0			76.0			187.9			70.4
Effect of diluted units	—			—			—			—
Weighted-average limited partner units - diluted	188.0			76.0			187.9			70.4
Basic earnings per unit:
Net income (loss) per limited partner	$	—		$	(0.01	)	$	(0.03	)	$	0.04
Diluted earnings per unit:
Net income (loss) per limited partner	$	—		$	(0.01	)	$	(0.03	)	$	0.04

We exclude potentially dilutive securities from the determination of diluted earnings per unit (as well as their related income statement impacts) when their impact on net income attributable to CMLP per limited partner unit is anti-dilutive. During the three and six months endedJune 30, 2014, we excluded a weighted-average of 6,070,354 and 5,549,570 common units, representing Crestwood Niobrara's preferred units if converted to common units, from our diluted earnings per unit. During the three and six months endedJune 30, 2014, we also excluded a weighted-average of 1,838,799 and 924,479 common units, representing Class A preferred units if converted to common units, from our diluted earnings per unit. There were no units excluded from our dilutive earnings per unit as we did not have any anti-dilutive units for the three and six months endedJune 30, 2013. See Note 8 for additional information regarding the potential conversion of the preferred units to common units.

Note 7 - Financial Instruments

Fair Value

We separate the fair values of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instruments and would be reflected at the end of the period in which the change occurs. At June 30, 2014 and December 31, 2013, there were 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.

14

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

As of June 30, 2014 and December 31, 2013, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair value based on the short-term nature of these instruments. The fair value of the amount outstanding under our credit facility approximates its carrying amount as of June 30, 2014 and December 31, 2013 due primarily to the variable nature of the interest rate of the instrument, which is considered a Level 2 fair value measurement.

We estimate the fair value of our senior notes primarily based on quoted market prices for the same or similar issuances (representing a Level 2 fair value measurement). The following table reflects the carrying value and fair value of our senior notes (in millions):

	June 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2019 Senior Notes	$	351.1	$	376.6	$	351.2	$	379.3
2020 Senior Notes	$	504.3	$	532.7	$	504.7	$	513.8
2022 Senior Notes	$	600.0	$	634.5	$	600.0	$	617.3

Long-Term Debt

Long-term debt consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Credit Facility	$	412.3	$	414.9
2019 Senior Notes	350.0		350.0
Premium on 2019 Senior Notes	1.1		1.2
2020 Senior Notes	500.0		500.0
Fair value adjustment of 2020 Senior Notes	4.3		4.7
2022 Senior Notes	600.0		600.0
Other	3.5		—
Total debt	1,871.2		1,870.8
Less: current portion	24.9		2.9
Total long-term debt	$	1,846.3	$	1,867.9

Credit Facility

We have a five-year $1 billion senior secured revolving credit facility (the Credit Facility), which is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The Credit Facility includes a sub-limit up to $25 million for same-day swing line advances and a sub-limit up to $250 million for letters of credit. Subject to limited exception, the Credit Facility is secured by substantially all of the equity interests and assets of our restricted domestic subsidiaries, and is joint and severally guaranteed by substantially all of our restricted domestic subsidiaries.

On June 11, 2014, we amended our Credit Facility to clarify, among other things, (i) the methodology for calculating the value of our investment in certain joint ventures constituting unrestricted subsidiaries, and (ii) that redemptions, repurchases and retirements of equity interests are permitted to the extent made solely through the issuance of additional equity units. We did not pay any fees to our bank syndicate for this amendment.

At June 30, 2014, the balance outstanding on our Credit Facility was $412.3 million and outstanding standby letters of credit were $31.4 million. We had $366.7 million of available capacity under the revolving credit facility at June 30, 2014 considering our most restrictive debt covenants under the facility. The interest rates on our Credit Facility are based on the prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 2.71% and 5.00% at June 30, 2014. The weighted-average interest rate as of June 30, 2014 was 5.73%.

We are required under our credit agreement to maintain a consolidated leverage ratio (as defined in our credit agreement) of not more than 5.00 (subject to, at our election, a consolidated net leverage ratio of not more than 5.50 to 1.0 during certain periods

15

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

following certain material acquisitions as further described in our credit agreement) to 1.0 and an interest coverage ratio (as defined in our credit agreement) of not less than 2.50 to 1.0.

At June 30, 2014, we elected to use a consolidated net leverage ratio of 5.50 to 1.0. At September 30, 2014, our consolidated net leverage ratio will revert back to 5.00 to 1.0. Our net debt to consolidated EBITDA was approximately 4.56 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 3.69 to 1.0 at June 30, 2014.

Senior Notes

We have three series of senior unsecured notes outstanding, including (i) $350 million in aggregate principal amount of 7.75% Senior Notes due 2019 (the 2019 Senior Notes), (ii) $500 million in aggregate principal amount of 6.0% Senior Notes due 2020 (the 2020 Senior Notes), and (iii) $600 million in aggregate principal amount of 6.125% Senior Notes due 2022 (the 2022 Senior Notes, and together with the 2019 Senior Notes and 2020 Senior Notes, our Senior Notes). Our Senior Notes are guaranteed on a senior unsecured basis by all of our domestic restricted subsidiaries, subject to certain exceptions. 

Under the indenture governing our 2019 Senior Notes, we may not pay any dividend on our common units unless, among other things, at the time of and after giving effect to such dividend payment, no default under the indenture has occurred and is continuing or would occur as a consequence of such dividend payment.

At June 30, 2014, we were in compliance with all of our debt covenants applicable to our Credit Facility and our Senior Notes. For additional information regarding our debt covenants, see our 2013 Annual Report on Form 10-K as filed with the SEC.

On July 17, 2014, we filed a registration statement with the SEC under which we are offering to exchange $600 million in aggregate principal amount of registered 6.125% Senior Notes due 2022 for any and all outstanding 2022 Senior Notes, which were issued in a private offering in November 2013. The terms of the exchange notes are substantially identical to the terms of the 2022 Senior Notes, except that the exchange notes will be freely tradable. We expect to complete the exchange offering in August 2014.

Note 8 - Partners’ Capital

Equity Distribution Agreement

On July 10, 2014, we entered into an equity distribution agreement with Morgan Stanley & Co. LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC (each, a Manager), under which we may offer and sell from time to time through one or more of the Managers, common units having an aggregate offering price of up to $300.0 million. Common units sold pursuant to this at-the-market (ATM) equity distribution program will be issued under a registration statement that became effective on May 27, 2014. We will pay the Managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under our ATM program. We have not issued any common units under this equity distribution program. Additional information on our ATM equity distribution program is available in our Form 8-K filed with the SEC on July 10, 2014.

Distributions

Our partnership agreement requires us to distribute, within 45 days after the end of each quarter, all available cash (as defined in our partnership agreement) to our common and preferred unitholders of record on the applicable record date. The general partner is not entitled to distributions on its non-economic general partner interest.

Distributions to General Partner

We paid cash distributions to our general partner (representing IDRs and distributions related to common units held by the general partner) of approximately $20.9 million and $9.3 million during the six months endedJune 30, 2014 and 2013.

16

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Distributions to Class A Preferred Unit Holders

Our partnership agreement requires us to make quarterly distributions to our Class A Preferred Unit holders. The holders of our Class A Preferred Units (the Preferred Units) are entitled to receive fixed quarterly distributions of $0.5804 per unit. For the 12 quarters following the quarter ended June 30, 2014 (the Initial Distribution Period), distributions on our Preferred Units can be made in additional Preferred Units, cash, or a combination thereof, at our election. If we elect to pay the quarterly distribution through the issuance of additional Preferred Units, the number of units to be distributed will be calculated as the fixed quarterly distribution of $0.5804 per unit divided by the cash purchase price of $25.10 per unit. We accrue the fair value of such distribution at the end of the quarterly period and adjust the fair value of the distribution on the date the additional Preferred Units are distributed. Distributions on our Preferred Units following the Initial Distribution Period will be made in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to our Preferred Unit holders. If we fail to pay the full amount payable to our Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.7059 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if we fail to pay in full any Class A Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter. For additional information on our Preferred Units, see Class A Preferred Units section below.

On July 23, 2014, the board of directors of our general partner authorized the issuance 42,523 Preferred Units to our Preferred Unit holders for the quarter ending June 30, 2014. In accordance with our partnership agreement, the additional Preferred Units will not be issued until the distribution payment date for the quarter ending September 30, 2014.

Distributions to Limited Partners

The following table presents quarterly cash distributions paid to our limited partners (excluding distributions paid to our general partner on its common units held) during the six months endedJune 30, 2014:

Six Months Ended June 30, 2014
Record Date	Payment Date	Per Unit Rate		Cash Distribution (in millions)
February 7, 2014	February 14, 2014	$	0.41	$	74.1
May 8, 2014	May 15, 2014	$	0.41	74.2
				$	148.3

The following table presents Legacy Crestwood's quarterly cash distributions paid to the limited partners (excluding distributions paid to the general partner on its common units held) during the six months ended ended June 30, 2013:

Six Months Ended June 30, 2013
Record Date	Payment Date	Per Unit Rate		Cash Distribution (in millions)
January 31, 2013	February 12, 2013	$	0.51	$	21.0
April 30, 2013	May 10, 2013	$	0.51	27.4
				$	48.4

On July 23, 2014, we declared a distribution of $0.41 per limited partner unit to be paid on August 14, 2014, to unitholders of record on August 7, 2014 with respect to the second quarter of 2014.

Preferred Equity

Class A Preferred Units

On June 17, 2014, we entered into definitive agreements with a group of investors, including Magnetar Capital, affiliates of GSO Capital Partners LP and GE Energy Financial Services (the Class A Purchasers). Under these agreements, we have

17

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

agreed to sell to the Class A Purchasers and the Class A Purchasers have agreed to purchase from us up to $500 million of Preferred Units at a fixed price of $25.10 per unit on or before September 30, 2015. Contemporaneously with the closing ofthis equity commitment, on June 17, 2014, the Class A Purchasers purchased 11,952,191 Preferred Units for a cash purchase price of $25.10 per unit resulting in gross proceeds to us of approximately $300 million (net proceeds of approximately $293.7 million after deducting transaction fees and offering expenses).

Subject to certain conditions, holders of the Preferred Units will have the right to convert Preferred Units into (i) common units on a one-for-one basis after June 17, 2017, or (ii) a number of common units determined pursuant to a conversion ratio set forth in our partnership agreement upon the occurrence of certain events, such as a change in control. Also, subject to certain conditions after the full $500 million purchase commitment has been satisfied, we may convert the Preferred Units into common units at a conversion ratio set forth in the partnership agreement, which is based in part on the aggregate principal amount of the Preferred Units outstanding and the weighted average trading price of our common units. 

The Preferred Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each Preferred Unit entitled to one vote for each common unit into which such Preferred Unit is convertible, except that the Preferred Units are entitled to vote as a separate class on any matter on which all unitholders are entitled to vote that adversely affects the rights, powers, privileges or preferences of the Preferred Units in relation to our other securities outstanding.

Additional information on the terms and conditions of the Preferred Units, including distribution, conversion, voting rights and liquidation preferences, is available on our Form 8-Ks filed with the SEC on June 19, 2014 and July 11, 2014, respectively.

On July 9, 2014, we filed a shelf registration statement with the SEC under which holders of the Preferred Units may sell the common units into which the Preferred Units are convertible. The registration statement became effective on July 18, 2014. We registered 26,299,076 common units under the registration statement.

Crestwood Niobrara Preferred Interest

Crestwood Niobrara issued a preferred interest to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE) in conjunction with the acquisition of its investment in Jackalope. The preferred interest is reflected as non-controlling interest in our consolidated financial statements. During the three and six months endedJune 30, 2014, we allocated approximately $3.7 million and $6.8 million of net income to the non-controlling interest, which was based on the overall return attributable to the preferred security.

Crestwood Niobrara will fund 75% of future capital contributions to Jackalope through additional preferred interest issuances to GE (up to a maximum of an additional $20.3 million as of June 30, 2014), with the remainder to be funded through our capital contributions to Crestwood Niobrara. During the six months endedJune 30, 2014, GE made capital contributions of $33.6 million to Crestwood Niobrara in exchange for an equivalent number of preferred units. Through June 30, 2014, GE has made cumulative capital contributions totaling $129.7 million.

Crestwood Niobrara has the option to pay distributions to GE with cash or by issuing additional preferred units through the January 2015 distribution. During the three months ended March 31, 2014 and June 30, 2014, Crestwood Niobrara issued 2,210,294 and 2,536,010 preferred units to GE in lieu of paying a cash distribution. We serve as the managing member of Crestwood Niobrara and, subject to certain restrictions, we have the ability to redeem GE’s preferred interest in either cash or our common units at an amount equal to the face amount of the preferred units plus an applicable return. On July 30, 2014,Crestwood Niobrara issued 3,073,357 preferred units to GE in lieu of paying a cash distribution.

Other Partners’ Capital Transaction

On January 8, 2013, Legacy Crestwood acquired Crestwood Holdings’ 65% membership interest in Crestwood Marcellus Midstream LLC (CMM) for approximately $258.0 million, of which approximately $129.0 million was funded through the issuance of 6,190,469 Class D units and the issuance of 133,060 general partner units to the Legacy Crestwood general partner. We reflected the issuances of the Class D and general partner units as distributions for additional interest in CMM in our consolidated statements of cash flows for the six months endedJune 30, 2013.

18

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 9 - Long-Term Incentive Plan

Long-term incentive awards are granted under the Crestwood Midstream Partners LP Long Term Incentive Plan (Crestwood LTIP) (formerly the Inergy Midstream, L.P. Long Term Incentive Plan) in order to align the economic interests of key employees and directors with those of CMLP's common unitholders and to provide an incentive for continuous employment. Long-term incentive compensation consist solely of grants of restricted common units (which represent limited partner interests of CMLP) which vest based upon continued service.

On January 17, 2014, we issued restricted unit awards, which were approved by the CMLP Board's compensation committee, to certain key employees. The awards consisted of an annual award based on a percentage of each recipient's annual salary, and a one-time bridge award designed to provide an additional base award to certain key employees with no remaining unvested awards given that their previously accumulated equity ownership in Legacy Inergy and Legacy Crestwood vested as a result of the change of control with the Crestwood Merger. Both of these awards vest upon continued service.

The following table summarizes information regarding restricted unit activity during the six months endedJune 30, 2014:

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	250,557		$	22.13
Vested - restricted units	(190,818	)	$	22.29
Granted - restricted units	792,034		$	23.39
Forfeited	(41,523	)	$	23.58
Unvested - June 30, 2014	810,250		$	23.25

As of June 30, 2014 and December 31, 2013, we had total unamortized compensation expense of approximately $13.3 million and $1.8 million related to restricted units, which we expect will be amortized during the next three years (or sooner in certain cases, which generally represents the original vesting period of these instruments), except for grants to non-employee directors of our general partner, which vest over one year. As of June 30, 2014, the restricted units issued under the Legacy Inergy long-term incentive plan were fully vested and as such, there was no unamortized compensation expense related to those units at June 30, 2014. We recognized compensation expense of approximately $3.3 million and $0.9 million during the three months ended June 30, 2014 and 2013 and $6.2 million and $1.5 million during the six months endedJune 30, 2014 and 2013, which is included in general and administrative expenses on our consolidated statements of operations. An additional $1.9 million and $3.6 million of net compensation expense was allocated from CEQP to us during the three and six months endedJune 30, 2014 and an additional $0.2 million was allocated from CEQP to us during the three and six months endedJune 30, 2013 (see Note 11). The compensation expense recognized during the three and six months endedJune 30, 2013 was primarily related to the Legacy Crestwood long-term incentive plan. We granted restricted units with a grant date fair value of approximately $0.8 million and $18.5 million during the three and six months endedJune 30, 2014.  As of June 30, 2014, we had 6,460,338 units available for issuance under the Crestwood LTIP.

Under the Crestwood LTIP, participants who have been granted restricted units may elect to have common units withheld 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 Crestwood LTIP on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When we withhold these common units, we are required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. During the three months ended June 30, 2014 and 2013, we withheld 61,076 and 900 common units and during the six months endedJune 30, 2014 and 2013, we withheld 68,532 common units and 2,429 common units to satisfy employee tax withholding obligations.

19

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 10 - Commitments and Contingencies

Legal Proceedings

Class Action Lawsuits.Five putative class action lawsuits challenging the Crestwood 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 of the cases named Legacy Crestwood (since merged with the Company), Crestwood Gas Services GP LLC, Crestwood Holdings LLC, the current and former directors of Crestwood Gas Services GP LLC, CEQP, the Company, Crestwood Midstream GP LLC (formerly NRGM GP, LLC), and Intrepid Merger Sub, LLC as defendants. All of the suits were brought by purported holders of common units of Legacy Crestwood, both individually and on behalf of a putative class consisting of holders of common units of Legacy 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 Legacy Crestwood by agreeing to a transaction with inadequate consideration and unfair terms and pursuant to an inadequate process. The lawsuits further alleged that CEQP, the Company, Crestwood Midstream GP LLC, and Intrepid Merger Sub, LLC aided and abetted the Legacy 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 has been granted by the Court, such that the Hawley action has now been 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 matter as In re Crestwood Midstream Partners Unitholder Litigation, Lead Case No. 4:13-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. A final settlement was approved by the Court on May 16, 2014, and the settlement did not have a material impact to our consolidated financial statements.

Arrow Acquisition Class Action Lawsuit. Prior to the completion of the Arrow Acquisition on November 8, 2013, a train transporting over 50,000 barrels of crude oil produced in North Dakota derailed in Lac Megantic, Quebec, Canada on July 6, 2013. The derailment resulted in the death of 47 people, injured numerous others, and caused severe damage to property and the environment.  In October 2013, certain individuals suffering harm in the derailment filed a motion to certify a class action lawsuit in the Superior Court for the District of Megantic, Province of Quebec, Canada, on behalf of all persons suffering loss in the derailment.

In March 2014, the plaintiffs filed their fourth amended motion to name Arrow and numerous other energy companies as additional defendants in the class action lawsuit. The plaintiffs have named at least 53 defendants purportedly involved in the events leading up to the derailment, including the producers and sellers of the crude being transported, the midstream companies that transported the crude from the well head to the rail system, the manufacturers of the rail cars used to transport the crude, the railroad companies involved, the insurers of these companies, and the Canadian Attorney General.  The plaintiffs allege, among other things, that Arrow (i) was a producer of the crude oil being transported on the derailed train, (ii) was negligent in failing to properly classify the crude delivered to the trucks that hauled the crude to the rail loading terminal, and (iii) owed a duty to the petitioners to ensure the safe transportation of the crude being transported.  The motion to authorize the class action and motions in opposition were heard by the Court in June 2014.  The Canadian Attorney General was granted an extension of time to respond and will make their oral argument opposing the motion at the end of August 2014. We do not anticipate a ruling from the Judge on Petitioners' motion to authorize the class action until the fourth quarter of 2014. We believe the claims against us are without merit and will vigorously defend ourselves.  Moreover, to the extent this action proceeds, we believe we have meritorious defenses to the claims.  Because this litigation is in the early stages of the proceeding, we are unable to estimate a reasonably possible loss or range of loss in this matter.  We believe this claim is an insurable event under our insurance policy and we have notified our insurance company of the claim.

20

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

We are periodically involved in litigation proceedings. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, then we accrue the estimated amount. The results of litigation proceedings cannot be predicted with certainty. We could incur judgments, enter into settlements or revise our expectations regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations or cash flows in the period in which the amounts are paid and/or accrued. As of June 30, 2014 and December 31, 2013, we had less than $0.1 million accrued for our outstanding legal matters. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures for which we can estimate will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.

Any loss estimates are inherently subjective, based on currently available information, and are subject to management's judgment and various assumptions. Due to the inherently subjective nature of these estimates and the uncertainty and unpredictability surrounding the outcome of legal proceedings, actual results may differ materially from any amounts that have been accrued.

Regulatory Compliance

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

Environmental Compliance

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. We are subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. Our accruals and potential exposures related to our environmental matters were immaterial at June 30, 2014 and December 31, 2013.

On July 4, 2014, we experienced a release of approximately 25,000 barrels of produced water on our Arrow water gathering system located on the Fort Berthold Indian Reservation in North Dakota. We immediately notified the National Response Center, the Three Affiliated Tribes and numerous other regulatory authorities, and thereafter contained and cleaned up the release promptly. We placed the impacted segment of the water line back into service on July 20, 2014. We will continue our long-term remediation efforts to ensure the impacted lands are restored to their prior state, and we will potentially be subject to substantial fines and penalties. We believe that the release is an insurable event under our policies, and we have notified our carriers of the event. Because this matter is in the early stages of remediation, we are unable to estimate a reasonably possible loss or range of loss.

Contingent Consideration - Antero

In connection with the acquisition of Antero Resources (Antero), we agreed to pay Antero conditional consideration in the form of potential additional cash payments of up to $40 million, depending on the achievement of certain defined average annual production levels achieved during 2012, 2013 and 2014. During 2012 and 2013, Antero did not meet the annual production level to earn additional payments. Based on our estimates of Antero’s 2014 production, we believe their production levels will exceed the annual production threshold in the earn-out provision and accordingly, we recognized a liability of $40.0 million and $31.4 million as of June 30, 2014 and December 31, 2013, which we anticipate paying in the first quarter of 2015.

21

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 11 - Related Party Transactions

We do not have any employees. We share common management, operating and administrative and overhead costs with CEQP. We have an Omnibus Agreement with CEQP that requires us to reimburse CEQP for all shared costs incurred on our behalf, except for certain unit based compensation costs which are treated as capital transactions. CEQP allocated to us $12.9 million and $28.7 million of costs for the three and six months endedJune 30, 2014. Included in this amount was $1.9 million and $3.6 million of net unit-based compensation charges for the three and six months endedJune 30, 2014. During the three and six months endedJune 30, 2013, CEQP allocated to us $0.5 million of costs, including $0.2 million of net unit-based compensation charges. Due to the nature of these shared costs, it is not practicable to estimate what the costs would have been on a stand-alone basis. Accordingly, the accompanying financial statements may not necessarily be indicative of the conditions that would have existed, or the results of operations that would have occurred, if we operated as a stand-alone entity.

The following table shows revenues, costs of goods sold and general and administrative expenses from our affiliates for the three and six months endedJune 30, 2014 and 2013 (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014(a)		2013		2014(a)		2013
Gathering and processing revenues	$	0.7	$	24.6	$	1.6	$	50.2
NGL and crude services revenues	$	3.4	$	0.4	$	6.7	$	0.4
Gathering and processing costs of goods sold	$	9.8	$	7.8	$	20.8	$	14.6
General and administrative expenses	$	4.5	$	5.3	$	8.3	$	10.6

(a) Concurrent with the Crestwood Merger, Quicksilver Resources Inc. (Quicksilver) is no longer a related party, and as a result our transactions with Quicksilver subsequent to June 19, 2013, are now considered non-affiliated transactions.

The following table shows accounts receivable and accounts payable from our affiliates as of June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Accounts receivable	$	7.2	$	1.1
Accounts payable	$	13.8	$	8.7

For additional information regarding our related party transactions, see our 2013 Annual Report on Form 10-K as filed with the SEC.

Note 12 - Segments

Financial Information

We have three operating and reporting segments; (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) NGL and crude services operations. Our gathering and processing operations engage in the gathering, processing, treating, compression, transportation and sales of natural gas and the delivery of NGLs. Our storage and transportation operations provide regulated natural gas storage and transportations services to producers, utilities and other customers. Our NGL and crude services operations provide gathering, storage and transportation services to producers, refiners, marketers, and other customers that effectively provide flow assurances to our customers, as well as the production and sale of salt products. Our corporate operations include all general and administrative expenses that are not allocated to the reportable segments. We assess the performance of our operating segments based on EBITDA, which represents operating income plus depreciation, amortization and accretion expense.

22

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The following table is a reconciliation of net income to EBITDA (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Net income	$	11.7	$	6.7	$	17.2	$	15.6
Add:
Interest and debt expense, net	29.0		12.5		57.1		23.9
Provision for income taxes	0.1		0.3		0.8		0.7
Depreciation, amortization and accretion	54.9		20.9		105.7		38.3
EBITDA	$	95.7	$	40.4	$	180.8	$	78.5

The following tables summarize the reportable segment data for the three and six months endedJune 30, 2014 and 2013 (in millions).

	Three Months Ended June 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Operating revenues	$	83.4		$	45.4	$	546.9		$	—		$	675.7
Costs of product/services sold	17.6			3.8		497.7			—			519.1
Operations and maintenance expense	14.7			4.4		13.6			—			32.7
General and administrative expense	—			—		—			21.3			21.3
Gain on long-lived assets	0.5			0.6		—			—			1.1
Loss on contingent consideration	(6.5		)	—		—			—			(6.5		)
Loss from unconsolidated affiliates, net	(0.6		)	—		(0.9		)	—			(1.5		)
EBITDA	$	44.5		$	37.8	$	34.7		$	(21.3	)	$	95.7
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	1,980.2		$	1,960.6	$	2,536.7		$	158.1		$	6,635.6
Cash expenditures for property, plant and equipment	$	79.4		$	1.3	$	13.6		$	2.7		$	97.0

	Three Months Ended June 30, 2013
	Gathering and Processing		Storage and Transportation		NGL and Crude Services		Corporate			Total
Operating revenues	$	71.1	$	5.5	$	3.5	$	—		$	80.1
Costs of product/services sold	14.0		0.4		0.9		—			15.3
Operations and maintenance expense	12.6		0.6		0.2		—			13.4
General and administrative expense	—		—		—		11.0			11.0
EBITDA	$	44.5	$	4.5	$	2.4	$	(11.0	)	$	40.4
Goodwill	$	95.0	$	691.7	$	609.1	$	—		$	1,395.8
Total assets	$	1,652.0	$	1,997.0	$	1,232.5	$	40.2		$	4,921.7
Cash expenditures for property, plant and equipment	$	56.0	$	2.2	$	1.0	$	—		$	59.2

23

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

	Six Months Ended June 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Operating revenues	$	162.9		$	89.7	$	960.1		$	—		$	1,212.7
Costs of product/services sold	36.3			7.0		873.9			—			917.2
Operations and maintenance expense	28.1			8.7		23.9			—			60.7
General and administrative expense	—			—		—			45.4			45.4
Gain on long-lived assets	1.0			0.6		—			—			1.6
Loss on contingent consideration	(8.6		)	—		—			—			(8.6		)
Loss from unconsolidated affiliates, net	(0.3		)	—		(1.3		)	—			(1.6		)
EBITDA	$	90.6		$	74.6	$	61.0		$	(45.4	)	$	180.8
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	1,980.2		$	1,960.6	$	2,536.7		$	158.1		$	6,635.6
Cash expenditures for property, plant and equipment	$	121.1		$	2.5	$	37.5		$	3.6		$	164.7

	Six Months Ended June 30, 2013
	Gathering and Processing		Storage and Transportation		NGL and Crude Services		Corporate			Total
Operating revenues	$	143.5	$	5.5	$	3.5	$	—		$	152.5
Costs of product/services sold	27.5		0.4		0.9		—			28.8
Operations and maintenance expense	25.6		0.6		0.2		—			26.4
General and administrative expense	—		—		—		18.8			18.8
EBITDA	$	90.4	$	4.5	$	2.4	$	(18.8	)	$	78.5
Goodwill	$	95.0	$	691.7	$	609.1	$	—		$	1,395.8
Total assets	$	1,652.0	$	1,997.0	$	1,232.5	$	40.2		$	4,921.7
Cash expenditures for property, plant and equipment	$	79.9	$	2.2	$	1.0	$	0.4		$	83.5

Major Customers

Two customers, Tesoro Refining & Marketing Company (Tesoro) (22%) and QEP Energy Company (QEP) (12%) accounted for 10% or more of our total consolidated revenues for the three months ended June 30, 2014. Tesoro (20%) and QEP (12%) also accounted for 10% or more of our total consolidated revenues for the six months endedJune 30, 2014. These customers' revenues are reflected in the NGL and crude services segment. Two customers, Quicksilver (30%) and Antero Resources Appalachian Corporation (Antero) (19%), accounted for 10% or more of our total consolidated revenues for the three months ended June 30, 2013. Quicksilver (32%) and Antero (19%), also accounted for 10% or more of our total consolidated revenues for the six months endedJune 30, 2013. These customers' revenues are reflected in the gathering and processing segment.

Three customers, QEP (14%), Halcon Resources Corp. (Halcon) (18%) and WPX (13%), accounted for 10% or more of our consolidated accounts receivable at June 30, 2014. One customer, Tesoro, accounted for approximately 19% of our consolidated accounts receivable at December 31, 2013. These customers' accounts receivable are reflected in the NGL and crude services segment.

24

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 13 – Condensed Consolidating Financial Information

CMLP is a holding company and owns no operating assets and have no significant operations independent of our subsidiaries. Obligations under our Senior Notes and our Credit Facility are jointly and severally guaranteed by substantially all of our restricted domestic subsidiaries, except for Crestwood Niobrara and PRBIC and their subsidiaries (Non-Guarantor Subsidiaries). Crestwood Midstream Finance Corp., the co-issuer of our Senior Notes, 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.

The tables below present condensed consolidating financial statements for us (parent) on a stand-alone, unconsolidated basis, and our combined guarantor and combined non-guarantor subsidiaries as of June 30, 2014 and December 31, 2013, and for the three-month and six-month periods ended June 30, 2014.  As discussed in Note 2, the Crestwood Merger was accounted for as a reverse merger between entities under common control, and as such, changes in the composition of guarantors and non-guarantors should be reflected retrospectively based on the guarantor structure that existed as of the end of the most recent balance sheet.  Accordingly, we have not reflected condensed consolidating financial information for the three-month and six-month periods ended June 30, 2013 because our unrestricted subsidiaries were not formed or were not designated as unrestricted subsidiaries as of June 30, 2013.  

25

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Balance Sheet
June 30, 2014
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	0.1	$	17.2		$	—	$	—		$	17.3
Accounts receivable	576.5		279.0			0.1		(565.2		)	290.4
Inventories	—		7.6			—		—			7.6
Other current assets	—		13.9			—		—			13.9
Total current assets	576.6		317.7			0.1		(565.2		)	329.2
Property, plant and equipment, net	5.8		3,459.1			—		—			3,464.9
Goodwill and intangible assets, net	—		2,621.9			—		—			2,621.9
Investment in consolidated affiliates	6,496.4		—			—		(6,496.4		)	—
Investment in unconsolidated affiliates	—		—			198.4		—			198.4
Other assets	—		21.2			—		—			21.2
Total assets	$	7,078.8	$	6,419.9		$	198.5	$	(7,061.6	)	$	6,635.6
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	833.0	$	(73.3	)	$	0.1	$	(565.2	)	$	194.6
Other current liabilities	26.2		167.4			—		—			193.6
Total current liabilities	859.2		94.1			0.1		(565.2		)	388.2
Long-term liabilities:
Long-term debt, less current portion	1,846.3		—			—		—			1,846.3
Other long-term liabilities	1.6		27.8			—		—			29.4
Total long-term liabilities	1,847.9		27.8			—		—			1,875.7
Partners' capital	4,230.3		6,298.0			57.0		(6,355.0		)	4,230.3
Interest of non-controlling partners in subsidiaries	141.4		—			141.4		(141.4		)	141.4
Total partners' capital	4,371.7		6,298.0			198.4		(6,496.4		)	4,371.7
Total liabilities and partners' capital	$	7,078.8	$	6,419.9		$	198.5	$	(7,061.6	)	$	6,635.6

26

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Balance Sheet
December 31, 2013
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	0.1	$	1.6		$	1.0	$	—		$	2.7
Accounts receivable	466.8		197.8			0.2		(459.7		)	205.1
Inventories	—		7.0			—		—			7.0
Other current assets	—		10.2			—		—			10.2
Total current assets	466.9		216.6			1.2		(459.7		)	225.0
Property, plant and equipment, net	4.8		3,345.3			—		—			3,350.1
Goodwill and intangible assets, net	—		2,653.6			—		—			2,653.6
Investment in consolidated affiliates	6,385.2		—			—		(6,385.2		)	—
Investment in unconsolidated affiliates	—		—			151.4		—			151.4
Other assets	—		21.7			—		—			21.7
Total assets	$	6,856.9	$	6,237.2		$	152.6	$	(6,844.9	)	$	6,401.8
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	782.7	$	(159.8	)	$	—	$	(459.7	)	$	163.2
Other current liabilities	11.5		139.6			0.2		—			151.3
Total current liabilities	794.2		(20.2		)	0.2		(459.7		)	314.5
Long-term liabilities:
Long-term debt, less current portion	1,867.9		—			—		—			1,867.9
Other long-term liabilities	1.7		24.6			—		—			26.3
Total long-term liabilities	1,869.6		24.6			—		—			1,894.2
Partners' capital	4,092.1		6,232.8			51.4		(6,284.2		)	4,092.1
Interest of non-controlling partners in subsidiaries	101.0		—			101.0		(101.0		)	101.0
Total partners' capital	4,193.1		6,232.8			152.4		(6,385.2		)	4,193.1
Total liabilities and partners' capital	$	6,856.9	$	6,237.2		$	152.6	$	(6,844.9	)	$	6,401.8

27

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	82.7		$	—		$	—		$	82.7
Storage and transportation	—			45.4			—			—			45.4
NGL and crude services	—			543.5			—			—			543.5
Related party	—			4.1			—			—			4.1
	—			675.7			—			—			675.7
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			7.8			—			—			7.8
Storage and transportation	—			3.8			—			—			3.8
NGL and crude services	—			497.7			—			—			497.7
Related party	—			9.8			—			—			9.8
	—			519.1			—			—			519.1
Expenses:
Operations and maintenance	—			32.7			—			—			32.7
General and administrative	(0.9		)	22.2			—			—			21.3
Depreciation, amortization and accretion	0.2			54.7			—			—			54.9
	(0.7		)	109.6			—			—			108.9
Other operating income (expense):
Loss on contingent consideration	—			(6.5		)	—			—			(6.5		)
Other	—			1.1			—			—			1.1
Operating income	0.7			41.6			—			—			42.3
Interest and debt expense, net	(29.2		)	0.2			—			—			(29.0		)
Equity in net income (loss) of subsidiary	40.2			—			—			(40.2		)	—
Other	—			—			(1.5		)	—			(1.5		)
Income (loss) before income taxes	11.7			41.8			(1.5		)	(40.2		)	11.8
Provision for income taxes	—			0.1			—			—			0.1
Net income (loss)	11.7			41.7			(1.5		)	(40.2		)	11.7
Net income attributable to non-controlling partners	—			—			(3.7		)	—			(3.7		)
Net income (loss) attributable to Crestwood Midstream Partners LP	11.7			41.7			(5.2		)	(40.2		)	8.0
Net income attributable to Class A preferred units	(1.1		)	—			—			—			(1.1		)
Net income (loss) attributable to partners	10.6			41.7			(5.2		)	(40.2		)	6.9

28

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	161.3		$	—		$	—		$	161.3
Storage and transportation	—			89.7			—			—			89.7
NGL and crude services	—			953.4			—			—			953.4
Related party	—			8.3			—			—			8.3
	—			1,212.7			—			—			1,212.7
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			15.5			—			—			15.5
Storage and transportation	—			7.0			—			—			7.0
NGL and crude services	—			873.9			—			—			873.9
Related party	—			20.8			—			—			20.8
	—			917.2			—			—			917.2
Expenses:
Operations and maintenance	—			60.7			—			—			60.7
General and administrative	(3.0		)	48.4			—			—			45.4
Depreciation, amortization and accretion	0.4			105.3			—			—			105.7
	(2.6		)	214.4			—			—			211.8
Other operating income (expense):
Loss on contingent consideration	—			(8.6		)	—			—			(8.6		)
Other	—			1.6			—			—			1.6
Operating income	2.6			74.1			—			—			76.7
Interest and debt expense, net	(57.3		)	0.2			—			—			(57.1		)
Equity in net income (loss) of subsidiary	71.9			—			—			(71.9		)	—
Other	—			—			(1.6		)	—			(1.6		)
Income (loss) before income taxes	17.2			74.3			(1.6		)	(71.9		)	18.0
Provision for income taxes	—			0.8			—			—			0.8
Net income (loss)	17.2			73.5			(1.6		)	(71.9		)	17.2
Net (income) attributable to non-controlling partners	—			—			(6.8		)	—			(6.8		)
Net income (loss) attributable to Crestwood Midstream Partners LP	17.2			73.5			(8.4		)	(71.9		)	10.4
Net income attributable to Class A preferred units	(1.1		)	—			—			—			(1.1		)
Net income (loss) attributable to partners	16.1			73.5			(8.4		)	(71.9		)	9.3

29

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.)

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(16.7	)	$	112.1		$	—		$	—		$	95.4
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(19.5		)	—			—			(19.5		)
Purchases of property, plant and equipment	(2.3		)	(162.4		)	—			—			(164.7		)
Investment in unconsolidated affiliates, net	—			(2.8		)	(45.8		)	—			(48.6		)
Capital contribution from consolidated affiliates	(11.2		)	(2.8		)	—			14.0			—
Other	(265.5		)	—			—			265.5			—
Net cash provided by (used in) investing activities	(279.0		)	(187.5		)	(45.8		)	279.5			(232.8		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2.5			858.1			—			—			860.6
Principal payments on long-term debt	—			(863.2		)	—			—			(863.2		)
Distributions paid	—			(169.2		)	—			—			(169.2		)
Contributions from parent	—			2.8			11.2			(14.0		)	—
Net proceeds from issuance of preferred equity	—			—			33.6			—			33.6
Net proceeds from issuance of Class A preferred units	293.7			—			—			—			293.7
Payments on capital leases	(0.5		)	(1.4		)	—			—			(1.9		)
Taxes paid for unit-based compensation vesting	—			(1.5		)	—			—			(1.5		)
Net change in payables to affiliates	—			265.5			—			(265.5		)	—
Other	—			(0.1		)	—			—			(0.1		)
Net cash provided by (used in) financing activities	295.7			91.0			44.8			(279.5		)	152.0
Net increase in cash	—			15.6			(1.0		)	—			14.6
Cash at beginning of period	0.1			1.6			1.0			—			2.7
Cash at end of period	$	0.1		$	17.2		$	—		$	—		$	17.3

30

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

Item 2 of this report should be read in conjunction with the accompanying consolidated financial statements and Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in the 2013 Annual Report on Form 10-K of Crestwood Midstream Partners LP for the year ended December 31, 2013.

This report, including information included or incorporated by reference herein, contains forward-looking statements concerning the financial condition, results of operations, plans, objectives, future performance and business of our company and its subsidiaries. These forward-looking statements include:

• statements that are not historical in nature, including, but not limited to: (i) our expectation that we will complete certain projects, and achieve certain capacity or throughput amounts, by specified target dates; (ii) our assessment of certain developing and emerging shale and tight gas plays, including our estimates of producer activity within certain of these areas; and (iii) our belief that we do not have material potential liability in connection with legal proceedings that would have a significant financial impact on our consolidated financial condition, results of operations or cash flows; and

• statements preceded by, followed by or that contain forward-looking terminology including the words “believe,” “expect,” “may,” “will,” “should,” “could,” “anticipate,” “estimate,” “intend” or the negation thereof, or similar expressions.

Forward-looking statements are not guarantees of future performance or results. They involve risks, uncertainties and assumptions. Actual results may differ materially from those contemplated by the forward-looking statements due to, among others, the following factors:

• our ability to successfully implement our business plan for our assets and operations:

• governmental legislation and regulations;

• industry factors that influence the supply of and demand for crude oil, natural gas and NGLs;

• industry factors that influence the demand for services in the markets (particularly unconventional shale plays) in which we provide services;

• weather conditions;

• the availability of crude oil, natural gas and NGLs, and the price of those commodities, to consumers relative to the price of alternative and competing fuels;

• economic conditions;

• costs or difficulties related to the integration of our existing businesses and acquisitions;

• environmental claims;

• operating hazards and other risks incidental to the provision of midstream services, including gathering, compressing, treating, processing, fractionating, transporting and storing crude oil, NGLs and natural gas;

• interest rates; and

• the price and availability of debt and equity financing.

We have described under Item 1A, Risk Factors, additional factors that could cause actual results to be materially different from those described in the forward-looking statements. Other factors that we have not identified in this report could also have this effect.

Our Company

We manage, own and operate crude oil, natural gas and NGL midstream assets and operations. Headquartered in Houston, Texas, we are a fully-integrated midstream solution provider that specializes in connecting shale-based energy supplies to key demand markets. We conduct gathering, processing, storage and transportation operations in the most prolific shale plays across the United States.

Our three business segments include (i) gathering and processing, which includes our natural gas G&P operations; (ii) storage and transportation, which includes our natural gas storage and transportation operations; and (iii) NGL and crude services, which includes our crude oil gathering, storage and transportation operations, NGL storage facility and salt production business.

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Gathering and Processing

Our G&P operations provide gathering, compression, treating, and processing services to producers in multiple unconventional resource plays across the United States. We have established footprints in “core of the core” areas of several shale plays with delineated condensate and rich gas windows offering attractive producer economics, while maintaining operations in several prolific dry gas plays.

• Marcellus Shale. In the rich gas southwest portion of the Marcellus Shale, we have completed several expansions on our Antero gathering systems that have increased total gathering capacity to 706 MMcf/d as of June 30, 2014. During the second quarter of 2014, we completed and placed into service a 120 MMcf/d compressor station in Antero's western development area. Additional expansion projects on our Marcellus systems are expected to increase total gathering capacity to approximately 875 MMcf/d and gathering volumes to 750 MMcf/d at year-end 2014.    At June 30, 2104, we estimate that Antero had 23 drilled but uncompleted wells on pads connected to our gathering system, and we estimate that Antero continues to operate approximately 15 drilling rigs in the southwestern Marcellus Shale.

• Powder River Basin (PRB) Niobrara. Expansion of the Jackalope gas gathering system and construction of the 120 MMcf/d Bucking Horse gas processing plant remains on schedule to be completed in the fourth quarter of 2014. During the three and six month ended June 30, 2014, gathering volumes on the Jackalope gas gathering system were 44 MMcf/d and 49 MMcf/d and were constrained due to third party processing limitations. Chesapeake continues to operate three drilling rigs on the 311,000 acre dedication and has approximately 36 drilled but uncompleted wells available to be connected to the system when the Bucking Horse gas processing plant is placed in service. Under Jackalope’s cost of service gathering agreement, gathering fees have increased in 2014, taking into account the significant capital being invested in the midstream infrastructure. In addition, there has been a considerable increase in rig activity and drilling permits in recent months targeting multiple producing formations such as the Niobrara, Frontier/Turner, Sussex/Shannon and Parkman/Teapot. We are actively working with area producers to develop additional gathering and processing facilities beyond our Jackalope acreage in the region.

• Permian Delaware Basin. On April 1, 2014, we announced a Phase 2 expansion of our Willow Lake project to include a 20 MMcf/d cryogenic processing facility and expand our gathering system, anchored by a 10-year fixed-fee gas gathering and processing agreement with Legend Production Holdings, LLC (Legend) in Eddy County, New Mexico. Construction of the Willow Lake plant remains on schedule for completion in third quarter of 2014 at a cost of approximately $25 million to $30 million. We are also actively working with area producers, particularly those targeting the Bone Spring, Avalon and Wolfcamp formations, for a potential Phase 3 expansion and relocation to our proposed Delaware Ranch Plant site of our West Johnson County processing plant (located in the Barnett Shale region) which has a capacity of approximately 120 MMcf/d. These projects support emerging production from one of the most active drilling areas within the region.  

• Barnett Shale. Our Barnett Shale dry and rich gas gathering systems had a 13% increase in average volumes during the second quarter of 2014. Our primary customer in the Barnett, Quicksilver, resumed drilling activity in the Alliance and Lake Arlington dry gas areas and connected 18 wells to our gathering systems during the first half of 2014. As a result, gathering volumes on the Barnett Shale systems have averaged approximately 439 MMcf/d during the second quarter of 2014, which is up from 387 MMcf/d during the first quarter of 2014.

Storage and Transportation

Our storage and transportation segment consists of our interconnected natural gas storage and transportation assets in the Northeast. We have four natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake) and three transportation pipelines (North-South Facilities, MARC I and the East Pipeline) located in the Northeast in or near the Marcellus Shale. Our storage facilities provide 41.0 Bcf of firm storage capacity and our transportation assets provide more than 1.0 Bcf/d of firm transportation capacity to producers, utilities, marketers and other customers.

We continued to experience high demand for storage and transportation services during the first half of 2014 due to continued growth in Marcellus shale production, sustained colder weather throughout the region, increased volatility and widening of basis differential along our pipeline systems.  During the second quarter of 2014, total firm throughput from our storage and transportation services averaged approximately 1.6 Bcf/d, an increase of 14% from the first quarter of 2014, with peak deliveries reaching as high as 1.76 Bcf/d during the six month period ending June 30, 2014. 

32

Following a successful open season during the first half of 2014, we executed long-term agreements to provide an additional 40,000 dekatherms per day (Dth/d) of firm transportation on our North/South facilities and MARC I Pipeline which began on April 1, 2014. We have executed precedent agreements to provide an additional 117,000 Dth/d of firm capacity on these systems which is expected to begin in the first quarter of 2015, and we are in active negotiations with customers to provide up to 125,000 Dth/d of additional firm service starting in the latter half of 2015.  The additional capacity would be completed through the modification and replacement of an existing compressor unit at the NS -1 station.

NGL and Crude Services

Our NGL and crude services segment consists of our crude oil gathering systems, rail terminals and other transportation assets, as well as our NGL storage facility and US Salt. We have facilities located in the core of the Bakken Shale, one of the most prolific crude oil shales in North America, and the premium Northeast demand market. We utilize these facilities on a portfolio basis to provide integrated supply and logistics solutions to producers, refiners and other customers.

• Arrow System (Bakken). Following the harsh winter that negatively impacted our first quarter of 2014, average crude, natural gas and produced water volumes gathered by our gathering systems have increased approximately 35% in the second quarter compared to the first quarter of 2014, and we anticipate that such volumes will continue to increase during the third quarter. In addition, we are adding 200,000 barrels of crude oil storage on the Arrow gathering system and contracting for firm pipeline transportation capacity on third party systems that directly connect our Arrow system and our COLT Hub. We expect to commence construction of the new storage tank in the third quarter of 2014 and place it into service in 2015. In the second quarter of 2014, we also acquired 10,000 Bbls/d of firm transportation capacity on Tesoro High Plains Pipeline's (THPP) crude oil expansion project that connects our Arrow system and COLT Hub. THPP expects to place the expansion project in service in September 2014.

• COLT Hub (Bakken). We substantially completed the COLT Hub expansion project (including expansion of rail loading capacity to 160,000 Bbls/d and adding 480,000 barrels of storage) in the first quarter of 2014 and have since experienced daily loading volumes in excess of the first quarter average volumes (as high as 154,000 Bbls/d) in the second quarter. New long-term agreements with BP Products North America, Inc. and Statoil Marketing & Trading in 2014, which were effective January 1, 2014, continue to further support the COLT expansion. We expect to complete the installation of new release and departure track at the COLT Hub in the third quarter of 2014, which will provide greater operational flexibility to our customers and the BNSF Railroad and consequently improve utilization rates. We have also ordered two crude oil unit trains, which we expect to receive during the first half of 2015.

• Transportation Fleet (Bakken). In the second quarter of 2014, we acquired LT Enterprises' crude oil and produced water transportation fleet based in Watford City, North Dakota. This acquisition adds approximately 20,000 Bbls/d of crude oil transportation capacity to our existing Bakken transportation fleet. As a result of the Red Rock and LT Enterprises acquisitions, we now own approximately 48,000 Bbls/d of crude oil and water transportation capacity in Watford City, North Dakota. We expect these fleet acquisitions to (i) further expand the menu of integrated takeaway solutions that we are able to offer to Bakken producers, (ii) provide greater crude marketing opportunities for us in the region, and (iii) provide opportunities to transport water volumes being produced by our Arrow customers until we are able to increase pipeline takeaway capacity on the Arrow system.

Regulatory Matters

We are experiencing greater regulatory challenges relative to our Bakken crude oil operations, particularly with respect to (i) increased regulation and enforcement efforts relating to the crude packaging classifications, which predominantly impacts our crude-by-rail operations at the COLT Hub and our crude oil sales at the Arrow central delivery point, and (ii) recent right-of-way regulations implemented by the MHA Nation that are designed to foster more environmentally-friendly oil and gas practices and to generate revenue from oil and gas activities performed on the Fort Berthold Reservation. We expect to manage these regulatory challenges accordingly and, in this regard, we are working closely with (i) regulatory authorities to ensure compliance with existing regulation and provide input on proposed initiatives, and (ii) the MHA Nation to craft right-of-way policies and exemptions that strike an appropriate balance between the industry and the MHA Nation. However, we cannot provide any assurances that new regulatory challenges facing Bakken producers and our company will not have an impact our results of operations in a material and adverse manner.

We continue to pursue the state regulatory permits required to construct our proposed Finger Lakes NGL storage facility near Watkins Glen, New York.  This year’s harsh winter conditions significantly taxed the propane supply infrastructure in the Northeast, to the point where New York propane consumers alone incurred more than $100 million of incremental supply delivery costs that could have been avoided had our proposed storage facility been operational.  With domestic propane

33

production and export volumes expected to increase in the near term, we anticipate that propane consumers in New York and the greater New England and Mid-Atlantic markets will continue to face significantly higher costs to obtain propane supplies until additional local storage can be installed to help balance out seasonal price dislocations.  Although it has become clear that political agendas are driving the Department of Environmental Conservation’s ongoing delay in permitting the Finger Lakes project, we remain optimistic that these political headwinds will subside later this year and we will place into service the Finger Lakes storage project next year.  We continue to work proactively with industry associations to educate federal, state and local agencies and officials on the market’s need for this critical energy infrastructure and otherwise generate public support for projects like our Finger Lakes project that support growing demand in the local and regional markets.  In this regard, during the second quarter (i) the FERC authorized an expansion of our Seneca Lake natural gas storage facility located at our US Salt complex, which we believe positively supports our permitting efforts, and (ii) the Schuyler County Legislature, which is the appropriations and policy-making body of the project's county, passed a resolution in support of the Finger Lakes NGL storage project on June 9, 2014.

How We Evaluate Our Operations

We evaluate our overall business performance based primarily on EBITDA and Adjusted EBITDA. We evaluate our ability to make distributions to our unitholders based on cash available for distributions.

We do not utilize depreciation, depletion and amortization expense in our key measures because we focus our performance management on cash flow generation and our assets have long useful lives.

EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company's operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. EBITDA is defined as income before income taxes, plus net interest and debt expense, and depreciation, amortization and accretion expense. In addition, Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates for our proportionate share of their depreciation and interest, the impact of certain significant items, such as non-cash equity compensation expenses, gains and impairments of long-lived assets and goodwill, third party costs incurred related to potential and completed acquisitions, loss on contingent consideration, and other transactions identified in a specific reporting period. EBITDA and Adjusted EBITDA are not measures calculated in accordance with 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. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.

See our reconciliation of net income to EBITDA and Adjusted EBITDA in Results of Operations below.

34

Results of Operations

Our consolidated financial statements were originally the financial statements of Legacy Crestwood, prior to the Crestwood Merger and the merger of Legacy Crestwood with and into Legacy Inergy on October 7, 2013 as discussed in Item 1, Financial Statements, Note 2. Financial data presented for the periods ended June 30, 2013 reflect the operations of Legacy Crestwood for the entire period, and the operations of Legacy Inergy from June 19, 2013 to June 30, 2013. The following table summarizes our results of operations for the three and six months endedJune 30, 2014 and 2013 (in millions):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Revenues	$	675.7		$	80.1		$	1,212.7		$	152.5
Costs of product/services sold	519.1			15.3			917.2			28.8
Operations and maintenance expense	32.7			13.4			60.7			26.4
General and administrative expense	21.3			11.0			45.4			18.8
Depreciation, amortization and accretion expense	54.9			20.9			105.7			38.3
Gain on long-lived assets	1.1			—			1.6			—
Loss on contingent consideration	(6.5		)	—			(8.6		)	—
Operating income	42.3			19.5			76.7			40.2
Loss from unconsolidated affiliates, net	(1.5		)	—			(1.6		)	—
Interest and debt expense, net	(29.0		)	(12.5		)	(57.1		)	(23.9		)
Provision for income taxes	(0.1		)	(0.3		)	(0.8		)	(0.7		)
Net income	$	11.7		$	6.7		$	17.2		$	15.6
Add:
Interest and debt expense, net	29.0			12.5			57.1			23.9
Provision for income taxes	0.1			0.3			0.8			0.7
Depreciation, amortization and accretion	54.9			20.9			105.7			38.3
EBITDA	$	95.7		$	40.4		$	180.8		$	78.5
Non-cash equity compensation expense	5.2			1.1			9.8			1.7
Gain on long-lived assets	(1.1		)	—			(1.6		)	—
Loss on contingent consideration	6.5			—			8.6			—
Loss from unconsolidated affiliates, net	1.5			—			1.6			—
Adjusted EBITDA from unconsolidated affiliates	0.4			—			2.1			—
Significant transaction related costs and other items	1.5			4.8			7.3			5.5
Adjusted EBITDA	$	109.7		$	46.3		$	208.6		$	85.7

35

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
EBITDA:
Net cash provided by operating activities	$	37.3		$	34.4		$	95.4		$	68.5
Net changes in operating assets and liabilities	43.0			(4.8		)	50.0			(10.8		)
Amortization of debt-related deferred costs and premiums	(1.8		)	(0.9		)	(3.6		)	(2.0		)
Interest and debt expense, net	29.0			12.5			57.1			23.9
Non-cash equity compensation expense	(5.2		)	(1.1		)	(9.8		)	(1.7		)
Gain on long-lived assets	1.1			—			1.6			—
Loss on contingent consideration	(6.5		)	—			(8.6		)	—
Loss from unconsolidated affiliates, net	(1.5		)	—			(1.6		)	—
Deferred income taxes	—			—			(0.5		)	—
Provision for income taxes	0.1			0.3			0.8			0.7
Other non-cash income	0.2			—			—			(0.1		)
EBITDA	$	95.7		$	40.4		$	180.8		$	78.5
Non-cash equity compensation expense	5.2			1.1			9.8			1.7
Gain on long-lived assets	(1.1		)	—			(1.6		)	—
Loss on contingent consideration	6.5			—			8.6			—
Loss from unconsolidated affiliates, net	1.5			—			1.6			—
Adjusted EBITDA from unconsolidated affiliates	0.4			—			2.1			—
Significant transaction related costs and other items	1.5			4.8			7.3			5.5
Adjusted EBITDA	$	109.7		$	46.3		$	208.6		$	85.7

The following tables summarize the EBITDA of our segments (in millions):

	Three Months Ended								Three Months Ended
	June 30, 2014								June 30, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Gathering and Processing		Storage and Transportation		NGL and Crude Services
Operating revenues	$	83.4		$	45.4	$	546.9		$	71.1	$	5.5	$	3.5
Costs of product/services sold	17.6			3.8		497.7			14.0		0.4		0.9
Operations and maintenance expense	14.7			4.4		13.6			12.6		0.6		0.2
Gain on long-lived assets	0.5			0.6		—			—		—		—
Loss on contingent consideration	(6.5		)	—		—			—		—		—
Loss from unconsolidated affiliates	(0.6		)	—		(0.9		)	—		—		—
EBITDA	$	44.5		$	37.8	$	34.7		$	44.5	$	4.5	$	2.4

36

	Six Months Ended								Six Months Ended
	June 30, 2014								June 30, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Gathering and Processing		Storage and Transportation		NGL and Crude Services
Operating revenues	$	162.9		$	89.7	$	960.1		$	143.5	$	5.5	$	3.5
Costs of product/services sold	36.3			7.0		873.9			27.5		0.4		0.9
Operations and maintenance expense	28.1			8.7		23.9			25.6		0.6		0.2
Gain on long-lived assets	1.0			0.6		—			—		—		—
Loss on contingent consideration	(8.6		)	—		—			—		—		—
Loss from unconsolidated affiliates	(0.3		)	—		(1.3		)	—		—		—
EBITDA	$	90.6		$	74.6	$	61.0		$	90.4	$	4.5	$	2.4

Segment Results

Below is a discussion of the factors that impacted EBITDA by segment for the three and six months endedJune 30, 2014 compared to the same periods in 2013 for our gathering and processing segment and compared to the the three months ended March 31, 2014 for our storage and transportation and NGL and crude services segments (see further discussion below).

Gathering and Processing:

EBITDA for our G&P segment was relatively flat for the three and six months endedJune 30, 2014 compared to the same periods in 2013, although our G&P segment’s revenues increased by $12.3 million (or 17%) and $19.4 million (or 14%) for those same periods. The increases in our G&P revenues were primarily driven by increases in gathering and compression volumes during the three and six months ended June 30, 2014 compared to the same periods in 2013. We gathered approximately 1.2 Bcf/d and 1.1 Bcf/d of natural gas on our G&P systems during the three and six months ended June 30, 2014 compared to 1.0 Bcf/d during the same periods in 2013. Our compression volumes increased from 0.3 Bcf/d for both the three and six months ended June 30, 2013 to 0.5 Bcf/d during the same periods in 2014, which primarily related to several new compressor stations placed in service during 2013 and the first half of 2014 in the Marcellus Shale.

Partially offsetting the increases in our G&P segment’s revenues were higher costs of product/services sold during the three and six months ended June 30, 2014 compared to the same periods in 2013. The increase was primarily due to higher volumes gathered on our New Mexico gathering systems under a gathering and processing agreement we entered into with Legend in April 2014. Operations and maintenance expense in our gathering and processing segment increased approximately $2.1 million and $2.5 million during the three and six months ended June 30, 2014 compared to the same period in 2013 primarily due to the expansion of our assets in the Marcellus Shale.In addition, during the three and six months ended June 30, 2014, we had a $6.5 million and $8.6 million loss on contingent consideration in connection with the acquisition of the Antero assets.

Storage and Transportation:

Our storage and transportation segment results were included in our consolidated results of operations beginning June 19, 2013 (the date that Crestwood Holdings acquired control of our general partner). Accordingly, the following discusses the results of operations of our storage and transportation segment for the three months ended June 30, 2014 compared to the three months ended March 31, 2014.

EBITDA for our storage and transportation segment increased by approximately 2.7% during the three months ended June 30, 2014 compared to the three months ended March 31, 2014. Our storage and transportation revenues increased by 2.5% during the three months ended June 30, 2014 when compared to the three months ended March 31, 2014 primarily due to increased revenues from usage fees on our firm storage and transportation contracts and increased revenues from interruptible services, resulting from increased producer activity and increased locational basis spreads in the Northeast. During the three months ended June 30, 2014, firm throughput on our storage and transportation services was 1.6 Bcf/d compared to 1.4 Bcf/d during the three months ended March 31, 2014.

Costs of product/services sold and operations and maintenance expenses for our storage and transportation segment were relatively flat during the three months ended June 30, 2014 compared to the three months ended March 31, 2014.

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NGL and Crude Services:

Our NGL and crude services segment results were included in our consolidated results of operations beginning June 19, 2013 (the date that Crestwood Holdings acquired control of our general partner). Accordingly, the following discusses the results of operations of our NGL and crude services segment for the three months ended June 30, 2014 compared to the three months ended March 31, 2014.

EBITDA for our NGL and crude services segment increased by approximately 31.9% during the three months ended June 30, 2014 compared to the three months ended March 31, 2014. Our NGL and crude services segment's revenues increased by approximately 32.3% primarily due to increases in volumes on our Arrow system and COLT Hub as a result of our expansion of these facilities and continued improvement of the performance of these assets after the harsh winter conditions experienced in the fourth quarter of 2013 and the first quarter of 2014.

Partially offsetting the increases in our NGL and crude services segment's revenues were higher costs of product/services sold primarily related to higher crude volumes gathered and sold on our Arrow system as discussed above. Our NGL and crude services segment also experienced higher operations and maintenance expenses during the three months ended June 30, 2014 compared to the three months ended March 31, 2014, primarily due to the acquisitions of Red Rock and LT Enterprises.

Other Results

Our consolidated EBITDA for the three and six months endedJune 30, 2014 was $95.7 million and $180.8 million, an increase of $55.3 million and $102.3 million compared to the same periods in 2013. Our consolidated Adjusted EBITDA for the three and six months endedJune 30, 2014 was $109.7 million and $208.6 million, an increase of $63.4 million and $122.9 million compared to the same periods in 2013. Below is a discussion of items impacting our EBITDA that are not included in our segment results described above.

The increase in our EBITDA and Adjusted EBITDA was primarily driven by our segment results described above. Partially offsetting those results were the general and administrative expenses of our Corporate operations, which totaled $21.3 million and $45.4 million for the three and six months ended June 30, 2014, an increase of $10.3 million and $26.6 million compared to the same periods in 2013. The increases in our general and administrative expenses were driven by the assets acquired as a result of the Crestwood Merger and the Arrow Acquisition in 2013. Also contributing to the increase was primarily legal and other consulting expenses we recognized to evaluate certain transaction opportunities primarily related to the Arrow Acquisition, which were approximately $1.5 million and $7.3 million for the three and six months ended June 30, 2014. We also had increases in payroll and related benefit costs, which reflects the increased scope of our business operations, and an increase of $4.1 million and $8.1 million of expenses related to our equity compensation plans during the three and six months ended June 30, 2014 compared to the same periods in 2013.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense - During the three and six months endedJune 30, 2014, our depreciation, amortization and accretion expense increased compared to the same period in 2013 primarily due to the assets acquired as a result of the Crestwood Merger and the Arrow Acquisition during 2013.

Interest and Debt Expense - Interest and debt expense increased for the three and six months endedJune 30, 2014 compared to the same period in 2013, primarily due to (i) higher outstanding balances on our long-term debt, net of repayments; (ii) the assumption of $0.7 billion of long-term debt due to the Crestwood Merger; and (iii) the issuance of $600 million of 6.125% senior notes in November 2013.

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The following table provides a summary of interest and debt expense (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Credit facilities	$	4.9	$	4.5	$	9.0	$	8.9
Senior notes	23.4		8.0		46.9		15.0
Capital lease interest	0.1		0.1		0.1		0.1
Other debt-related costs	2.0		0.1		3.8		0.1
Gross interest and debt expense	30.4		12.7		59.8		24.1
Less: capitalized interest	1.4		0.2		2.7		0.2
Interest and debt expense, net	$	29.0	$	12.5	$	57.1	$	23.9

Liquidity and Sources of Capital

We are a partnership holding company that derives all of our operating cash flow from our operating subsidiaries.  Our principal sources of liquidity include cash generated by operating activities, credit facilities, debt issuances, and sales of our common and preferred units.  Our operating subsidiaries use cash from their respective operations to fund their operating activities and maintenance capital expenditures.  We utilize a variety of sources to service our outstanding indebtedness, fund growth capital expenditures, and make distributions to unitholders.  These sources include funds cash generated by our operating subsidiaries, borrowings under our Credit Facility, funds from the issuance of Preferred Units and funds from the sale of common units under our equity distribution agreement.

• Credit Facility. As of June 30, 2014, we had $366.7 million of available capacity under the Credit Facility considering our most restrictive debt covenants under the facility. In addition, as of June 30, 2014, we were in compliance with all our debt covenants related to our Credit Facility and Senior Notes. See Item 1, Financial Statements, Note 7 for a more detailed description of our Credit Facility.

• Preferred Units. On June 17, 2014, we entered into definitive agreements with a group of investors under which we have agreed to sell and they have agreed to purchase up to $500 million of Preferred Units at a purchase price of $25.10 per unit prior to September 30, 2015. Concurrently with the closing, we sold 11,952,191 Preferred Units to the investors in a privately-placed transaction that generated gross proceeds of approximately $300.0 million (or approximately $293.7 million of net proceeds after transaction fees and offering expenses). We expect to use to the proceeds from the issuance of the Preferred Units to fund expansion and development projects, to reduce borrowings under our Credit Facility, and for other general partnership purposes. We expect to issue an additional $200 million of Preferred Units to the Class A Purchasers prior to September 30, 2015. See Item 1, Financial Statements, Note 8 for a more detailed description of the Preferred Units.

• Equity Distribution Agreement. On July 10, 2014, we entered into an equity distribution agreement with several financial institutions under which we may offer and sell from time to time through one or more managers common units having an aggregate offering price of up to $300.0 million. Common units sold pursuant to this at-the-market equity distribution program will be issued under our ATM registration statement that became effective on May 27, 2014. We will pay the managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under our ATM program, and net proceeds from equity sold under this program will be used to fund expansion and development projects, to finance acquisitions, to reduce borrowings under our Credit Facility, and for other general partnership purposes. We have not issued any common units under this equity distribution program. See Item 1, Financial Statements, Note 8 for more information on our ATM equity distribution program.

We believe our current liquidity sources and operating cash flows will be sufficient to fund our future operating and capital requirements.

39

The following table provides a summary of our cash flows by category (in millions):

	Six Months Ended
	June 30,
	2014			2013
Net cash provided by operating activities	$	95.4		$	68.5
Net cash used in investing activities	(232.8		)	(83.3		)
Net cash provided by financing activities	152.0			17.0

Operating Activities

During the six months endedJune 30, 2014, we experienced an increase in our operating cash flow compared to the same period in 2013 primarily due to additional operating revenues of approximately $1,040.8 million related to the Crestwood Merger and the Arrow Acquisition which occurred in 2013. Partially offsetting these increases in operating revenues was higher operations and maintenance expenses, general and administrative expenses and costs of product/services sold of approximately $938.0 million, which also primarily related to the Crestwood Merger and the Arrow Acquisition in 2013. In addition, our interest costs increased by approximately $33.2 million due to higher outstanding balances on our credit facility.

Investing Activities

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

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

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

We have identified additional growth capital project opportunities for each of our reporting segments. Additional commitments or expenditures will be made at our discretion, and any discontinuation of the construction of these projects will likely result in less future cash flow and earnings. The following table summarizes our capital expenditures for the six months endedJune 30, 2014 (in millions):

Growth capital	$	142.4
Maintenance capital	7.4
Other(1)	14.9
Total	$	164.7

(1)     Represents capital expenditures that are reimbursable by third parties.

During the six months endedJune 30, 2014, we acquired substantially all of the operating assets of Red Rock and LT Enterprises for approximately $12.1 million and $9.0 million, respectively. For a further discussion of these acquisitions, see Item 1, Financial Statements, Note 4. We also made capital contributions of approximately $48.6 million to our unconsolidated affiliates to fund their capital projects. For a further discussion of investment in our unconsolidated affiliates, see Item 1, Financial Statements, Note 5.

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Financing Activities

Significant items impacting our financing activities during the six months endedJune 30, 2014 and 2013, included the following:

Equity Transactions

• $111.5 million increase in distributions to partners during the six months endedJune 30, 2014 compared to the same period in 2013;

• $293.7 million net proceeds from the issuance of Class A Preferred Units in June 2014;

• $33.6 million proceeds from the issuance of preferred security units to GE during the six months ended June 30, 2014; 

• $118.5 million net proceeds from the issuance of Legacy Crestwood common units during the six months endedJune 30, 2013; and

• $129.0 million distribution to Crestwood Holdings for the acquisition of Legacy Crestwood's additional interest in CMM in January 2013.

Debt Transactions

• $90.8 million increase in net repayments of long-term debt during the six months endedJune 30, 2014 compared to the same period in 2013.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Our interest rate risk and commodity price, market and credit risks are discussed in our 2013 Annual Report on Form 10-K and there have been no material changes in those exposures from December 31, 2013 to June 30, 2014.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As of June 30, 2014, we carried out an evaluation under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as to the effectiveness, design and operation of our disclosure controls and procedures (as defined in the Securities Exchange Act of 1934, as amended (Exchange Act) Rules 13a-15(e) and 15d-15(e)). We maintain controls and procedures designed to provide reasonable assurance that information required to be disclosed in our reports that we file or submit under the Exchange Act of 1934, as amended, are recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as appropriate, to allow timely decisions regarding required disclosure. Our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our Chief Executive Officer and Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of June 30, 2014.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) during the six months endedJune 30, 2014 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

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PART II – OTHER INFORMATION

Item 1. Legal Proceedings

Part I, Item 1. Financial Statements, Note 10 to the Consolidated Financial Statements, of this Form 10-Q is hereby incorporated herein by reference.

Item 1A. Risk Factors

This Form 10-Q should be read together with the Item 1A. Risk Factors of our Annual Report on Form 10-K for the year ended December 31, 2013, which describes various risks and uncertainties to which we are or may become subject, and is supplemented by the discussion below.

Our business involves many hazards and risks, some of which may not be fully covered by insurance.

Our operations are subject to many risks inherent in gathering, processing, storage and transportation segments of the energy midstream industry, such as:

• damage to pipelines and plants, related equipment and surrounding properties caused by natural disasters and acts of terrorism;

• subsidence of the geological structures where we store natural gas or NGLs, or storage cavern collapses;

• operator error;

• inadvertent damage from construction, farm and utility equipment;

• leaks, migrations or losses of natural gas, NGLs or crude oil;

• fires and explosions;

• cyber intrusions; and

• other hazards that could also result in personal injury, loss of life, pollution (including environmental pollution) or suspension of operations.

These risks could result in substantial losses due to breaches of contractual commitments, personal injury and/or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage. For example, in early July 2014, we experienced a rupture on our Arrow water gathering system that resulted in a spill of an estimated 25,000 barrels of produced water on the Fort Berthold Indian Reservation in North Dakota, the remediation and repair costs of which we believe are covered by insurance but nonetheless potentially subjects us to substantial penalties, fines and damages from the Three Affiliated Tribes, federal and state regulatory agencies and individual landowners. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are also not insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could result in a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities.

Although we maintain insurance policies with insurers in such amounts and with such coverages and deductibles as we believe are reasonable and prudent, our insurance may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage.

We also share insurance coverage with Crestwood Equity, for which we reimburse Crestwood Equity pursuant to the terms of the omnibus agreement. To the extent Crestwood Equity experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased.

Our Class A Preferred Units contain covenants that may limit our business flexibility.

Our Class A Preferred Units contain covenants preventing us from taking certain actions without the approval of the holders of a majority or a super-majority of the Class A Preferred Units, depending on the action as described below. The need to obtain the approval of holders of the Class A Preferred Units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of our unitholders. The affirmative

42

vote of the then-applicable voting threshold of the outstanding Class A Preferred Units, voting separately as a class with one vote per Class A Preferred Unit, shall be necessary to amend our Partnership Agreement in any manner that (1) alters or changes the rights, powers, privileges or preferences or duties and obligations of the Class A Preferred Units in any material respect, (2) except as contemplated in the Partnership Agreement, increases or decreases the authorized number of Class A Preferred Units, or (3) otherwise adversely affects the Class A Preferred Units, including without limitation the creation (by reclassification or otherwise) of any class of senior securities (or amending the provisions of any existing class of Partnership interests to make such class of partnership interests a class of senior securities). In addition, our Partnership Agreement provides certain rights to the Preferred Unit holders that could impair our ability to consummate (or increase the cost of consummating) a change-in-control transaction, which could result in less economic benefits accruing to our common unitholders.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.4 to Inergy Midstream, L.P.'s Form S-1/A filed on November 21, 2011)
3.1A	Amendment to the Certificate of Limited Partnership of Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.2 to the Partnership’s Form 8-K filed on October 10, 2013)
3.3	First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P., dated December 21, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)
3.3A	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy Midstream, L.P.’s Form 8-K filed on October 1, 2013)
3.3B	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.1 to the Partnership’s Form 8-K filed on October 10, 2013)
3.3C	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP (incorporated herein by reference to Exhibit 3.1 to the Partnership's Form 8-K filed on June 19, 2014)
3.4	Certificate of Formation of NRGM GP, LLC (incorporated herein by reference to Exhibit 3.7 to Inergy Midstream, L.P.'s Form S-1/A filed on November 21, 2011)
3.4A	Certificate of Amendment of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.37 to the Partnership’s Form S-4 filed on October 28, 2013)
3.5	Amended and Restated Limited Liability Company Agreement of NRGM GP, LLC, dated December 21, 2011 (incorporated herein by reference to Exhibit 3.2 to Inergy Midstream, L.P.'s Form 8-K filed on December 22, 2011)
3.5A	Amendment No. 1 to the Amended and Restated Limited Liability Company Agreement of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.39 to the Partnership’s Form S-4 filed on October 28, 2013)
*10.1	Amendment No. 1 dated as of June 11, 2014, to the Credit Agreement dated as of October 7, 2014, among the Partnership, Wells Fargo Bank, as Administrative Agent, and the lender parties thereto
*12.1	Computation of ratio of earnings to fixed charges
*31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
*31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended
*32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
*32.2	Certification of the Chief Financial Officer 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 Document
**101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
**101.LAB	XBRL Taxonomy Extension Label Linkbase Document
**101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
**101.DEF	XBRL Taxonomy Extension Definition Linkbase Document

44

*

Filed herewith

**

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

45

SIGNATURE

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		CRESTWOOD MIDSTREAM PARTNERS LP
		By:	CRESTWOOD MIDSTREAM GP LLC
			(its general partner)
Date:	August 7, 2014	By:	/s/ MICHAEL J. CAMPBELL
			Michael J. Campbell
			Senior Vice President and Chief Financial Officer
			(Duly Authorized Officer and Principal Financial Officer)

46

EX-10.1

Exhibit 10.1

AMENDMENT NO. 1

THIS AMENDMENT NO. 1, dated as of June 11, 2014 (this “Amendment”), to the Credit Agreement, dated as of October 7, 2013 (as the same may be amended, restated, supplemented or otherwise modified from time to time prior to the date hereof, the “Credit Agreement”) by and among CRESTWOOD MIDSTREAM PARTNERS LP (F/K/A INERGY MIDSTREAM, L.P.), a Delaware limited partnership (the “Borrower”), the several banks and other financial institutions or entities from time to time party thereto (the “Lenders”), WELLS FARGO BANK, NATIONAL ASSOCIATION (“Wells Fargo”), as Administrative Agent (the “Administrative Agent”), Swingline Lender and Issuing Bank, and the other parties thereto.

RECITALS:

WHEREAS, pursuant to the Credit Agreement, the Lenders have agreed to make certain loans and other extensions of credit to the Borrower;

WHEREAS, the Borrower has further requested that the Credit Agreement be amended as set forth herein; and

WHEREAS, the Required Lenders are willing to agree to this Amendment on the terms set forth herein.

NOW, THEREFORE, in consideration of the premises and agreements, provisions and covenants herein contained, the parties hereto agree as follows:

SECTION 1.Capitalized Terms. Capitalized terms used but not defined herein shall have the meanings assigned to such terms in the Credit Agreement.

SECTION 2.Amendment of the Credit Agreement. The Credit Agreement shall be amended as of the Amendment Effective Date (as defined below) as set forth below.

(a)Section 5.13(a) of the Credit Agreement is hereby amended by inserting the following parenthetical immediately following the words “all Unrestricted Subsidiaries” appearing in clause (5) of such Section:

“(in the case of any Unrestricted Subsidiary that is not a Wholly Owned Subsidiary, including only a percentage of its total assets corresponding to the percentage of its Equity Interests owned by the Borrower or any Restricted Subsidiary)”

(b)Section 6.05 of the Credit Agreement is hereby amended by (i) deleting the words “the Borrower or” in each place those words appear in the fifth and sixth lines of such Section and (ii) amending and restating the last paragraph of such Section in its entirety as follows:

“Notwithstanding anything to the contrary contained in Section 6.05 above, (i) no sale, transfer or other disposition of assets shall be permitted by this Section 6.05 (other than sales, transfers, leases or other dispositions to Loan Parties pursuant to paragraph (c) hereof) unless such disposition is for fair market value, (ii) no sale, transfer or other disposition of assets shall be permitted by paragraph (a), (d), or (j) of this Section 6.05 unless such disposition is for at least 75%cash consideration and (iii) no sale, transfer or other disposition of assets in excess of $20.0 million shall be permitted by paragraph (g) of this Section 6.05 unless such

disposition is for at least 75% cash consideration; provided that for purposes of clauses (ii) and (iii), the amount of any secured Indebtedness or other Indebtedness of a Subsidiary of the Borrower that is not a Loan Party (as shown on the Borrower’s or such Subsidiary’s most recent balance sheet or in the notes thereto) that is assumed by the transferee of any such assets shall be deemed to be cash.”

(c)Section 6.06 of the Credit Agreement is hereby amended by inserting the following parenthetical immediately following the words “of its Equity Interests” and immediately before the words “or set aside any amount” appearing in the introductory paragraph of such Section:

“(other than redemptions, purchases, retirements and acquisitions of Equity Interests made solely through the issuance of additional shares of Equity Interests of the Person redeeming, purchasing, retiring or acquiring such Equity Interests)”

(d)Section 6.06(d) of the Credit Agreement is hereby amended and restated in its entirety as follows:

“(d) provided no Default or Event of Default then exists or would result therefrom, the Borrower may declare and pay dividends or make other distributions, or directly or indirectly redeem, purchase, retire or otherwise acquire for value its Equity Interests, with the proceeds of any issuance of Equity Interests permitted to be made under this Agreement; and”

SECTION 3.Conditions to Effectiveness. This Amendment shall become effective on the date on which (the “Amendment Effective Date”) the Administrative Agent shall have received a counterpart of this Amendment, executed and delivered by a duly authorized officer of each of (i) the Borrower and (ii) the Required Lenders.

SECTION 4.Representations and Warranties of the Borrower. The Borrower hereby represents and warrants, as of the Amendment Effective Date, as follows:

(a)Each of the representations and warranties contained in Article III of the Credit Agreement and the other Loan Documents is true and correct in all material respects on and as of the Amendment Effective Date as if made on and as of such date except to the extent that such representations and warranties expressly specifically refer to an earlier date (in which case such representations and warranties are true and correct in all material respects as of such earlier date); and

(b)No Default or Event of Default exists after giving effect to this Amendment.

SECTION 5.Effects on Loan Documents.

(a)Except as specifically amended herein, all Loan Documents shall continue to be in full force and effect and are hereby in all respects ratified and confirmed.

(b)The execution, delivery and effectiveness of this Amendment shall not operate as a waiver of any right, power or remedy of any Lender or the Administrative Agent under any of the Loan Documents, nor constitute a waiver of any provision of the Loan Documents.

(c)The Borrower and the other parties hereto acknowledge and agree that this Amendment shall constitute a Loan Document.

SECTION 6.Amendments; Execution in Counterparts.

(a)This Amendment shall not constitute an amendment of any other provision of the Credit Agreement not referred to herein and shall not be construed as a waiver or consent to any further or future action on the part of the Borrower that would require a waiver or consent of the Required Lenders or the Administrative Agent. Except as expressly amended hereby, the provisions of the Credit Agreement are and shall remain in full force and effect.

(b)This Amendment may not be amended nor may any provision hereof be waived except pursuant to a writing signed by the Borrower, the Administrative Agent and the Required Lenders party hereto. This Amendment may be executed by one or more of the parties hereto on any number of separate counterparts, and all of said counterparts taken together shall be deemed to constitute one and the same instrument. Delivery of an executed signature page of this Amendment by facsimile or other electronic submission shall be effective as delivery of a manually executed counterpart hereof.

SECTION 7.GOVERNING LAW; WAIVER OF JURY TRIAL. THIS AMENDMENT SHALL BE CONSTRUED IN ACCORDANCE WITH AND GOVERNED BY THE LAWS OF THE STATE OF NEW YORK. EACH PARTY HERETO HEREBY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY RIGHT IT MAY HAVE TO A TRIAL BY JURY IN RESPECT OF ANY LITIGATION DIRECTLY OR INDIRECTLY ARISING OUT OF, UNDER OR IN CONNECTION WITH THIS AMENDMENT OR ANY OF THE OTHER LOAN DOCUMENTS. EACH PARTY HERETO (i) CERTIFIES THAT NO REPRESENTATIVE, AGENT OR ATTORNEY OF ANY OTHER PARTY HAS REPRESENTED, EXPRESSLY OR OTHERWISE, THAT SUCH OTHER PARTY WOULD NOT, IN THE EVENT OF LITIGATION, SEEK TO ENFORCE THE FOREGOING WAIVER AND (ii) ACKNOWLEDGES THAT IT AND THE OTHER PARTIES HERETO HAVE BEEN INDUCED TO ENTER INTO THIS AMENDMENT AND THE OTHER LOAN DOCUMENTS, AS APPLICABLE, BY, AMONG OTHER THINGS, THE MUTUAL WAIVERS AND CERTIFICATIONS IN THIS SECTION.

[Remainder of page intentionally left blank]

IN WITNESS WHEREOF, each of the undersigned has caused its duly authorized officer to execute and deliver this Amendment as of the date first written above.

[NAME OF REQUIRED LENDER(S)]

By:______________________________

Name:

Title:

Notice Address:

Attention:

Telephone:

Facsimile:

CRESTWOOD MIDSTREAM PARTNERS LP

By: Crestwood Midstream GP LLC, its general partner

By: ______________________________

Name:

Title:

Signature Page to Amendment No. 1

Consented to by:

WELLS FARGO BANK, N.A.,

as Administrative Agent, Swingline Lender,

Issuing Bank and Lender

By: _____________________________

Name:

Title:

Signature Page to Amendment No. 1

EX-12.1

Exhibit 12.1

CRESTWOOD MIDSTREAM PARTNERS LP

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(in millions, except for ratio)

	Three Months Ended June 30,						Six Months Ended June 30,
	2014			2013			2014					2013
Earnings:
Pre-tax income from continuing operations before adjustment for non-controlling interest and equity earnings (including amortization of excess cost of equity investment) per statements of income	$	13.3		$	7.0		$	19.6				$	16.3
Add:
Fixed charges	30.8			13.3			60.7					25.4
Amortized capitalized interest	0.1			—			0.1					—
Less:
Capitalized interest	(1.4		)	(0.2		)	(2.7		)			(0.2		)
Non-controlling interest in pre-tax income of subsidiary with no fixed charges	(3.7		)	—			(6.8		)	(2	)	—
Total earnings available for fixed charges	$	39.1		$	20.1		$	70.9				$	41.5
Fixed charges:
Interest and debt expense	30.4			12.7			59.8					24.1
Interest component of rent	0.4			0.6			0.9					1.3
Total fixed charges	$	30.8		$	13.3		$	60.7				$	25.4
Ratio of earnings to fixed charges(1)	1.3			1.5			1.2					1.6

(1) For purposes of computing the ratio of earnings to fixed charges, "earnings" consists of pretax income from continuing operations before adjustment for non-controlling interest and income from equity investee plus fixed charges (excluding capitalized interest) and amortized capitalized interest. "Fixed charges" represents interest incurred (whether expensed or capitalized), amortization of debt costs and that portion of rental expense on operating leases deemed to be the equivalent of interest.

(2) Dividend requirement of preferred securities issued by our consolidated subsidiary was paid in units and therefore were not considered a fixed charge for purposes of this computation.

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Robert G. Phillips, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Crestwood Midstream Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over the financial reporting (as defined in Exchange Act Rules 13a-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2014

/s/ Robert G. Phillips

Robert G. Phillips

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Michael J. Campbell, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Crestwood Midstream Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over the financial reporting (as defined in Exchange Act Rules 13a-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: August 7, 2014

/s/ Michael J. Campbell      

Michael J. Campbell

Senior Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification of the Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Crestwood Midstream Partners LP (the “Company”) on Form 10-Q for the period ended June 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert G. Phillips, Chief Executive Officer of Crestwood Midstream Partners LP, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Robert G. Phillips
August 7, 2014	Robert G. Phillips Chief Executive Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification of the Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Quarterly Report of Crestwood Midstream Partners LP (the “Company”) on Form 10-Q for the period ended June 30, 2014, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael J. Campbell, Chief Financial Officer of Crestwood Midstream Partners LP, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Michael J. Campbell
August 7, 2014	Michael J. Campbell Chief Financial Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Earnings Per Limited Partner Unit (Schedule of Reconciliation of Earnings Per Share) (Details) (USD $) In Millions, except Share data, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Earnings Per Share [Abstract]
Limited partners’ interest in net income (loss) attributable to CMLP after incentive distributions	$ (0.6)	$ (1.1)	$ (5.7)	$ 2.6
Basic (units)	187,998,000	75,986,000	187,920,000	70,352,000
Incremental Common Shares Attributable to Share-based Payment Arrangements	0	0	0	0
Diluted (units)	187,998,000	75,986,000	187,920,000	70,352,000
Basic, in dollars per unit	$ 0.00	$ (0.01)	$ (0.03)	$ 0.04
Diluted, in dollars per unit	$ 0.00	$ (0.01)	$ (0.03)	$ 0.04

XML

Condensed Consolidating Financial Information (Condensed Consolidating Statement of Operations) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]
Gathering and processing	$ 82.7	$ 46.5	$ 161.3	$ 93.3
Storage and transportation	45.4	5.5	89.7	5.5
NGL and crude services	543.5	3.1	953.4	3.1
Related party (Note 11)	4.1	25.0	8.3	50.6
Revenues	675.7	80.1	1,212.7	152.5
Gathering and processing	7.8	6.2	15.5	12.9
Storage and transportation	3.8	0.4	7.0	0.4
NGL and crude services	497.7	0.9	873.9	0.9
Related party	9.8	7.8	20.8	14.6
Cost of Revenue	519.1	15.3	917.2	28.8
Operations and maintenance	32.7	13.4	60.7	26.4	73.3	43.1	36.3
Operations and maintenance expense	32.7	13.4	60.7	26.4
General and administrative expense	21.3	11.0	45.4	18.8	80.7	29.6	24.1
Depreciation, amortization and accretion	54.9	20.9	105.7	38.3
Costs and Expenses, Total	108.9	45.3	211.8	83.5
Loss on contingent consideration (Note 10)	(6.5)	0	(8.6)	0
Other	1.1		1.6
Operating income	42.3	19.5	76.7	40.2
Interest and debt expense, net	(29.0)	(12.5)	(57.1)	(23.9)
Equity in net income (loss) of subsidiary	0		0
Loss from unconsolidated affiliates, net	(1.5)	0	(1.6)	0
Income before income taxes	11.8	7.0	18.0	16.3
Provision for income taxes	0.1	0.3	0.8	0.7
Net income	11.7	6.7	17.2	15.6
Net income attributable to non-controlling partners	(3.7)	0	(6.8)	0
Net income attributable to Crestwood Midstream Partners LP	8.0	6.7	10.4	15.6
Net income attributable to Class A preferred units	(1.1)	0	(1.1)	0
Net Income (Loss), Partners Interest in Net Income	6.9	6.7	9.3	15.6
Parent
Condensed Financial Statements, Captions [Line Items]
Gathering and processing	0		0
Storage and transportation	0		0
NGL and crude services	0		0
Related party (Note 11)	0		0
Revenues	0		0
Gathering and processing	0		0
Storage and transportation	0		0
NGL and crude services	0		0
Related party	0		0
Cost of Revenue	0		0
Operations and maintenance	0		0
General and administrative expense	(0.9)		(3.0)
Depreciation, amortization and accretion	0.2		0.4
Costs and Expenses, Total	(0.7)		(2.6)
Loss on contingent consideration (Note 10)	0		0
Other	0		0
Operating income	0.7		2.6
Interest and debt expense, net	(29.2)		(57.3)
Equity in net income (loss) of subsidiary	40.2		71.9
Loss from unconsolidated affiliates, net	0		0
Income before income taxes	11.7		17.2
Provision for income taxes	0		0
Net income	11.7		17.2
Net income attributable to non-controlling partners	0		0
Net income attributable to Crestwood Midstream Partners LP	11.7		17.2
Net income attributable to Class A preferred units	(1.1)		(1.1)
Net Income (Loss), Partners Interest in Net Income	10.6		16.1
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Gathering and processing	82.7		161.3
Storage and transportation	45.4		89.7
NGL and crude services	543.5		953.4
Related party (Note 11)	4.1		8.3
Revenues	675.7		1,212.7
Gathering and processing	7.8		15.5
Storage and transportation	3.8		7.0
NGL and crude services	497.7		873.9
Related party	9.8		20.8
Cost of Revenue	519.1		917.2
Operations and maintenance	32.7		60.7
General and administrative expense	22.2		48.4
Depreciation, amortization and accretion	54.7		105.3
Costs and Expenses, Total	109.6		214.4
Loss on contingent consideration (Note 10)	(6.5)		(8.6)
Other	1.1		1.6
Operating income	41.6		74.1
Interest and debt expense, net	0.2		0.2
Equity in net income (loss) of subsidiary	0		0
Loss from unconsolidated affiliates, net	0		0
Income before income taxes	41.8		74.3
Provision for income taxes	0.1		0.8
Net income	41.7		73.5
Net income attributable to non-controlling partners	0		0
Net income attributable to Crestwood Midstream Partners LP	41.7		73.5
Net income attributable to Class A preferred units	0		0
Net Income (Loss), Partners Interest in Net Income	41.7		73.5
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Gathering and processing	0		0
Storage and transportation	0		0
NGL and crude services	0		0
Related party (Note 11)	0		0
Revenues	0		0
Gathering and processing	0		0
Storage and transportation	0		0
NGL and crude services	0		0
Related party	0		0
Cost of Revenue	0		0
Operations and maintenance	0		0
General and administrative expense	0		0
Depreciation, amortization and accretion	0		0
Costs and Expenses, Total	0		0
Loss on contingent consideration (Note 10)	0		0
Other	0		0
Operating income	0		0
Interest and debt expense, net	0		0
Equity in net income (loss) of subsidiary	0		0
Loss from unconsolidated affiliates, net	(1.5)		(1.6)
Income before income taxes	(1.5)		(1.6)
Provision for income taxes	0		0
Net income	(1.5)		(1.6)
Net income attributable to non-controlling partners	(3.7)		(6.8)
Net income attributable to Crestwood Midstream Partners LP	(5.2)		(8.4)
Net income attributable to Class A preferred units	0		0
Net Income (Loss), Partners Interest in Net Income	(5.2)		(8.4)
Consolidation, Eliminations
Condensed Financial Statements, Captions [Line Items]
Gathering and processing	0		0
Storage and transportation	0		0
NGL and crude services	0		0
Related party (Note 11)	0		0
Revenues	0		0
Gathering and processing	0		0
Storage and transportation	0		0
NGL and crude services	0		0
Related party	0		0
Cost of Revenue	0		0
Operations and maintenance	0		0
General and administrative expense	0		0
Depreciation, amortization and accretion	0		0
Costs and Expenses, Total	0		0
Loss on contingent consideration (Note 10)	0		0
Other	0		0
Operating income	0		0
Interest and debt expense, net	0		0
Equity in net income (loss) of subsidiary	(40.2)		(71.9)
Loss from unconsolidated affiliates, net	0		0
Income before income taxes	(40.2)		(71.9)
Provision for income taxes	0		0
Net income	(40.2)		(71.9)
Net income attributable to non-controlling partners	0		0
Net income attributable to Crestwood Midstream Partners LP	(40.2)		(71.9)
Net income attributable to Class A preferred units	0		0
Net Income (Loss), Partners Interest in Net Income	$ (40.2)		$ (71.9)

XML

Commitments and Contingencies (Details) (USD $) In Millions, except Share data, unless otherwise specified			6 Months Ended				1 Months Ended
	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2014 Antero	Dec. 31, 2013 Antero	Sep. 30, 2013 Class Action Challenging Crestwood Merger Lawsuit	Sep. 30, 2013 Class Action Challenging Crestwood Merger - Federal Lawsuit	Mar. 31, 2014 Arrow Acquisition Class Action Lawsuit defendant	Nov. 08, 2013 Arrow Acquisition Class Action Lawsuit people bbl	Jul. 04, 2014 Subsequent event bbl
Schedule Of Commitments And Contingencies [Line Items]
Loss Contingency, Pending Claims, Number					5	4
Barrels of Oil Equivalents Spilled								50,000
Loss Contingency, Loss of Life, Number								47
Loss Contingency, Number of Defendants							53
Loss contingency accrual, less than	$ 0.1	$ 0.1
Site Contingency, Loss Exposure, Release of Produced Water									25,000
Shares Paid for Tax Withholding for Share Based Compensation			40,000,000
Contingent Consideration Classified as Equity, Fair Value Disclosure			$ 40.0	$ 31.4

XML

Condensed Consolidating Financial Information (Condensed Consolidating Statements of Cash Flows) (Details) (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 95.4	$ 68.5
Acquisitions, net of cash acquired	(19.5)	0.2
Purchases of property, plant and equipment	(164.7)	(83.5)
Investment in unconsolidated affiliates	(48.6)	0
Capital contribution from consolidated affiliate	0
Proceeds from sale of assets	0
Net cash used in investing activities	(232.8)	(83.3)
Proceeds from the issuance of long-term debt	860.6	326.7
Principal payments on long-term debt	(863.2)	(238.5)
Distributions paid	(169.2)
Contributions from parent	0
Net proceeds from issuance of preferred equity	33.6
Net proceeds from issuance of Class A preferred units	293.7	0
Payments on capital leases	(1.9)	(2.2)
Taxes paid for unit-based compensation vesting	1.5	0.7
Net change in payables to affiliate	0
Other	(0.1)	0
Net cash provided by financing activities	152.0	17.0
Net change in cash	14.6	2.2
Cash at beginning of period	2.7	0.1
Cash at end of period	17.3	2.3
Parent
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	(16.7)
Acquisitions, net of cash acquired	0
Purchases of property, plant and equipment	(2.3)
Investment in unconsolidated affiliates	0
Capital contribution from consolidated affiliate	(11.2)
Proceeds from sale of assets	(265.5)
Net cash used in investing activities	(279.0)
Proceeds from the issuance of long-term debt	2.5
Principal payments on long-term debt	0
Distributions paid	0
Contributions from parent	0
Net proceeds from issuance of preferred equity	0
Net proceeds from issuance of Class A preferred units	293.7
Payments on capital leases	(0.5)
Taxes paid for unit-based compensation vesting	0
Net change in payables to affiliate	0
Other	0
Net cash provided by financing activities	295.7
Net change in cash	0
Cash at beginning of period	0.1
Cash at end of period	0.1
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	112.1
Acquisitions, net of cash acquired	(19.5)
Purchases of property, plant and equipment	(162.4)
Investment in unconsolidated affiliates	(2.8)
Capital contribution from consolidated affiliate	(2.8)
Proceeds from sale of assets	0
Net cash used in investing activities	(187.5)
Proceeds from the issuance of long-term debt	858.1
Principal payments on long-term debt	(863.2)
Distributions paid	(169.2)
Contributions from parent	2.8
Net proceeds from issuance of preferred equity	0
Net proceeds from issuance of Class A preferred units	0
Payments on capital leases	(1.4)
Taxes paid for unit-based compensation vesting	1.5
Net change in payables to affiliate	265.5
Other	(0.1)
Net cash provided by financing activities	91.0
Net change in cash	15.6
Cash at beginning of period	1.6
Cash at end of period	17.2
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	0
Acquisitions, net of cash acquired	0
Purchases of property, plant and equipment	0
Investment in unconsolidated affiliates	(45.8)
Capital contribution from consolidated affiliate	0
Proceeds from sale of assets	0
Net cash used in investing activities	(45.8)
Proceeds from the issuance of long-term debt	0
Principal payments on long-term debt	0
Distributions paid	0
Contributions from parent	11.2
Net proceeds from issuance of preferred equity	33.6
Net proceeds from issuance of Class A preferred units	0
Payments on capital leases	0
Taxes paid for unit-based compensation vesting	0
Net change in payables to affiliate	0
Other	0
Net cash provided by financing activities	44.8
Net change in cash	(1.0)
Cash at beginning of period	1.0
Cash at end of period	0
Consolidation, Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	0
Acquisitions, net of cash acquired	0
Purchases of property, plant and equipment	0
Investment in unconsolidated affiliates	0
Capital contribution from consolidated affiliate	14.0
Proceeds from sale of assets	265.5
Net cash used in investing activities	279.5
Proceeds from the issuance of long-term debt	0
Principal payments on long-term debt	0
Distributions paid	0
Contributions from parent	(14.0)
Net proceeds from issuance of preferred equity	0
Net proceeds from issuance of Class A preferred units	0
Payments on capital leases	0
Taxes paid for unit-based compensation vesting	0
Net change in payables to affiliate	(265.5)
Other	0
Net cash provided by financing activities	(279.5)
Net change in cash	0
Cash at beginning of period	0
Cash at end of period	$ 0

XML

Long-Term Incentive Plan (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended		6 Months Ended		3 Months Ended	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014 Crestwood LTIP	Jun. 30, 2013 Crestwood LTIP	Jun. 30, 2014 Crestwood LTIP	Jun. 30, 2013 Crestwood LTIP	Jun. 30, 2014 Crestwood LTIP CMLP	Jun. 30, 2013 Crestwood LTIP CMLP	Jun. 30, 2014 Crestwood LTIP CMLP	Jun. 30, 2013 Crestwood LTIP CMLP	Jun. 30, 2014 Crestwood LTIP Restricted units	Jun. 30, 2014 Crestwood LTIP Restricted units	Dec. 31, 2013 Crestwood LTIP Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized											$ 13.3	$ 13.3	$ 1.8
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition					3 years
Unit-based compensation charges	9.8	1.7	3.3	0.9	6.2	1.5
Allocated Share-based Compensation Expense							1.9	0.2	3.6	0.2
Share-based Compensation Arrangement, Equity Instruments Other than Options, Grants in Period, Fair Value											$ 0.8	$ 18.5
Common Stock, Capital Shares Reserved for Future Issuance											6,460,338	6,460,338
Shares Paid for Tax Withholding for Share Based Compensation			61,076	900	68,532	2,429

XML

Certain Balance Sheet Information (Property Plant and Equipment) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	$ 3,749.5	$ 3,565.7
Less: accumulated depreciation and depletion	284.6	215.6
Property, plant and equipment, net	3,464.9	3,350.1
Capital Leased Assets, Gross	3.4	5.0
Gathering systems and pipelines
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	1,250.2	1,231.1
Facilities and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	1,361.9	1,041.0
Buildings, land, rights-of-way, storage contracts and easements
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	780.2	766.2
Vehicles
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	13.7	4.1
Construction in process
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	180.9	360.5
Base gas
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	36.9	36.3
Salt deposits
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	120.5	120.5
Office furniture and fixtures
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	$ 5.2	$ 6.0

XML

Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2014

Debt Disclosure [Abstract]

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

The following table reflects the carrying value and fair value of our senior notes (in millions):

	June 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2019 Senior Notes	$	351.1	$	376.6	$	351.2	$	379.3
2020 Senior Notes	$	504.3	$	532.7	$	504.7	$	513.8
2022 Senior Notes	$	600.0	$	634.5	$	600.0	$	617.3

Schedule of Debt

Long-term debt consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Credit Facility	$	412.3	$	414.9
2019 Senior Notes	350.0		350.0
Premium on 2019 Senior Notes	1.1		1.2
2020 Senior Notes	500.0		500.0
Fair value adjustment of 2020 Senior Notes	4.3		4.7
2022 Senior Notes	600.0		600.0
Other	3.5		—
Total debt	1,871.2		1,870.8
Less: current portion	24.9		2.9
Total long-term debt	$	1,846.3	$	1,867.9

XML

Segments (Narrative) (Details)	3 Months Ended		6 Months Ended	12 Months Ended	3 Months Ended	6 Months Ended	12 Months Ended	3 Months Ended	6 Months Ended			3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended
	Jun. 30, 2014 customer	Jun. 30, 2013 customer	Jun. 30, 2014 segment customer	Dec. 31, 2013 customer	Jun. 30, 2014 Tesoro Refining and Marketing Company [Member] Revenue Customer Concentration Risk [Member]	Jun. 30, 2014 Tesoro Refining and Marketing Company [Member] Revenue Customer Concentration Risk [Member]	Dec. 31, 2013 Tesoro Refining and Marketing Company [Member] Accounts Receivable Customer Concentration Risk [Member]	Jun. 30, 2014 QEP Energy Company [Member] Revenue Customer Concentration Risk [Member]	Jun. 30, 2014 QEP Energy Company [Member] Revenue Customer Concentration Risk [Member]	Jun. 30, 2014 QEP Energy Company [Member] Accounts Receivable Customer Concentration Risk [Member]	Jun. 30, 2014 WPX Williston, LLC [Member] Accounts Receivable Customer Concentration Risk [Member]	Jun. 30, 2013 Quicksilver Revenue	Jun. 30, 2013 Quicksilver Revenue	Jun. 30, 2013 Antero Revenue	Jun. 30, 2013 Antero Revenue	Jun. 30, 2014 Halcon Resources Corp [Member] Accounts Receivable Customer Concentration Risk [Member]
Segment Reporting Information [Line Items]
Number Of Customers Representing Ten Percent Or More Of Consolidated Revenues	2	2
Concentration Risk, Percentage					22.00%	20.00%	19.00%	12.00%	12.00%	14.00%	13.00%	30.00%	32.00%	19.00%	19.00%	18.00%
Number Of Customers Representing Ten Percent Or More Of Consolidated Accounts Receivable			3	1
Number of operating segments			3

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Financial Instruments (Debt) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Total debt	$ 1,871.2	$ 1,870.8
Less: current portion	24.9	2.9
Total long-term debt	1,846.3	1,867.9
Other
Debt Instrument [Line Items]
Senior notes	3.5	0
Senior Notes | 2019 Senior Notes
Debt Instrument [Line Items]
Senior notes	350.0	350.0
Premium on senior notes	1.1	1.2
Senior Notes | 2020 Senior Notes
Debt Instrument [Line Items]
Senior notes	500.0	500.0
Fair value adjustment of senior notes	4.3	4.7
Senior Notes | 2022 Senior Notes
Debt Instrument [Line Items]
Senior notes	600.0	600.0
Revolver | Crestwood Midstream Revolver
Debt Instrument [Line Items]
Outstanding balance on the credit facility	$ 412.3	$ 414.9

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Investments in Unconsolidated Affiliates (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended			3 Months Ended	6 Months Ended		3 Months Ended	6 Months Ended		6 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Jun. 30, 2014 Jackalope Gas Gathering Services, LLC	Jun. 30, 2014 Jackalope Gas Gathering Services, LLC	Dec. 31, 2013 Jackalope Gas Gathering Services, LLC	Jun. 30, 2014 PRBIC	Jun. 30, 2014 PRBIC	Dec. 31, 2013 PRBIC	Jun. 30, 2014 Crestwood Niobrara LLC Jackalope Gas Gathering Services, LLC	Jul. 19, 2013 Crestwood Niobrara LLC Jackalope Gas Gathering Services, LLC	Jun. 30, 2014 Crude Logistics LLC PRBIC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage									50.00%	50.00%			50.00%
Investment in Unconsolidated Affiliate												$ 45.8
Investment in unconsolidated affiliates (Note 5)	198.4		198.4		151.4	172.7	172.7	127.2	25.7	25.7	24.2
Share of Net Earnings In Unconsolidated Affiliate						0.1	1.2
Difference between carrying amount and underlying equity						55.3	55.3
Amortization						0.7	1.5
Investment in unconsolidated affiliates in period			48.6	0										2.8
Loss from unconsolidated affiliates, net	$ (1.5)	$ 0	$ (1.6)	$ 0					$ (0.9)	$ (1.3)

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Segments (Schedule of Reportable Segment Data) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Operating revenues	$ 675.7	$ 80.1	$ 1,212.7	$ 152.5
Costs of product/services sold	519.1	15.3	917.2	28.8
Operations and maintenance expense	32.7	13.4	60.7	26.4
General and administrative expense	21.3	11.0	45.4	18.8	80.7	29.6	24.1
Gain on long-lived assets	1.1	0	1.6	0
Loss on contingent consideration	(6.5)		(8.6)	0
Loss from unconsolidated affiliates, net	(1.5)	0	(1.6)	0
EBITDA	95.7	40.4	180.8	78.5
Goodwill	1,681.4	1,395.8	1,681.4	1,395.8	1,682.8
Total assets	6,635.6	4,921.7	6,635.6	4,921.7	6,401.8
Cash expenditures for property, plant and equipment	97.0	59.2	164.7	83.5
Gathering and Processing
Segment Reporting Information [Line Items]
Operating revenues	83.4	71.1	162.9	143.5
Costs of product/services sold	17.6	14.0	36.3	27.5
Operations and maintenance expense	14.7	12.6	28.1	25.6
General and administrative expense	0	0	0	0
Gain on long-lived assets	0.5		1.0
Loss on contingent consideration	(6.5)		(8.6)
Loss from unconsolidated affiliates, net	(0.6)		(0.3)
EBITDA	44.5	44.5	90.6	90.4
Goodwill	99.6	95.0	99.6	95.0
Total assets	1,980.2	1,652.0	1,980.2	1,652.0
Cash expenditures for property, plant and equipment	79.4	56.0	121.1	79.9
Storage and Transportation
Segment Reporting Information [Line Items]
Operating revenues	45.4	5.5	89.7	5.5
Costs of product/services sold	3.8	0.4	7.0	0.4
Operations and maintenance expense	4.4	0.6	8.7	0.6
General and administrative expense	0	0	0	0
Gain on long-lived assets	0.6		0.6
Loss on contingent consideration	0		0
Loss from unconsolidated affiliates, net	0		0
EBITDA	37.8	4.5	74.6	4.5
Goodwill	726.3	691.7	726.3	691.7
Total assets	1,960.6	1,997.0	1,960.6	1,997.0
Cash expenditures for property, plant and equipment	1.3	2.2	2.5	2.2
NGL and Crude Services
Segment Reporting Information [Line Items]
Operating revenues	546.9	3.5	960.1	3.5
Costs of product/services sold	497.7	0.9	873.9	0.9
Operations and maintenance expense	13.6	0.2	23.9	0.2
General and administrative expense	0	0	0	0
Gain on long-lived assets	0		0
Loss on contingent consideration	0		0
Loss from unconsolidated affiliates, net	(0.9)		(1.3)
EBITDA	34.7	2.4	61.0	2.4
Goodwill	855.5	609.1	855.5	609.1
Total assets	2,536.7	1,232.5	2,536.7	1,232.5
Cash expenditures for property, plant and equipment	13.6	1.0	37.5	1.0
Corporate
Segment Reporting Information [Line Items]
Operating revenues	0	0	0	0
Costs of product/services sold	0	0	0	0
Operations and maintenance expense	0	0	0	0
General and administrative expense	21.3	11.0	45.4	18.8
Gain on long-lived assets	0		0
Loss on contingent consideration	0		0
Loss from unconsolidated affiliates, net	0		0
EBITDA	(21.3)	(11.0)	(45.4)	(18.8)
Goodwill	0	0	0	0
Total assets	158.1	40.2	158.1	40.2
Cash expenditures for property, plant and equipment	$ 2.7	$ 0	$ 3.6	$ 0.4

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Long-Term Incentive Plan (Restricted Unit Activity) (Details) (Crestwood LTIP, Restricted units, USD $)	6 Months Ended
	Jun. 30, 2014
Crestwood LTIP | Restricted units
Units
Unvested - January 1, 2014	250,557
Vested - restricted units	(190,818)
Granted - restricted units	792,034
Forfeited	(41,523)
Unvested - June 30, 2014	810,250
Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	$ 22.13
Vested - restricted units	$ 22.29
Granted - restricted units	$ 23.39
Forfeited	$ 23.58
Unvested - June 30, 2014	$ 23.25

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Certain Balance Sheet Information

6 Months Ended

Jun. 30, 2014

Balance Sheet Related Disclosures [Abstract]

Certain Balance Sheet Information

Certain Balance Sheet Information

Property, Plant and Equipment

Property, plant and equipment consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Gathering systems and pipelines	1,250.2		1,231.1
Facilities and equipment	1,361.9		1,041.0
Buildings, land, rights-of-way, storage contracts and easements	780.2		766.2
Vehicles	13.7		4.1
Construction in process	180.9		360.5
Base gas	36.9		36.3
Salt deposits	120.5		120.5
Office furniture and fixtures	5.2		6.0
	3,749.5		3,565.7
Less: accumulated depreciation and depletion	284.6		215.6
Total property, plant and equipment, net	$	3,464.9	$	3,350.1

Capital Leases. We have a treating facility and certain auto leases which are accounted for as capital leases. Our treating facility lease is reflected in facilities and equipment in the above table. We had capital lease assets of $3.4 million and $5.0 million included in property, plant and equipment, net at June 30, 2014 and December 31, 2013.

Intangible Assets

Intangible assets consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Customer accounts	$	483.2	$	476.4
Covenants not to compete	5.5		3.0
Gas gathering, compression and processing contracts	451.4		451.4
Acquired storage contracts	29.0		29.0
Trademarks	11.0		11.0
Deferred financing and other costs	54.3		54.3
	1,034.4		1,025.1
Less: accumulated amortization	93.9		54.3
Total intangible assets, net	$	940.5	$	970.8

Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Accrued expenses	$	23.3	$	20.0
Accrued property taxes	5.5		7.6
Accrued product purchases payable	0.2		1.6
Tax payable	1.2		10.6
Interest payable	21.7		14.9
Accrued additions to property, plant and equipment	68.7		58.1
Commitments and contingent liabilities (Note 10)	40.0		31.4
Capital leases	1.6		2.6
Deferred revenue	6.5		1.6
Total accrued expenses and other liabilities	$	168.7	$	148.4

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Financial Instruments (Narrative) (Details) (USD $)	6 Months Ended	0 Months Ended	6 Months Ended									3 Months Ended
	Jun. 30, 2014 Crestwood Midstream Revolver	Oct. 07, 2013 Crestwood Midstream Revolver Revolver	Jun. 30, 2014 Crestwood Midstream Revolver Revolver	Dec. 31, 2013 Crestwood Midstream Revolver Revolver	Oct. 07, 2013 Crestwood Midstream Revolver Standby Letters of Credit	Oct. 07, 2013 Crestwood Midstream Revolver Swing Line Loans	Apr. 30, 2011 2019 Senior Notes Senior Notes	Dec. 07, 2012 2020 Senior Notes Senior Notes	Oct. 22, 2013 2022 Senior Notes Senior Notes	Jun. 30, 2014 Minimum [Member] Crestwood Midstream Revolver Revolver	Jun. 30, 2014 Maximum Crestwood Midstream Revolver Revolver	Sep. 30, 2014 Scenario, Forecast Crestwood Midstream Revolver Revolver	Jul. 17, 2014 Subsequent event 2022 Senior Notes Senior Notes
Debt Instrument [Line Items]
Term of debt instrument		5 years
Line of credit, maximum capacity		$ 1,000,000,000			$ 250,000,000	$ 25,000,000
Outstanding balance on the credit facility			412,300,000	414,900,000
Letters of credit outstanding			31,400,000
Remaining borrowing capacity			366,700,000
Line of Credit Facility, Interest Rate at Period End										2.71%	5.00%
Weighted average interest rate			5.73%
Maximum leverage ratio			5.0
Maximum leverage ratio, certain periods post acquisition			5.50									5.00
Minimum interest coverage ratio			2.50
Current debt to EBITDA ratio	4.56
Consolidated EBITDA to interest expense ratio	3.69
Face amount of debt							$ 350,000,000	$ 500,000,000	$ 600,000,000				$ 600,000,000
Interest rate on debt							7.75%	6.00%	6.125%				6.125%

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Segments (Tables)

6 Months Ended

Jun. 30, 2014

Segment Reporting [Abstract]

Reportable Segments

The following table is a reconciliation of net income to EBITDA (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Net income	$	11.7	$	6.7	$	17.2	$	15.6
Add:
Interest and debt expense, net	29.0		12.5		57.1		23.9
Provision for income taxes	0.1		0.3		0.8		0.7
Depreciation, amortization and accretion	54.9		20.9		105.7		38.3
EBITDA	$	95.7	$	40.4	$	180.8	$	78.5

The following tables summarize the reportable segment data for the three and six months endedJune 30, 2014 and 2013 (in millions).

	Three Months Ended June 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Operating revenues	$	83.4		$	45.4	$	546.9		$	—		$	675.7
Costs of product/services sold	17.6			3.8		497.7			—			519.1
Operations and maintenance expense	14.7			4.4		13.6			—			32.7
General and administrative expense	—			—		—			21.3			21.3
Gain on long-lived assets	0.5			0.6		—			—			1.1
Loss on contingent consideration	(6.5		)	—		—			—			(6.5		)
Loss from unconsolidated affiliates, net	(0.6		)	—		(0.9		)	—			(1.5		)
EBITDA	$	44.5		$	37.8	$	34.7		$	(21.3	)	$	95.7
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	1,980.2		$	1,960.6	$	2,536.7		$	158.1		$	6,635.6
Cash expenditures for property, plant and equipment	$	79.4		$	1.3	$	13.6		$	2.7		$	97.0

	Three Months Ended June 30, 2013
	Gathering and Processing		Storage and Transportation		NGL and Crude Services		Corporate			Total
Operating revenues	$	71.1	$	5.5	$	3.5	$	—		$	80.1
Costs of product/services sold	14.0		0.4		0.9		—			15.3
Operations and maintenance expense	12.6		0.6		0.2		—			13.4
General and administrative expense	—		—		—		11.0			11.0
EBITDA	$	44.5	$	4.5	$	2.4	$	(11.0	)	$	40.4
Goodwill	$	95.0	$	691.7	$	609.1	$	—		$	1,395.8
Total assets	$	1,652.0	$	1,997.0	$	1,232.5	$	40.2		$	4,921.7
Cash expenditures for property, plant and equipment	$	56.0	$	2.2	$	1.0	$	—		$	59.2

	Six Months Ended June 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Operating revenues	$	162.9		$	89.7	$	960.1		$	—		$	1,212.7
Costs of product/services sold	36.3			7.0		873.9			—			917.2
Operations and maintenance expense	28.1			8.7		23.9			—			60.7
General and administrative expense	—			—		—			45.4			45.4
Gain on long-lived assets	1.0			0.6		—			—			1.6
Loss on contingent consideration	(8.6		)	—		—			—			(8.6		)
Loss from unconsolidated affiliates, net	(0.3		)	—		(1.3		)	—			(1.6		)
EBITDA	$	90.6		$	74.6	$	61.0		$	(45.4	)	$	180.8
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	1,980.2		$	1,960.6	$	2,536.7		$	158.1		$	6,635.6
Cash expenditures for property, plant and equipment	$	121.1		$	2.5	$	37.5		$	3.6		$	164.7

	Six Months Ended June 30, 2013
	Gathering and Processing		Storage and Transportation		NGL and Crude Services		Corporate			Total
Operating revenues	$	143.5	$	5.5	$	3.5	$	—		$	152.5
Costs of product/services sold	27.5		0.4		0.9		—			28.8
Operations and maintenance expense	25.6		0.6		0.2		—			26.4
General and administrative expense	—		—		—		18.8			18.8
EBITDA	$	90.4	$	4.5	$	2.4	$	(18.8	)	$	78.5
Goodwill	$	95.0	$	691.7	$	609.1	$	—		$	1,395.8
Total assets	$	1,652.0	$	1,997.0	$	1,232.5	$	40.2		$	4,921.7
Cash expenditures for property, plant and equipment	$	79.9	$	2.2	$	1.0	$	0.4		$	83.5

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Related Party Transactions (Tables)

6 Months Ended

Jun. 30, 2014

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following table shows revenues, costs of goods sold and general and administrative expenses from our affiliates for the three and six months endedJune 30, 2014 and 2013 (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014(a)		2013		2014(a)		2013
Gathering and processing revenues	$	0.7	$	24.6	$	1.6	$	50.2
NGL and crude services revenues	$	3.4	$	0.4	$	6.7	$	0.4
Gathering and processing costs of goods sold	$	9.8	$	7.8	$	20.8	$	14.6
General and administrative expenses	$	4.5	$	5.3	$	8.3	$	10.6

(a) Concurrent with the Crestwood Merger, Quicksilver Resources Inc. (Quicksilver) is no longer a related party, and as a result our transactions with Quicksilver subsequent to June 19, 2013, are now considered non-affiliated transactions.

Schedule of Related Party Receivables and Payables

The following table shows accounts receivable and accounts payable from our affiliates as of June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Accounts receivable	$	7.2	$	1.1
Accounts payable	$	13.8	$	8.7

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Partners' Capital (Narrative) (Details) (USD $)	0 Months Ended									3 Months Ended		6 Months Ended			0 Months Ended						0 Months Ended	6 Months Ended	3 Months Ended		0 Months Ended	3 Months Ended	6 Months Ended		0 Months Ended	6 Months Ended	0 Months Ended		6 Months Ended	0 Months Ended	3 Months Ended
	May 15, 2014	May 08, 2014	Feb. 14, 2014	Feb. 07, 2014	May 10, 2013	Apr. 30, 2013	Feb. 12, 2013	Jan. 31, 2013	Jan. 08, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jan. 08, 2013	Jan. 08, 2013 Legacy Crestwood Credit Facility	Jun. 17, 2014 Preferred Units, Class A [Member]	Jan. 08, 2013 Preferred Units, Class D	Jan. 08, 2013 General Partner	Jul. 10, 2014 Subsequent event	Jul. 10, 2014 Subsequent event	Jul. 18, 2014 Subsequent event Common Unit	Jun. 30, 2014 Legacy Crestwood	Jun. 30, 2014 Crestwood Niobrara LLC Preferred Units, Class D	Mar. 31, 2014 Crestwood Niobrara LLC Preferred Units, Class D	Jul. 30, 2014 Crestwood Niobrara LLC Subsequent event Preferred Units, Class D	Jun. 30, 2014 Jackalope Gas Gathering Services, LLC	Jun. 30, 2014 Jackalope Gas Gathering Services, LLC	Jun. 30, 2014 Jackalope Gas Gathering Services, LLC Preferred Units	Jul. 19, 2013 Jackalope Gas Gathering Services, LLC Crestwood Niobrara LLC	Jun. 30, 2014 Jackalope Gas Gathering Services, LLC Crestwood Niobrara LLC Preferred Units	Jun. 17, 2014 Preferred Partner	Jun. 30, 2014 Preferred Partner	Jun. 30, 2014 Preferred Partner Preferred Units, Class A [Member]	Jun. 17, 2014 Class A Purchasers Maximum Preferred Units, Class A [Member]	Sep. 30, 2014 Scenario, Forecast Preferred Units
Distribution Made to Limited Partner [Line Items]
Partners' Capital Account, Units, Sale of Units																11,952,191					26,299,076
Issuance of Class A preferred units																			$ 300,000,000															$ 500,000,000
Offering Costs, Partnership Interests																				0.020
Maximum Period For Distribution Of Available Cash												45 days
Incentive Distribution, Distribution										7,500,000	7,700,000	15,000,000	12,700,000									20,900,000
Distribution Made to General Partner, Cash Distributions Paid												20,900,000	9,300,000
Distribution Made to Limited Partner, Date of Record		May 08, 2014		Feb. 07, 2014		Apr. 30, 2013		Jan. 31, 2013
Per unit rate, in dollars per unit	$ 0.41		$ 0.41		$ 0.51		$ 0.51
Contribution from issuance of units																												129,700,000		33,600,000
Net Income (Loss) Attributable to Noncontrolling Interest										3,700,000	0	6,800,000	0													3,700,000	6,800,000
Percent of Contributions to be Funded by Units																													75.00%
Funds from Capital Contributions, Maximum																													20,300,000
Distribution Made to Member or Limited Partner, Cash Distributions Paid	74,200,000		74,100,000		27,400,000		21,000,000				48,400,000	148,300,000	48,400,000
Business Acquisition, Percentage of Voting Interests Acquired														65.00%
Consideration Transferred									258,000,000						129,000,000
Distribution Made to Limited Partner, Unit Distribution																	6,190,469	133,060					2,536,010	2,210,294	3,073,357										42,523
Distribution Made to Limited Partner, Distribution Date	May 15, 2014		Feb. 14, 2014		May 10, 2013		Feb. 12, 2013
Partners' Capital, Distribution Amount Per Share																																$ 0.5804
Partners' Capital Account, Term to Convert Cash Distributions to Stock Distributions																																	36 months
Partners' Capital Account, Private Placement of Units																$ 25.10															$ 25.10
Proceeds from Issuance of Preferred Limited Partners Units, Gross																300,000,000
Net proceeds from issuance of Class A preferred units												$ 293,700,000	$ 0			$ 293,700,000
Partners' Capital, Contingent Distribution Amount Per Share																																$ 0.7059
Partner's Capital, Unpaid Distribution, Accrual Percentage																															2.8125%

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Condensed Consolidating Financial Information (Tables)

6 Months Ended

Jun. 30, 2014

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Consolidating Balance Sheet

Condensed Consolidating Balance Sheet
June 30, 2014
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	0.1	$	17.2		$	—	$	—		$	17.3
Accounts receivable	576.5		279.0			0.1		(565.2		)	290.4
Inventories	—		7.6			—		—			7.6
Other current assets	—		13.9			—		—			13.9
Total current assets	576.6		317.7			0.1		(565.2		)	329.2
Property, plant and equipment, net	5.8		3,459.1			—		—			3,464.9
Goodwill and intangible assets, net	—		2,621.9			—		—			2,621.9
Investment in consolidated affiliates	6,496.4		—			—		(6,496.4		)	—
Investment in unconsolidated affiliates	—		—			198.4		—			198.4
Other assets	—		21.2			—		—			21.2
Total assets	$	7,078.8	$	6,419.9		$	198.5	$	(7,061.6	)	$	6,635.6
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	833.0	$	(73.3	)	$	0.1	$	(565.2	)	$	194.6
Other current liabilities	26.2		167.4			—		—			193.6
Total current liabilities	859.2		94.1			0.1		(565.2		)	388.2
Long-term liabilities:
Long-term debt, less current portion	1,846.3		—			—		—			1,846.3
Other long-term liabilities	1.6		27.8			—		—			29.4
Total long-term liabilities	1,847.9		27.8			—		—			1,875.7
Partners' capital	4,230.3		6,298.0			57.0		(6,355.0		)	4,230.3
Interest of non-controlling partners in subsidiaries	141.4		—			141.4		(141.4		)	141.4
Total partners' capital	4,371.7		6,298.0			198.4		(6,496.4		)	4,371.7
Total liabilities and partners' capital	$	7,078.8	$	6,419.9		$	198.5	$	(7,061.6	)	$	6,635.6

Condensed Consolidating Balance Sheet
December 31, 2013
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	0.1	$	1.6		$	1.0	$	—		$	2.7
Accounts receivable	466.8		197.8			0.2		(459.7		)	205.1
Inventories	—		7.0			—		—			7.0
Other current assets	—		10.2			—		—			10.2
Total current assets	466.9		216.6			1.2		(459.7		)	225.0
Property, plant and equipment, net	4.8		3,345.3			—		—			3,350.1
Goodwill and intangible assets, net	—		2,653.6			—		—			2,653.6
Investment in consolidated affiliates	6,385.2		—			—		(6,385.2		)	—
Investment in unconsolidated affiliates	—		—			151.4		—			151.4
Other assets	—		21.7			—		—			21.7
Total assets	$	6,856.9	$	6,237.2		$	152.6	$	(6,844.9	)	$	6,401.8
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	782.7	$	(159.8	)	$	—	$	(459.7	)	$	163.2
Other current liabilities	11.5		139.6			0.2		—			151.3
Total current liabilities	794.2		(20.2		)	0.2		(459.7		)	314.5
Long-term liabilities:
Long-term debt, less current portion	1,867.9		—			—		—			1,867.9
Other long-term liabilities	1.7		24.6			—		—			26.3
Total long-term liabilities	1,869.6		24.6			—		—			1,894.2
Partners' capital	4,092.1		6,232.8			51.4		(6,284.2		)	4,092.1
Interest of non-controlling partners in subsidiaries	101.0		—			101.0		(101.0		)	101.0
Total partners' capital	4,193.1		6,232.8			152.4		(6,385.2		)	4,193.1
Total liabilities and partners' capital	$	6,856.9	$	6,237.2		$	152.6	$	(6,844.9	)	$	6,401.8

Consolidating Statements of Operations

Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	82.7		$	—		$	—		$	82.7
Storage and transportation	—			45.4			—			—			45.4
NGL and crude services	—			543.5			—			—			543.5
Related party	—			4.1			—			—			4.1
	—			675.7			—			—			675.7
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			7.8			—			—			7.8
Storage and transportation	—			3.8			—			—			3.8
NGL and crude services	—			497.7			—			—			497.7
Related party	—			9.8			—			—			9.8
	—			519.1			—			—			519.1
Expenses:
Operations and maintenance	—			32.7			—			—			32.7
General and administrative	(0.9		)	22.2			—			—			21.3
Depreciation, amortization and accretion	0.2			54.7			—			—			54.9
	(0.7		)	109.6			—			—			108.9
Other operating income (expense):
Loss on contingent consideration	—			(6.5		)	—			—			(6.5		)
Other	—			1.1			—			—			1.1
Operating income	0.7			41.6			—			—			42.3
Interest and debt expense, net	(29.2		)	0.2			—			—			(29.0		)
Equity in net income (loss) of subsidiary	40.2			—			—			(40.2		)	—
Other	—			—			(1.5		)	—			(1.5		)
Income (loss) before income taxes	11.7			41.8			(1.5		)	(40.2		)	11.8
Provision for income taxes	—			0.1			—			—			0.1
Net income (loss)	11.7			41.7			(1.5		)	(40.2		)	11.7
Net income attributable to non-controlling partners	—			—			(3.7		)	—			(3.7		)
Net income (loss) attributable to Crestwood Midstream Partners LP	11.7			41.7			(5.2		)	(40.2		)	8.0
Net income attributable to Class A preferred units	(1.1		)	—			—			—			(1.1		)
Net income (loss) attributable to partners	10.6			41.7			(5.2		)	(40.2		)	6.9

Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	161.3		$	—		$	—		$	161.3
Storage and transportation	—			89.7			—			—			89.7
NGL and crude services	—			953.4			—			—			953.4
Related party	—			8.3			—			—			8.3
	—			1,212.7			—			—			1,212.7
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			15.5			—			—			15.5
Storage and transportation	—			7.0			—			—			7.0
NGL and crude services	—			873.9			—			—			873.9
Related party	—			20.8			—			—			20.8
	—			917.2			—			—			917.2
Expenses:
Operations and maintenance	—			60.7			—			—			60.7
General and administrative	(3.0		)	48.4			—			—			45.4
Depreciation, amortization and accretion	0.4			105.3			—			—			105.7
	(2.6		)	214.4			—			—			211.8
Other operating income (expense):
Loss on contingent consideration	—			(8.6		)	—			—			(8.6		)
Other	—			1.6			—			—			1.6
Operating income	2.6			74.1			—			—			76.7
Interest and debt expense, net	(57.3		)	0.2			—			—			(57.1		)
Equity in net income (loss) of subsidiary	71.9			—			—			(71.9		)	—
Other	—			—			(1.6		)	—			(1.6		)
Income (loss) before income taxes	17.2			74.3			(1.6		)	(71.9		)	18.0
Provision for income taxes	—			0.8			—			—			0.8
Net income (loss)	17.2			73.5			(1.6		)	(71.9		)	17.2
Net (income) attributable to non-controlling partners	—			—			(6.8		)	—			(6.8		)
Net income (loss) attributable to Crestwood Midstream Partners LP	17.2			73.5			(8.4		)	(71.9		)	10.4
Net income attributable to Class A preferred units	(1.1		)	—			—			—			(1.1		)
Net income (loss) attributable to partners	16.1			73.5			(8.4		)	(71.9		)	9.3

Consolidating Statement of Cash Flows

Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(16.7	)	$	112.1		$	—		$	—		$	95.4
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(19.5		)	—			—			(19.5		)
Purchases of property, plant and equipment	(2.3		)	(162.4		)	—			—			(164.7		)
Investment in unconsolidated affiliates, net	—			(2.8		)	(45.8		)	—			(48.6		)
Capital contribution from consolidated affiliates	(11.2		)	(2.8		)	—			14.0			—
Other	(265.5		)	—			—			265.5			—
Net cash provided by (used in) investing activities	(279.0		)	(187.5		)	(45.8		)	279.5			(232.8		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2.5			858.1			—			—			860.6
Principal payments on long-term debt	—			(863.2		)	—			—			(863.2		)
Distributions paid	—			(169.2		)	—			—			(169.2		)
Contributions from parent	—			2.8			11.2			(14.0		)	—
Net proceeds from issuance of preferred equity	—			—			33.6			—			33.6
Net proceeds from issuance of Class A preferred units	293.7			—			—			—			293.7
Payments on capital leases	(0.5		)	(1.4		)	—			—			(1.9		)
Taxes paid for unit-based compensation vesting	—			(1.5		)	—			—			(1.5		)
Net change in payables to affiliates	—			265.5			—			(265.5		)	—
Other	—			(0.1		)	—			—			(0.1		)
Net cash provided by (used in) financing activities	295.7			91.0			44.8			(279.5		)	152.0
Net increase in cash	—			15.6			(1.0		)	—			14.6
Cash at beginning of period	0.1			1.6			1.0			—			2.7
Cash at end of period	$	0.1		$	17.2		$	—		$	—		$	17.3

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Business Description (Details) (USD $)	6 Months Ended		9 Months Ended			6 Months Ended
	Jun. 30, 2014 segment	Jun. 30, 2014 CEQP	Jun. 30, 2013 Parent	Jun. 30, 2013 First Reserve	Jun. 30, 2013 Distribution Rights	Jun. 30, 2014 Distribution Rights CEQP
Partnership Organization And Basis Of Presentation [Line Items]
Limited Liability Company (LLC) or Limited Partnership (LP), Managing Member or General Partner, Ownership Interest		4.00%
Percentage of distribution entitled to receive			50.00%	11.00%		100.00%
Distribution declared per limited partner unit					$ 0.37
Number of operating segments	3

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Basis of Presentation and Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2014

Accounting Policies [Abstract]

Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements were originally the financial statements of Legacy Crestwood, prior to the Crestwood Merger and the merger of Legacy Crestwood with and into Legacy Inergy on October 7, 2013 as discussed above. Crestwood Holdings acquisition of control of CEQP’s general partner on June 19, 2013 was accounted for as a reverse acquisition under the purchase method of accounting in accordance with accounting standards for business combinations.  CEQP’s accounting for this reverse acquisition resulted in the legal acquiree (Crestwood Gas Services GP LLC) being the acquirer for accounting purposes.  CEQP’s accounting acquiree (inclusive of Legacy Inergy) was subject to the purchase method of accounting and its balance sheet was adjusted to fair market value as of June 19, 2013.  Accordingly, the merger of Legacy Crestwood and Legacy Inergy on October 7, 2013 was accounted for as a reverse merger amongst entities under common control.  Although Legacy Crestwood was the surviving entity for accounting purposes, Legacy Inergy was the surviving entity for legal purposes, and consequently we changed our name from Inergy Midstream, L.P. to Crestwood Midstream Partners LP. As the reverse merger was amongst entities under common control, the financial statements have been recasted to reflect the operations of Legacy Inergy as being acquired by Legacy Crestwood on June 19, 2013, the date in which Legacy Inergy and Legacy Crestwood came under common control.  

The financial information as of June 30, 2014, and for the three-month and six-month periods endedJune 30, 2014 and 2013, is unaudited. The consolidated balance sheet as of December 31, 2013, was derived from the audited balance sheet filed in our 2013 Annual Report on Form 10-K. Our consolidated financial statements are prepared in accordance with US GAAP and include the accounts of all consolidated subsidiaries after the elimination of all intercompany accounts and transactions. In management’s opinion, all necessary adjustments to fairly present our results of operations, financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and recurring nature. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the SEC.

Beginning in the first quarter of 2014, we began reflecting our operating and administrative expenses as operations and maintenance expenses and general and administrative expenses. In addition, we also reclassified our consolidated statements of operations for the three and six months endedJune 30, 2013 to reflect this change. This change had no impact on our previously reported net income, earnings per unit or partners' capital. The financial statements in our 2013 Annual Report on Form 10-K have not been recast to reflect this change. The following table summarizes the reclassification of the amounts previously reported in operating and administrative expenses for the periods presented (in millions):

	Year Ended December 31,
	2013		2012		2011
Operating and administrative expenses as previously reported	$	154.0	$	72.7	$	60.4
Operations and maintenance expenses	73.3		43.1		36.3
General and administrative expenses	80.7		29.6		24.1

In addition to the reclassification described above, our consolidated financial statements for prior periods include reclassifications that were made to conform to the current period presentation. None of our reclassifications had an impact on our previously reported net income, earnings per unit or partners' capital.

The accompanying consolidated financial statements should be read in conjunction with our 2013 Annual Report on Form 10-K filed with the Securities and Exchange Commission (SEC) on February 28, 2014.

Significant Accounting Policies

There were no material changes in our significant accounting policies from those described in our 2013 Annual Report on Form 10-K and no significant accounting pronouncements issued but not yet adopted as of June 30, 2014.

New Accounting Pronouncement Issued But Not Yet Adopted

As of June 30, 2014, the following accounting standard has not yet been adopted by us.

In May 2014, the Financial Accounting Standards Board issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes most current revenue recognition guidance. We will adopt the provisions of this standard effective January 1, 2017 and present the retroactive application of this standard to our revenue for the quarterly and annual periods ended 2015 and 2016.  We are currently evaluating the impact that this standard will have on our financial statements.

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Basis of Presentation and Summary of Significant Accounting Policies (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating and administrative expenses as previously reported	$ 32.7	$ 13.4	$ 60.7	$ 26.4
Operations and maintenance expenses	32.7	13.4	60.7	26.4	73.3	43.1	36.3
General and administrative expense	21.3	11.0	45.4	18.8	80.7	29.6	24.1
Scenario, Previously Reported [Member]
Operating and administrative expenses as previously reported					$ 154.0	$ 72.7	$ 60.4

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Earnings Per Limited Partner Unit (Narrative) (Details)	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended	3 Months Ended	6 Months Ended
	Jun. 30, 2013	Jun. 30, 2013	Jun. 30, 2014 Crestwood Niobrara LLC	Jun. 30, 2014 Crestwood Niobrara LLC	Jun. 30, 2014 Preferred Units	Jun. 30, 2014 Preferred Units	Jun. 30, 2014 Distribution Rights CEQP
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Percentage of distribution entitled to receive							100.00%
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	0	0	6,070,354	5,549,570	1,838,799	924,479

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Condensed Consolidating Financial Information (Condensed Consolidating Balance Sheet) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013	Jun. 30, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	$ 17.3	$ 2.7	$ 2.3	$ 0.1
Accounts receivable	290.4	205.1
Inventory	7.6	7.0
Prepaid expenses and other current assets	13.9	10.2
Total current assets	329.2	225.0
Property, plant and equipment, net	3,464.9	3,350.1
Goodwill and intangible assets, net	2,621.9	2,653.6
Investment in Consolidated Subsidiaries	0	0
Investment in unconsolidated affiliates (Note 5)	198.4	151.4
Other assets	21.2	21.7
Total assets	6,635.6	6,401.8	4,921.7
Accounts payable	194.6	163.2
Other current liabilities	193.6	151.3
Total current liabilities	388.2	314.5
Long-term debt, less current portion	1,846.3	1,867.9
Other long-term liabilities	29.4	26.3
Total long-term liabilities	1,875.7	1,894.2
Partners' Capital	4,230.3	4,092.1
Interest of non-controlling partners in subsidiary	141.4	101.0
Total partners’ capital	4,371.7	4,193.1
Total liabilities and partners’ capital	6,635.6	6,401.8
Parent
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	0.1	0.1
Accounts receivable	576.5	466.8
Inventory	0	0
Prepaid expenses and other current assets	0	0
Total current assets	576.6	466.9
Property, plant and equipment, net	5.8	4.8
Goodwill and intangible assets, net	0	0
Investment in Consolidated Subsidiaries	6,496.4	6,385.2
Investment in unconsolidated affiliates (Note 5)	0	0
Other assets	0	0
Total assets	7,078.8	6,856.9
Accounts payable	833.0	782.7
Other current liabilities	26.2	11.5
Total current liabilities	859.2	794.2
Long-term debt, less current portion	1,846.3	1,867.9
Other long-term liabilities	1.6	1.7
Total long-term liabilities	1,847.9	1,869.6
Partners' Capital	4,230.3	4,092.1
Interest of non-controlling partners in subsidiary	141.4	101.0
Total partners’ capital	4,371.7	4,193.1
Total liabilities and partners’ capital	7,078.8	6,856.9
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	17.2	1.6
Accounts receivable	279.0	197.8
Inventory	7.6	7.0
Prepaid expenses and other current assets	13.9	10.2
Total current assets	317.7	216.6
Property, plant and equipment, net	3,459.1	3,345.3
Goodwill and intangible assets, net	2,621.9	2,653.6
Investment in Consolidated Subsidiaries	0	0
Investment in unconsolidated affiliates (Note 5)	0	0
Other assets	21.2	21.7
Total assets	6,419.9	6,237.2
Accounts payable	(73.3)	(159.8)
Other current liabilities	167.4	139.6
Total current liabilities	94.1	(20.2)
Long-term debt, less current portion	0	0
Other long-term liabilities	27.8	24.6
Total long-term liabilities	27.8	24.6
Partners' Capital	6,298.0	6,232.8
Interest of non-controlling partners in subsidiary	0	0
Total partners’ capital	6,298.0	6,232.8
Total liabilities and partners’ capital	6,419.9	6,237.2
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	0	1.0
Accounts receivable	0.1	0.2
Inventory	0	0
Prepaid expenses and other current assets	0	0
Total current assets	0.1	1.2
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Investment in Consolidated Subsidiaries	0	0
Investment in unconsolidated affiliates (Note 5)	198.4	151.4
Other assets	0	0
Total assets	198.5	152.6
Accounts payable	0.1	0
Other current liabilities	0	0.2
Total current liabilities	0.1	0.2
Long-term debt, less current portion	0	0
Other long-term liabilities	0	0
Total long-term liabilities	0	0
Partners' Capital	57.0	51.4
Interest of non-controlling partners in subsidiary	141.4	101.0
Total partners’ capital	198.4	152.4
Total liabilities and partners’ capital	198.5	152.6
Consolidation, Eliminations
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	0	0
Accounts receivable	(565.2)	(459.7)
Inventory	0	0
Prepaid expenses and other current assets	0	0
Total current assets	(565.2)	(459.7)
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Investment in Consolidated Subsidiaries	(6,496.4)	(6,385.2)
Investment in unconsolidated affiliates (Note 5)	0	0
Other assets	0	0
Total assets	(7,061.6)	(6,844.9)
Accounts payable	(565.2)	(459.7)
Other current liabilities	0	0
Total current liabilities	(565.2)	(459.7)
Long-term debt, less current portion	0	0
Other long-term liabilities	0	0
Total long-term liabilities	0	0
Partners' Capital	(6,355.0)	(6,284.2)
Interest of non-controlling partners in subsidiary	(141.4)	(101.0)
Total partners’ capital	(6,496.4)	(6,385.2)
Total liabilities and partners’ capital	(7,061.6)	(6,844.9)
Consolidated Entities [Member]
Condensed Financial Statements, Captions [Line Items]
Total liabilities and partners’ capital		$ 6,401.8

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CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 17.3	$ 2.7
Accounts receivable	290.4	205.1
Inventory	7.6	7.0
Prepaid expenses and other current assets	13.9	10.2
Total current assets	329.2	225.0
Property, plant and equipment (Note 3)	3,749.5	3,565.7
Less: accumulated depreciation and depletion	284.6	215.6
Property, plant and equipment, net	3,464.9	3,350.1
Intangible assets:
Intangible assets (Note 3)	1,034.4	1,025.1
Less: accumulated amortization	93.9	54.3
Intangible assets, net	940.5	970.8
Goodwill	1,681.4	1,682.8
Investment in unconsolidated affiliates (Note 5)	198.4	151.4
Other assets	21.2	21.7
Total assets	6,635.6	6,401.8
Current liabilities:
Accounts payable	180.8	154.5
Accounts payable - related party (Note 11)	13.8	8.7
Accrued expenses and other liabilities	168.7	148.4
Current portion of long-term debt (Note 7)	24.9	2.9
Total current liabilities	388.2	314.5
Long-term debt, less current portion (Note 7)	1,846.3	1,867.9
Other long-term liabilities	29.4	26.3
Commitments and contingencies (Note 10)
Partners’ capital (Note 8):
Class A preferred units (11,952,191 units issued and outstanding at June 30, 2014)	294.8	0
Partners’ capital (187,925,968 and 187,243,989 limited partner units issued and outstanding at June 30, 2014 and December 31, 2013)	3,935.5	4,092.1
Total Crestwood Midstream Partners LP partners’ capital	4,230.3	4,092.1
Interest of non-controlling partners in subsidiary	141.4	101.0
Total partners’ capital	4,371.7	4,193.1
Total liabilities and partners’ capital	$ 6,635.6	$ 6,401.8

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Partners' Capital (Schedule of Partnership Distributions) (Details) (USD $)	0 Months Ended								3 Months Ended		6 Months Ended		0 Months Ended	6 Months Ended
	May 15, 2014	May 08, 2014	Feb. 14, 2014	Feb. 07, 2014	May 10, 2013	Apr. 30, 2013	Feb. 12, 2013	Jan. 31, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Jul. 23, 2014 Dividend Paid Cash distribution Subsequent event	Jun. 30, 2014 Legacy Crestwood
Limited Partners' Capital Account [Line Items]
Distribution Made to Limited Partner, Date of Record		May 08, 2014		Feb. 07, 2014		Apr. 30, 2013		Jan. 31, 2013
Distribution Made to Limited Partner, Distribution Date	May 15, 2014		Feb. 14, 2014		May 10, 2013		Feb. 12, 2013
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.41		$ 0.41		$ 0.51		$ 0.51
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 74,200,000		$ 74,100,000		$ 27,400,000		$ 21,000,000			$ 48,400,000	$ 148,300,000	$ 48,400,000
Disclosure Partners Capital Summary Of Quarterly Distributions Of Available Cash [Abstract]
Incentive Distribution, Distribution									$ 7,500,000	$ 7,700,000	$ 15,000,000	$ 12,700,000		$ 20,900,000
Distribution declared per limited partner unit													$ 0.41

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $) In Millions, unless otherwise specified	6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013
Operating activities
Net income	$ 17.2	$ 15.6
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion	105.7	38.3
Amortization of debt-related deferred costs and premiums	3.6	2.0
Unit-based compensation charges	9.8	1.7
Gain on long-lived assets	(1.6)	0
Loss on contingent consideration	8.6	0
Loss from unconsolidated affiliates, net	1.6	0
Deferred income taxes	0.5	0
Other	0	0.1
Changes in operating assets and liabilities, net of effects from acquisitions	(50.0)	10.8
Net cash provided by operating activities	95.4	68.5
Investing activities
Acquisitions, net of cash acquired (Note 4)	(19.5)	0.2
Purchases of property, plant and equipment	(164.7)	(83.5)
Investment in unconsolidated affiliates	(48.6)	0
Net cash used in investing activities	(232.8)	(83.3)
Financing activities
Proceeds from the issuance of long-term debt	860.6	326.7
Principal payments on long-term debt	(863.2)	(238.5)
Payments on capital leases	(1.9)	(2.2)
Payments for debt related deferred costs	0	(0.1)
Distributions to limited partners	(148.3)	(48.4)
Distributions to general partner	(20.9)	(9.3)
Distributions for additional interest in Crestwood Marcellus Midstream LLC	0	(129.0)
Net proceeds from issuance of Class A preferred units	293.7	0
Taxes paid for unit-based compensation vesting	(1.5)	(0.7)
Other	(0.1)	0
Net cash provided by financing activities	152.0	17.0
Net change in cash	14.6	2.2
Cash at beginning of period	2.7	0.1
Cash at end of period	17.3	2.3
Supplemental schedule of non-cash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	14.7	25.5
Preferred Units, Class A [Member]
Financing activities
Net proceeds from issuance of limited partner units	0	118.5
Preferred Stock [Member]
Financing activities
Net proceeds from issuance of limited partner units	$ 33.6	$ 0

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Certain Balance Sheet Information (Accrued Expenses and Other Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Payables and Accruals [Abstract]
Accrued expenses	$ 23.3	$ 20.0
Accrued property taxes	5.5	7.6
Accrued product purchases payable	0.2	1.6
Tax payable	1.2	10.6
Interest payable	21.7	14.9
Accrued additions to property, plant and equipment	68.7	58.1
Commitments and contingent liabilities (Note 10)	40.0	31.4
Capital leases	1.6	2.6
Deferred revenue	6.5	1.6
Total accrued expenses and other liabilities	$ 168.7	$ 148.4

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Certain Balance Sheet Information (Tables)

6 Months Ended

Jun. 30, 2014

Balance Sheet Related Disclosures [Abstract]

Components of Property, Plant and Equipment

Property, plant and equipment consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Gathering systems and pipelines	1,250.2		1,231.1
Facilities and equipment	1,361.9		1,041.0
Buildings, land, rights-of-way, storage contracts and easements	780.2		766.2
Vehicles	13.7		4.1
Construction in process	180.9		360.5
Base gas	36.9		36.3
Salt deposits	120.5		120.5
Office furniture and fixtures	5.2		6.0
	3,749.5		3,565.7
Less: accumulated depreciation and depletion	284.6		215.6
Total property, plant and equipment, net	$	3,464.9	$	3,350.1

Components of Intangible Assets

Intangible assets consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Customer accounts	$	483.2	$	476.4
Covenants not to compete	5.5		3.0
Gas gathering, compression and processing contracts	451.4		451.4
Acquired storage contracts	29.0		29.0
Trademarks	11.0		11.0
Deferred financing and other costs	54.3		54.3
	1,034.4		1,025.1
Less: accumulated amortization	93.9		54.3
Total intangible assets, net	$	940.5	$	970.8

Components of Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Accrued expenses	$	23.3	$	20.0
Accrued property taxes	5.5		7.6
Accrued product purchases payable	0.2		1.6
Tax payable	1.2		10.6
Interest payable	21.7		14.9
Accrued additions to property, plant and equipment	68.7		58.1
Commitments and contingent liabilities (Note 10)	40.0		31.4
Capital leases	1.6		2.6
Deferred revenue	6.5		1.6
Total accrued expenses and other liabilities	$	168.7	$	148.4

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Acquisitions (Details) (USD $)	0 Months Ended	3 Months Ended		6 Months Ended			3 Months Ended		6 Months Ended		0 Months Ended					0 Months Ended		0 Months Ended	6 Months Ended	3 Months Ended		6 Months Ended			3 Months Ended		6 Months Ended
	Jan. 08, 2013	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013	Dec. 31, 2013	Jun. 30, 2013 Arrow Midstream Holdings, LLC and Inergy Midstream [Member]		Jun. 30, 2013 Arrow Midstream Holdings, LLC and Inergy Midstream [Member]		Mar. 21, 2014 Red Rock Transportation, Inc tractor bbl double_bottom_body_tanks trailer_tanks	May 09, 2014 LT Enterprises [Member]	May 09, 2014 LT Enterprises [Member] crude_trailer	May 09, 2014 LT Enterprises [Member] service_vehicles acre bbl	May 09, 2014 LT Enterprises [Member] tractor	Jun. 30, 2013 Inergy Midstream	Jun. 19, 2013 Inergy Midstream	Nov. 08, 2013 Arrow Midstream Holdings, LLC	Jun. 30, 2014 Arrow Midstream Holdings, LLC	Jun. 30, 2014 NGL and Crude Services Operations	Jun. 30, 2013 NGL and Crude Services Operations	Jun. 30, 2014 NGL and Crude Services Operations	Jun. 30, 2013 NGL and Crude Services Operations	Jun. 19, 2013 NGL and Crude Services Operations Inergy Midstream	Jun. 30, 2014 Storage and Transportation	Jun. 30, 2013 Storage and Transportation	Jun. 30, 2014 Storage and Transportation	Jun. 30, 2013 Storage and Transportation	Jun. 30, 2014 Storage and Transportation Inergy Midstream
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net [Abstract]
Consideration Transferred	$ 258,000,000										$ 13,800,000	$ 10,700,000						$ 750,000,000
Cost of Acquired Entity, Cash Paid											12,100,000	9,000,000						550,000,000
Cost of Acquired Entity, Liabilities Incurred											1,700,000	1,700,000
Trailer Tanks, Number											56		51	17	38
Crude Hauling Capacity											28,000		20,000	20,000	20,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Assets [Abstract]
Current assets																	49,100,000	192,700,000
Property, plant and equipment											10,600,000						1,677,800,000	400,500,000
Intangible assets																	196,000,000	323,400,000
Other assets																	2,900,000	19,500,000
Total identifiable assets acquired																	1,925,800,000	936,100,000
Current liabilities																	30,900,000	215,800,000
Long-term debt																	745,000,000
Asset Retirement Obligation																		1,200,000
Other long-term liabilities																	5,300,000	3,700,000
Total liabilities assumed																	781,200,000	220,700,000
Net identifiable assets acquired																	1,144,600,000	715,400,000
Goodwill		1,681,400,000	1,395,800,000	1,681,400,000	1,395,800,000	1,682,800,000					3,200,000						1,532,700,000	45,900,000		855,500,000	609,100,000	855,500,000	609,100,000	806,400,000	726,300,000	691,700,000	726,300,000	691,700,000	726,300,000
Net assets acquired																	2,677,300,000	761,300,000
Business Combination, Consideration Transferred, Other																		11,300,000
Cost of Acquired Entity, Cash Paid											12,100,000	9,000,000						550,000,000
Incentive Distribution, Distribution		7,500,000	7,700,000	15,000,000	12,700,000													8,826,125
Business Acquisition, Pro Forma Information [Abstract]
Revenue							500,900,000		925,600,000
Net income							4,500,000		17,600,000
Basic (usd per unit)							$ (0.02)	[1]	$ 0.03	[1]
Diluted (usd per unit)							$ (0.02)	[1]	$ 0.03	[1]
Business Combination, Acquisition Related Costs																			5,200,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Land, Area													20	20	20
Revenues		675,700,000	80,100,000	1,212,700,000	152,500,000											9,000,000				546,900,000	3,500,000	960,100,000	3,500,000		45,400,000	5,500,000	89,700,000	5,500,000
Net income		$ 11,700,000	$ 6,700,000	$ 17,200,000	$ 15,600,000											$ 1,800,000

[1] Basic and diluted net income per limited partner unit for the three and six months ended June 30, 2013 were computed based on the number of Legacy Inergy common units outstanding plus the number of common units issued by Legacy Inergy to Legacy Crestwood unitholders as part of the Crestwood Merger and the number of units issued in conjunction with the Arrow Acquisition.

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Earnings Per Limited Partner Unit (Tables)

6 Months Ended

Jun. 30, 2014

Earnings Per Share [Abstract]

Schedule of Other Nonoperating Income (Expense)

The tables below show the (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 six months endedJune 30, 2014 and 2013 (in millions):

Allocation of Net Income Attributable to CMLP to General Partner and Limited Partners
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Net income attributable to CMLP	$	8.0		$	6.7		$	10.4		$	15.6
Class A preferred units interest in net income attributable to CMLP	(1.1		)	—			(1.1		)	—
General partner’s incentive distributions	(7.5		)	(7.7		)	(15.0		)	(12.7		)
General partner’s interest in net income attributable to CMLP	—			(0.1		)	—			(0.3		)
Limited partners’ interest in net income (loss) attributable to CMLP	$	(0.6	)	$	(1.1	)	$	(5.7	)	$	2.6

Schedule of Earnings Per Share Reconciliation

Earnings Per Limited Partner Unit
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Limited partners’ interest in net income (loss)	$	(0.6	)	$	(1.1	)	$	(5.7	)	$	2.6
Weighted-average limited partner units - basic	188.0			76.0			187.9			70.4
Effect of diluted units	—			—			—			—
Weighted-average limited partner units - diluted	188.0			76.0			187.9			70.4
Basic earnings per unit:
Net income (loss) per limited partner	$	—		$	(0.01	)	$	(0.03	)	$	0.04
Diluted earnings per unit:
Net income (loss) per limited partner	$	—		$	(0.01	)	$	(0.03	)	$	0.04

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Business Description

6 Months Ended

Jun. 30, 2014

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Business Description

Business Description

Crestwood Midstream Partners LP (the Company or Crestwood) is a publicly-traded (NYSE: CMLP) Delaware limited partnership that provides midstream solutions to customers in the crude oil, natural gas liquids (NGLs) and natural gas sectors of the energy industry. We are engaged primarily in the gathering, processing, storage and transportation of natural gas and NGLs and the gathering, storage and transportation of crude oil.

As of June 30, 2014, our general partner, Crestwood Equity Partners LP (CEQP), owns our non-economic general partnership interest, approximately 4% of our common units representing limited partnership interests and 100% of our incentive distribution rights (IDRs), which entitle CEQP to receive 50% of all distributions paid to our common unit holders in excess of our initial quarterly distributions of $0.37 per common unit. CEQP is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve) and which owns approximately 11% of our common units as of June 30, 2014.

Our financial statements reflect three operating and reporting segments, including:

• Gathering and Processing: our gathering and processing (G&P) operations provide natural gas gathering, processing, treating, compression, transportation services and sales of natural gas and the delivery of NGLs to producers in unconventional shale plays and tight-gas plays in West Virginia, Wyoming, Texas, Arkansas, New Mexico and Louisiana. This segment primarily includes our rich gas gathering systems and processing plants in the Marcellus, Powder River Basin (PRB) Niobrara, Barnett, and Permian Shale plays, and our dry gas gathering systems in the Barnett, Fayetteville, and Haynesville Shale plays;

• Storage and Transportation: our storage and transportation operations provide regulated natural gas storage and transportation services to producers, utilities and other customers. This segment primarily includes our natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake) and natural gas transmission facilities (the North-South Facilities, the MARC I Pipeline and the East Pipeline) in New York and Pennsylvania; and

• NGL and Crude Services: our NGL and crude services operations provide gathering, storage and transportation services to producers, refiners, marketers and other customers in or near unconventional shale plays in North Dakota and New York. This segment primarily includes our integrated Bakken crude oil footprint in North Dakota, which consists of (i) the COLT Hub, a crude oil rail loading and storage terminal, (ii) the Arrow crude oil, natural gas and water gathering systems, and (iii) our fleet of over-the-road crude and produced water transportation assets. This segment also includes our Bath storage facility, an NGL underground storage facility in New York, and US Salt, a solution-mining and salt production company in New York.

On October 7, 2013, we changed our name from Inergy Midstream, L.P. to Crestwood Midstream Partners LP. Unless otherwise indicated, references in this report to “we,” “us,” “our,” “ours,” “our company,” the “partnership,” the “Company,” “CMLP,” “Crestwood” and similar terms refer to either Crestwood Midstream Partners LP itself or Crestwood Midstream Partners LP and its consolidated subsidiaries, as the context requires. Unless otherwise indicated, references to (i) the Crestwood Merger refers to the October 7, 2013 merger of the Company’s wholly-owned subsidiary with and into Legacy Crestwood, with Legacy Inergy continuing as the surviving legal entity; (ii) Legacy Crestwood refers to either Crestwood Midstream Partners LP itself or Crestwood Midstream Partners LP and its consolidated subsidiaries prior to the Crestwood Merger; and (iii) Legacy Inergy refers to either Inergy Midstream, L.P. itself or Inergy Midstream, L.P. and its consolidated subsidiaries prior to the Crestwood Merger. See Note 4 for additional information on the Crestwood Merger.

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CONSOLIDATED BALANCE SHEETS (Parenthetical)	Jun. 30, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Preferred units, issued	11,952,191
Preferred units, outstanding	11,952,191
Common units, issued	187,925,968	187,243,989
Common units, outstanding	187,925,968	187,243,989

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Related Party Transactions

6 Months Ended

Jun. 30, 2014

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

We do not have any employees. We share common management, operating and administrative and overhead costs with CEQP. We have an Omnibus Agreement with CEQP that requires us to reimburse CEQP for all shared costs incurred on our behalf, except for certain unit based compensation costs which are treated as capital transactions. CEQP allocated to us $12.9 million and $28.7 million of costs for the three and six months endedJune 30, 2014. Included in this amount was $1.9 million and $3.6 million of net unit-based compensation charges for the three and six months endedJune 30, 2014. During the three and six months endedJune 30, 2013, CEQP allocated to us $0.5 million of costs, including $0.2 million of net unit-based compensation charges. Due to the nature of these shared costs, it is not practicable to estimate what the costs would have been on a stand-alone basis. Accordingly, the accompanying financial statements may not necessarily be indicative of the conditions that would have existed, or the results of operations that would have occurred, if we operated as a stand-alone entity.

The following table shows revenues, costs of goods sold and general and administrative expenses from our affiliates for the three and six months endedJune 30, 2014 and 2013 (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014(a)		2013		2014(a)		2013
Gathering and processing revenues	$	0.7	$	24.6	$	1.6	$	50.2
NGL and crude services revenues	$	3.4	$	0.4	$	6.7	$	0.4
Gathering and processing costs of goods sold	$	9.8	$	7.8	$	20.8	$	14.6
General and administrative expenses	$	4.5	$	5.3	$	8.3	$	10.6

(a) Concurrent with the Crestwood Merger, Quicksilver Resources Inc. (Quicksilver) is no longer a related party, and as a result our transactions with Quicksilver subsequent to June 19, 2013, are now considered non-affiliated transactions.

The following table shows accounts receivable and accounts payable from our affiliates as of June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Accounts receivable	$	7.2	$	1.1
Accounts payable	$	13.8	$	8.7

For additional information regarding our related party transactions, see our 2013 Annual Report on Form 10-K as filed with the SEC.

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Document and Entity Information	6 Months Ended
	Jun. 30, 2014
Document and Entity Information [Abstract]
Entity Registrant Name	Crestwood Midstream Partners LP
Trading Symbol	CMLP
Entity Central Index Key	0001304464
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding	0

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Segments

6 Months Ended

Jun. 30, 2014

Segment Reporting [Abstract]

Segments

Segments

Financial Information

We have three operating and reporting segments; (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) NGL and crude services operations. Our gathering and processing operations engage in the gathering, processing, treating, compression, transportation and sales of natural gas and the delivery of NGLs. Our storage and transportation operations provide regulated natural gas storage and transportations services to producers, utilities and other customers. Our NGL and crude services operations provide gathering, storage and transportation services to producers, refiners, marketers, and other customers that effectively provide flow assurances to our customers, as well as the production and sale of salt products. Our corporate operations include all general and administrative expenses that are not allocated to the reportable segments. We assess the performance of our operating segments based on EBITDA, which represents operating income plus depreciation, amortization and accretion expense.

The following table is a reconciliation of net income to EBITDA (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2014		2013		2014		2013
Net income	$	11.7	$	6.7	$	17.2	$	15.6
Add:
Interest and debt expense, net	29.0		12.5		57.1		23.9
Provision for income taxes	0.1		0.3		0.8		0.7
Depreciation, amortization and accretion	54.9		20.9		105.7		38.3
EBITDA	$	95.7	$	40.4	$	180.8	$	78.5

The following tables summarize the reportable segment data for the three and six months endedJune 30, 2014 and 2013 (in millions).

	Three Months Ended June 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Operating revenues	$	83.4		$	45.4	$	546.9		$	—		$	675.7
Costs of product/services sold	17.6			3.8		497.7			—			519.1
Operations and maintenance expense	14.7			4.4		13.6			—			32.7
General and administrative expense	—			—		—			21.3			21.3
Gain on long-lived assets	0.5			0.6		—			—			1.1
Loss on contingent consideration	(6.5		)	—		—			—			(6.5		)
Loss from unconsolidated affiliates, net	(0.6		)	—		(0.9		)	—			(1.5		)
EBITDA	$	44.5		$	37.8	$	34.7		$	(21.3	)	$	95.7
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	1,980.2		$	1,960.6	$	2,536.7		$	158.1		$	6,635.6
Cash expenditures for property, plant and equipment	$	79.4		$	1.3	$	13.6		$	2.7		$	97.0

	Three Months Ended June 30, 2013
	Gathering and Processing		Storage and Transportation		NGL and Crude Services		Corporate			Total
Operating revenues	$	71.1	$	5.5	$	3.5	$	—		$	80.1
Costs of product/services sold	14.0		0.4		0.9		—			15.3
Operations and maintenance expense	12.6		0.6		0.2		—			13.4
General and administrative expense	—		—		—		11.0			11.0
EBITDA	$	44.5	$	4.5	$	2.4	$	(11.0	)	$	40.4
Goodwill	$	95.0	$	691.7	$	609.1	$	—		$	1,395.8
Total assets	$	1,652.0	$	1,997.0	$	1,232.5	$	40.2		$	4,921.7
Cash expenditures for property, plant and equipment	$	56.0	$	2.2	$	1.0	$	—		$	59.2

	Six Months Ended June 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Operating revenues	$	162.9		$	89.7	$	960.1		$	—		$	1,212.7
Costs of product/services sold	36.3			7.0		873.9			—			917.2
Operations and maintenance expense	28.1			8.7		23.9			—			60.7
General and administrative expense	—			—		—			45.4			45.4
Gain on long-lived assets	1.0			0.6		—			—			1.6
Loss on contingent consideration	(8.6		)	—		—			—			(8.6		)
Loss from unconsolidated affiliates, net	(0.3		)	—		(1.3		)	—			(1.6		)
EBITDA	$	90.6		$	74.6	$	61.0		$	(45.4	)	$	180.8
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	1,980.2		$	1,960.6	$	2,536.7		$	158.1		$	6,635.6
Cash expenditures for property, plant and equipment	$	121.1		$	2.5	$	37.5		$	3.6		$	164.7

	Six Months Ended June 30, 2013
	Gathering and Processing		Storage and Transportation		NGL and Crude Services		Corporate			Total
Operating revenues	$	143.5	$	5.5	$	3.5	$	—		$	152.5
Costs of product/services sold	27.5		0.4		0.9		—			28.8
Operations and maintenance expense	25.6		0.6		0.2		—			26.4
General and administrative expense	—		—		—		18.8			18.8
EBITDA	$	90.4	$	4.5	$	2.4	$	(18.8	)	$	78.5
Goodwill	$	95.0	$	691.7	$	609.1	$	—		$	1,395.8
Total assets	$	1,652.0	$	1,997.0	$	1,232.5	$	40.2		$	4,921.7
Cash expenditures for property, plant and equipment	$	79.9	$	2.2	$	1.0	$	0.4		$	83.5

Major Customers

Two customers, Tesoro Refining & Marketing Company (Tesoro) (22%) and QEP Energy Company (QEP) (12%) accounted for 10% or more of our total consolidated revenues for the three months ended June 30, 2014. Tesoro (20%) and QEP (12%) also accounted for 10% or more of our total consolidated revenues for the six months endedJune 30, 2014. These customers' revenues are reflected in the NGL and crude services segment. Two customers, Quicksilver (30%) and Antero Resources Appalachian Corporation (Antero) (19%), accounted for 10% or more of our total consolidated revenues for the three months ended June 30, 2013. Quicksilver (32%) and Antero (19%), also accounted for 10% or more of our total consolidated revenues for the six months endedJune 30, 2013. These customers' revenues are reflected in the gathering and processing segment.

Three customers, QEP (14%), Halcon Resources Corp. (Halcon) (18%) and WPX (13%), accounted for 10% or more of our consolidated accounts receivable at June 30, 2014. One customer, Tesoro, accounted for approximately 19% of our consolidated accounts receivable at December 31, 2013. These customers' accounts receivable are reflected in the NGL and crude services segment.

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Revenues:
Gathering and processing	$ 82.7	$ 46.5	$ 161.3	$ 93.3
Storage and transportation	45.4	5.5	89.7	5.5
NGL and crude services	543.5	3.1	953.4	3.1
Related party (Note 11)	4.1	25.0	8.3	50.6
Revenues	675.7	80.1	1,212.7	152.5
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	7.8	6.2	15.5	12.9
Storage and transportation	3.8	0.4	7.0	0.4
NGL and crude services	497.7	0.9	873.9	0.9
Related party (Note 11)	9.8	7.8	20.8	14.6
Cost of Revenue	519.1	15.3	917.2	28.8
Expenses:
Operations and maintenance	32.7	13.4	60.7	26.4
General and administrative	21.3	11.0	45.4	18.8
Depreciation, amortization and accretion	54.9	20.9	105.7	38.3
Costs and Expenses, Total	108.9	45.3	211.8	83.5
Other operating income (expense):
Gain on long-lived assets	1.1	0	1.6	0
Loss on contingent consideration (Note 10)	(6.5)	0	(8.6)	0
Operating income	42.3	19.5	76.7	40.2
Loss from unconsolidated affiliates, net	(1.5)	0	(1.6)	0
Interest and debt expense, net	(29.0)	(12.5)	(57.1)	(23.9)
Income before income taxes	11.8	7.0	18.0	16.3
Provision for income taxes	0.1	0.3	0.8	0.7
Net income	11.7	6.7	17.2	15.6
Net income attributable to non-controlling partners	(3.7)	0	(6.8)	0
Net income attributable to Crestwood Midstream Partners LP	8.0	6.7	10.4	15.6
Net income attributable to Class A preferred units	(1.1)	0	(1.1)	0
Net income attributable to partners	6.9	6.7	9.3	15.6
Partners’ interest information:
General partner's interest in net income	7.5	7.8	15.0	13.0
Limited partners’ interest in net income (loss)	$ (0.6)	$ (1.1)	$ (5.7)	$ 2.6
Net income (loss) per limited partner unit:
Basic (usd per unit)	$ 0.00	$ (0.01)	$ (0.03)	$ 0.04
Diluted (usd per unit)	$ 0.00	$ (0.01)	$ (0.03)	$ 0.04
Weighted-average limited partners’ units outstanding:
Basic (units)	187,998	75,986	187,920	70,352
Diluted (units)	187,998	75,986	187,920	70,352

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Earnings Per Limited Partner Unit Earnings Per Limited Partner Unit

6 Months Ended

Jun. 30, 2014

Earnings Per Share [Abstract]

Earnings Per Limited Partner Unit

Earnings Per Limited Partner Unit

Prior to the Crestwood Merger, net income attributable to Legacy Crestwood was allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after giving effect to incentive distributions earned by the general partner. To the extent cash distributions exceeded net income attributable to Legacy Crestwood, the excess distributions were allocated proportionately to all participating units outstanding based on their respective ownership percentages. As a result of the Crestwood Merger, CEQP, which owns our general partner, owns a non-economic general partner interest in us and 100% of our IDRs. We allocate net income attributable to CMLP to our limited partners after giving effect to the IDRs earned by CEQP and net income attributable to the Class A preferred units.

Basic earnings per unit are calculated using the two-class method. 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 as discussed below. The weighted average number of units outstanding is calculated based on the presumption that the number of common units issued by Legacy Inergy to Legacy Crestwood unitholders as part of the Crestwood Merger were outstanding for the entire period prior to Crestwood Merger.

The tables below show the (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 six months endedJune 30, 2014 and 2013 (in millions):

Allocation of Net Income Attributable to CMLP to General Partner and Limited Partners
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Net income attributable to CMLP	$	8.0		$	6.7		$	10.4		$	15.6
Class A preferred units interest in net income attributable to CMLP	(1.1		)	—			(1.1		)	—
General partner’s incentive distributions	(7.5		)	(7.7		)	(15.0		)	(12.7		)
General partner’s interest in net income attributable to CMLP	—			(0.1		)	—			(0.3		)
Limited partners’ interest in net income (loss) attributable to CMLP	$	(0.6	)	$	(1.1	)	$	(5.7	)	$	2.6

Earnings Per Limited Partner Unit
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2014			2013			2014			2013
Limited partners’ interest in net income (loss)	$	(0.6	)	$	(1.1	)	$	(5.7	)	$	2.6
Weighted-average limited partner units - basic	188.0			76.0			187.9			70.4
Effect of diluted units	—			—			—			—
Weighted-average limited partner units - diluted	188.0			76.0			187.9			70.4
Basic earnings per unit:
Net income (loss) per limited partner	$	—		$	(0.01	)	$	(0.03	)	$	0.04
Diluted earnings per unit:
Net income (loss) per limited partner	$	—		$	(0.01	)	$	(0.03	)	$	0.04

We exclude potentially dilutive securities from the determination of diluted earnings per unit (as well as their related income statement impacts) when their impact on net income attributable to CMLP per limited partner unit is anti-dilutive. During the three and six months endedJune 30, 2014, we excluded a weighted-average of 6,070,354 and 5,549,570 common units, representing Crestwood Niobrara's preferred units if converted to common units, from our diluted earnings per unit. During the three and six months endedJune 30, 2014, we also excluded a weighted-average of 1,838,799 and 924,479 common units, representing Class A preferred units if converted to common units, from our diluted earnings per unit. There were no units excluded from our dilutive earnings per unit as we did not have any anti-dilutive units for the three and six months endedJune 30, 2013. See Note 8 for additional information regarding the potential conversion of the preferred units to common units.

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Investments in Unconsolidated Affiliates (Notes)

6 Months Ended

Jun. 30, 2014

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

Investments in Unconsolidated Affiliates

Jackalope Gas Gathering Services, L.L.C.

Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, owns a 50% ownership interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) which we account for under the equity method of accounting. During the six months endedJune 30, 2014, Crestwood Niobrara contributed $45.8 million to Jackalope to fund its construction projects.

Our investment in Jackalope was $172.7 million and $127.2 million at June 30, 2014 and December 31, 2013. We have reflected the earnings from our investment in Jackalope in our consolidated statements of income, which includes our share of net earnings based on our ownership interest and other adjustments recorded by us as discussed below. During the three and six months endedJune 30, 2014, our share of Jackalope’s net earnings was approximately $0.1 million and $1.2 million. As of June 30, 2014, our investment balance in Jackalope exceeded our equity in the underlying net assets of Jackalope by approximately $55.3 million. We amortize and generally assess the recoverability of this amount based on the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake) and RKI Exploration and Production, LLC (RKI). The amortization is reflected as a reduction of our earnings from unconsolidated affiliates, and during the three and six months endedJune 30, 2014, we recorded amortization expense of approximately $0.7 million and $1.5 million.

Jackalope is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the six months endedJune 30, 2014, Jackalope did not make any distributions to its members.

Our Jackalope investment is included in our gathering and processing segment.

Powder River Basin Industrial Complex, LLC

Crestwood Crude Logistics LLC (Crude Logistics), our consolidated subsidiary, owns a 50% ownership interest in Powder River Basin Industrial Complex, LLC (PRBIC) which we account for under the equity method of accounting. During the six months endedJune 30, 2014, Crude Logistics invested approximately $2.8 million in PRBIC to fund its construction projects.

Our investment in PRBIC was $25.7 million and $24.2 million at June 30, 2014 and December 31, 2013. During the three and six months endedJune 30, 2014, our share of PRBIC’s loss was approximately $0.9 million and $1.3 million. As of June 30, 2014, our investment balance in PRBIC approximated our equity in the underlying net assets of PRBIC.

PRBIC is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the six months endedJune 30, 2014, PRBIC did not make any distributions to its members.

Our PRBIC investment is included in our NGL and crude services segment.

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Acquisitions (Tables)

6 Months Ended

Jun. 30, 2014

Business Acquisition [Line Items]

Pro Forma Consolidated Statements of Operations

The following table represents the pro forma consolidated statement of operations as if the Legacy Inergy reverse merger and the Arrow Acquisition had been included in our consolidated results for the full three and six months endedJune 30, 2013 (in millions, except per unit information):

	Three Months Ended			Six Months Ended
	June 30, 2013			June 30, 2013
Revenues	$	500.9		$	925.6
Net income	$	4.5		$	17.6
Net income per limited partner unit(a):
Basic	$	(0.02	)	$	0.03
Diluted	$	(0.02	)	$	0.03

Inergy Midstream

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following table summarizes the final valuation of the assets acquired and liabilities assumed at the merger date (in millions):

Current assets	$	49.1
Property, plant and equipment	1,677.8
Intangible assets	196.0
Other assets	2.9
Total identifiable assets acquired	1,925.8
Current liabilities	30.9
Long-term debt	745.0
Other long-term liabilities	5.3
Total liabilities assumed	781.2
Net identifiable assets acquired	1,144.6
Goodwill	1,532.7
Net assets acquired	$	2,677.3

Arrow Midstream Holdings, LLC

Business Acquisition [Line Items]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

The following table summarizes the final valuation of the assets acquired and liabilities assumed at the acquisition date (in millions):

Current assets	$	192.7
Property, plant and equipment	400.5
Intangible assets	323.4
Other assets	19.5
Total identifiable assets acquired	936.1
Current liabilities	215.8
Assets retirement obligations	1.2
Other long-term liabilities	3.7
Total liabilities assumed	220.7
Net identifiable assets acquired	715.4
Goodwill	45.9
Net assets acquired	$	761.3

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Condensed Consolidating Financial Information (Notes)

6 Months Ended

Jun. 30, 2014

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Consolidating Financial Information

Condensed Consolidating Financial Information

CMLP is a holding company and owns no operating assets and have no significant operations independent of our subsidiaries. Obligations under our Senior Notes and our Credit Facility are jointly and severally guaranteed by substantially all of our restricted domestic subsidiaries, except for Crestwood Niobrara and PRBIC and their subsidiaries (Non-Guarantor Subsidiaries). Crestwood Midstream Finance Corp., the co-issuer of our Senior Notes, 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.

The tables below present condensed consolidating financial statements for us (parent) on a stand-alone, unconsolidated basis, and our combined guarantor and combined non-guarantor subsidiaries as of June 30, 2014 and December 31, 2013, and for the three-month and six-month periods ended June 30, 2014.  As discussed in Note 2, the Crestwood Merger was accounted for as a reverse merger between entities under common control, and as such, changes in the composition of guarantors and non-guarantors should be reflected retrospectively based on the guarantor structure that existed as of the end of the most recent balance sheet.  Accordingly, we have not reflected condensed consolidating financial information for the three-month and six-month periods ended June 30, 2013 because our unrestricted subsidiaries were not formed or were not designated as unrestricted subsidiaries as of June 30, 2013.  

Condensed Consolidating Balance Sheet
June 30, 2014
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	0.1	$	17.2		$	—	$	—		$	17.3
Accounts receivable	576.5		279.0			0.1		(565.2		)	290.4
Inventories	—		7.6			—		—			7.6
Other current assets	—		13.9			—		—			13.9
Total current assets	576.6		317.7			0.1		(565.2		)	329.2
Property, plant and equipment, net	5.8		3,459.1			—		—			3,464.9
Goodwill and intangible assets, net	—		2,621.9			—		—			2,621.9
Investment in consolidated affiliates	6,496.4		—			—		(6,496.4		)	—
Investment in unconsolidated affiliates	—		—			198.4		—			198.4
Other assets	—		21.2			—		—			21.2
Total assets	$	7,078.8	$	6,419.9		$	198.5	$	(7,061.6	)	$	6,635.6
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	833.0	$	(73.3	)	$	0.1	$	(565.2	)	$	194.6
Other current liabilities	26.2		167.4			—		—			193.6
Total current liabilities	859.2		94.1			0.1		(565.2		)	388.2
Long-term liabilities:
Long-term debt, less current portion	1,846.3		—			—		—			1,846.3
Other long-term liabilities	1.6		27.8			—		—			29.4
Total long-term liabilities	1,847.9		27.8			—		—			1,875.7
Partners' capital	4,230.3		6,298.0			57.0		(6,355.0		)	4,230.3
Interest of non-controlling partners in subsidiaries	141.4		—			141.4		(141.4		)	141.4
Total partners' capital	4,371.7		6,298.0			198.4		(6,496.4		)	4,371.7
Total liabilities and partners' capital	$	7,078.8	$	6,419.9		$	198.5	$	(7,061.6	)	$	6,635.6

Condensed Consolidating Balance Sheet
December 31, 2013
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	0.1	$	1.6		$	1.0	$	—		$	2.7
Accounts receivable	466.8		197.8			0.2		(459.7		)	205.1
Inventories	—		7.0			—		—			7.0
Other current assets	—		10.2			—		—			10.2
Total current assets	466.9		216.6			1.2		(459.7		)	225.0
Property, plant and equipment, net	4.8		3,345.3			—		—			3,350.1
Goodwill and intangible assets, net	—		2,653.6			—		—			2,653.6
Investment in consolidated affiliates	6,385.2		—			—		(6,385.2		)	—
Investment in unconsolidated affiliates	—		—			151.4		—			151.4
Other assets	—		21.7			—		—			21.7
Total assets	$	6,856.9	$	6,237.2		$	152.6	$	(6,844.9	)	$	6,401.8
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	782.7	$	(159.8	)	$	—	$	(459.7	)	$	163.2
Other current liabilities	11.5		139.6			0.2		—			151.3
Total current liabilities	794.2		(20.2		)	0.2		(459.7		)	314.5
Long-term liabilities:
Long-term debt, less current portion	1,867.9		—			—		—			1,867.9
Other long-term liabilities	1.7		24.6			—		—			26.3
Total long-term liabilities	1,869.6		24.6			—		—			1,894.2
Partners' capital	4,092.1		6,232.8			51.4		(6,284.2		)	4,092.1
Interest of non-controlling partners in subsidiaries	101.0		—			101.0		(101.0		)	101.0
Total partners' capital	4,193.1		6,232.8			152.4		(6,385.2		)	4,193.1
Total liabilities and partners' capital	$	6,856.9	$	6,237.2		$	152.6	$	(6,844.9	)	$	6,401.8

Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	82.7		$	—		$	—		$	82.7
Storage and transportation	—			45.4			—			—			45.4
NGL and crude services	—			543.5			—			—			543.5
Related party	—			4.1			—			—			4.1
	—			675.7			—			—			675.7
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			7.8			—			—			7.8
Storage and transportation	—			3.8			—			—			3.8
NGL and crude services	—			497.7			—			—			497.7
Related party	—			9.8			—			—			9.8
	—			519.1			—			—			519.1
Expenses:
Operations and maintenance	—			32.7			—			—			32.7
General and administrative	(0.9		)	22.2			—			—			21.3
Depreciation, amortization and accretion	0.2			54.7			—			—			54.9
	(0.7		)	109.6			—			—			108.9
Other operating income (expense):
Loss on contingent consideration	—			(6.5		)	—			—			(6.5		)
Other	—			1.1			—			—			1.1
Operating income	0.7			41.6			—			—			42.3
Interest and debt expense, net	(29.2		)	0.2			—			—			(29.0		)
Equity in net income (loss) of subsidiary	40.2			—			—			(40.2		)	—
Other	—			—			(1.5		)	—			(1.5		)
Income (loss) before income taxes	11.7			41.8			(1.5		)	(40.2		)	11.8
Provision for income taxes	—			0.1			—			—			0.1
Net income (loss)	11.7			41.7			(1.5		)	(40.2		)	11.7
Net income attributable to non-controlling partners	—			—			(3.7		)	—			(3.7		)
Net income (loss) attributable to Crestwood Midstream Partners LP	11.7			41.7			(5.2		)	(40.2		)	8.0
Net income attributable to Class A preferred units	(1.1		)	—			—			—			(1.1		)
Net income (loss) attributable to partners	10.6			41.7			(5.2		)	(40.2		)	6.9

Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	161.3		$	—		$	—		$	161.3
Storage and transportation	—			89.7			—			—			89.7
NGL and crude services	—			953.4			—			—			953.4
Related party	—			8.3			—			—			8.3
	—			1,212.7			—			—			1,212.7
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			15.5			—			—			15.5
Storage and transportation	—			7.0			—			—			7.0
NGL and crude services	—			873.9			—			—			873.9
Related party	—			20.8			—			—			20.8
	—			917.2			—			—			917.2
Expenses:
Operations and maintenance	—			60.7			—			—			60.7
General and administrative	(3.0		)	48.4			—			—			45.4
Depreciation, amortization and accretion	0.4			105.3			—			—			105.7
	(2.6		)	214.4			—			—			211.8
Other operating income (expense):
Loss on contingent consideration	—			(8.6		)	—			—			(8.6		)
Other	—			1.6			—			—			1.6
Operating income	2.6			74.1			—			—			76.7
Interest and debt expense, net	(57.3		)	0.2			—			—			(57.1		)
Equity in net income (loss) of subsidiary	71.9			—			—			(71.9		)	—
Other	—			—			(1.6		)	—			(1.6		)
Income (loss) before income taxes	17.2			74.3			(1.6		)	(71.9		)	18.0
Provision for income taxes	—			0.8			—			—			0.8
Net income (loss)	17.2			73.5			(1.6		)	(71.9		)	17.2
Net (income) attributable to non-controlling partners	—			—			(6.8		)	—			(6.8		)
Net income (loss) attributable to Crestwood Midstream Partners LP	17.2			73.5			(8.4		)	(71.9		)	10.4
Net income attributable to Class A preferred units	(1.1		)	—			—			—			(1.1		)
Net income (loss) attributable to partners	16.1			73.5			(8.4		)	(71.9		)	9.3

Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(16.7	)	$	112.1		$	—		$	—		$	95.4
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(19.5		)	—			—			(19.5		)
Purchases of property, plant and equipment	(2.3		)	(162.4		)	—			—			(164.7		)
Investment in unconsolidated affiliates, net	—			(2.8		)	(45.8		)	—			(48.6		)
Capital contribution from consolidated affiliates	(11.2		)	(2.8		)	—			14.0			—
Other	(265.5		)	—			—			265.5			—
Net cash provided by (used in) investing activities	(279.0		)	(187.5		)	(45.8		)	279.5			(232.8		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2.5			858.1			—			—			860.6
Principal payments on long-term debt	—			(863.2		)	—			—			(863.2		)
Distributions paid	—			(169.2		)	—			—			(169.2		)
Contributions from parent	—			2.8			11.2			(14.0		)	—
Net proceeds from issuance of preferred equity	—			—			33.6			—			33.6
Net proceeds from issuance of Class A preferred units	293.7			—			—			—			293.7
Payments on capital leases	(0.5		)	(1.4		)	—			—			(1.9		)
Taxes paid for unit-based compensation vesting	—			(1.5		)	—			—			(1.5		)
Net change in payables to affiliates	—			265.5			—			(265.5		)	—
Other	—			(0.1		)	—			—			(0.1		)
Net cash provided by (used in) financing activities	295.7			91.0			44.8			(279.5		)	152.0
Net increase in cash	—			15.6			(1.0		)	—			14.6
Cash at beginning of period	0.1			1.6			1.0			—			2.7
Cash at end of period	$	0.1		$	17.2		$	—		$	—		$	17.3

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Long-Term Incentive Plan (Notes)

6 Months Ended

Jun. 30, 2014

Equity [Abstract]

Long-Term Incentive Plan

Long-Term Incentive Plan

Long-term incentive awards are granted under the Crestwood Midstream Partners LP Long Term Incentive Plan (Crestwood LTIP) (formerly the Inergy Midstream, L.P. Long Term Incentive Plan) in order to align the economic interests of key employees and directors with those of CMLP's common unitholders and to provide an incentive for continuous employment. Long-term incentive compensation consist solely of grants of restricted common units (which represent limited partner interests of CMLP) which vest based upon continued service.

On January 17, 2014, we issued restricted unit awards, which were approved by the CMLP Board's compensation committee, to certain key employees. The awards consisted of an annual award based on a percentage of each recipient's annual salary, and a one-time bridge award designed to provide an additional base award to certain key employees with no remaining unvested awards given that their previously accumulated equity ownership in Legacy Inergy and Legacy Crestwood vested as a result of the change of control with the Crestwood Merger. Both of these awards vest upon continued service.

The following table summarizes information regarding restricted unit activity during the six months endedJune 30, 2014:

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	250,557		$	22.13
Vested - restricted units	(190,818	)	$	22.29
Granted - restricted units	792,034		$	23.39
Forfeited	(41,523	)	$	23.58
Unvested - June 30, 2014	810,250		$	23.25

As of June 30, 2014 and December 31, 2013, we had total unamortized compensation expense of approximately $13.3 million and $1.8 million related to restricted units, which we expect will be amortized during the next three years (or sooner in certain cases, which generally represents the original vesting period of these instruments), except for grants to non-employee directors of our general partner, which vest over one year. As of June 30, 2014, the restricted units issued under the Legacy Inergy long-term incentive plan were fully vested and as such, there was no unamortized compensation expense related to those units at June 30, 2014. We recognized compensation expense of approximately $3.3 million and $0.9 million during the three months ended June 30, 2014 and 2013 and $6.2 million and $1.5 million during the six months endedJune 30, 2014 and 2013, which is included in general and administrative expenses on our consolidated statements of operations. An additional $1.9 million and $3.6 million of net compensation expense was allocated from CEQP to us during the three and six months endedJune 30, 2014 and an additional $0.2 million was allocated from CEQP to us during the three and six months endedJune 30, 2013 (see Note 11). The compensation expense recognized during the three and six months endedJune 30, 2013 was primarily related to the Legacy Crestwood long-term incentive plan. We granted restricted units with a grant date fair value of approximately $0.8 million and $18.5 million during the three and six months endedJune 30, 2014.  As of June 30, 2014, we had 6,460,338 units available for issuance under the Crestwood LTIP.

Under the Crestwood LTIP, participants who have been granted restricted units may elect to have common units withheld 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 Crestwood LTIP on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When we withhold these common units, we are required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. During the three months ended June 30, 2014 and 2013, we withheld 61,076 and 900 common units and during the six months endedJune 30, 2014 and 2013, we withheld 68,532 common units and 2,429 common units to satisfy employee tax withholding obligations.

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Financial Instruments

6 Months Ended

Jun. 30, 2014

Debt Disclosure [Abstract]

Financial Instruments

Financial Instruments

Fair Value

We separate the fair values of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instruments and would be reflected at the end of the period in which the change occurs. At June 30, 2014 and December 31, 2013, there were 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.

As of June 30, 2014 and December 31, 2013, the carrying amounts of cash and cash equivalents, accounts receivable and accounts payable represent fair value based on the short-term nature of these instruments. The fair value of the amount outstanding under our credit facility approximates its carrying amount as of June 30, 2014 and December 31, 2013 due primarily to the variable nature of the interest rate of the instrument, which is considered a Level 2 fair value measurement.

We estimate the fair value of our senior notes primarily based on quoted market prices for the same or similar issuances (representing a Level 2 fair value measurement). The following table reflects the carrying value and fair value of our senior notes (in millions):

	June 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2019 Senior Notes	$	351.1	$	376.6	$	351.2	$	379.3
2020 Senior Notes	$	504.3	$	532.7	$	504.7	$	513.8
2022 Senior Notes	$	600.0	$	634.5	$	600.0	$	617.3

Long-Term Debt

Long-term debt consisted of the following at June 30, 2014 and December 31, 2013 (in millions):

	June 30, 2014		December 31, 2013
Credit Facility	$	412.3	$	414.9
2019 Senior Notes	350.0		350.0
Premium on 2019 Senior Notes	1.1		1.2
2020 Senior Notes	500.0		500.0
Fair value adjustment of 2020 Senior Notes	4.3		4.7
2022 Senior Notes	600.0		600.0
Other	3.5		—
Total debt	1,871.2		1,870.8
Less: current portion	24.9		2.9
Total long-term debt	$	1,846.3	$	1,867.9

Credit Facility

We have a five-year $1 billion senior secured revolving credit facility (the Credit Facility), which is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The Credit Facility includes a sub-limit up to $25 million for same-day swing line advances and a sub-limit up to $250 million for letters of credit. Subject to limited exception, the Credit Facility is secured by substantially all of the equity interests and assets of our restricted domestic subsidiaries, and is joint and severally guaranteed by substantially all of our restricted domestic subsidiaries.

On June 11, 2014, we amended our Credit Facility to clarify, among other things, (i) the methodology for calculating the value of our investment in certain joint ventures constituting unrestricted subsidiaries, and (ii) that redemptions, repurchases and retirements of equity interests are permitted to the extent made solely through the issuance of additional equity units. We did not pay any fees to our bank syndicate for this amendment.

At June 30, 2014, the balance outstanding on our Credit Facility was $412.3 million and outstanding standby letters of credit were $31.4 million. We had $366.7 million of available capacity under the revolving credit facility at June 30, 2014 considering our most restrictive debt covenants under the facility. The interest rates on our Credit Facility are based on the prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 2.71% and 5.00% at June 30, 2014. The weighted-average interest rate as of June 30, 2014 was 5.73%.

We are required under our credit agreement to maintain a consolidated leverage ratio (as defined in our credit agreement) of not more than 5.00 (subject to, at our election, a consolidated net leverage ratio of not more than 5.50 to 1.0 during certain periods following certain material acquisitions as further described in our credit agreement) to 1.0 and an interest coverage ratio (as defined in our credit agreement) of not less than 2.50 to 1.0.

At June 30, 2014, we elected to use a consolidated net leverage ratio of 5.50 to 1.0. At September 30, 2014, our consolidated net leverage ratio will revert back to 5.00 to 1.0. Our net debt to consolidated EBITDA was approximately 4.56 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 3.69 to 1.0 at June 30, 2014.

Senior Notes

We have three series of senior unsecured notes outstanding, including (i) $350 million in aggregate principal amount of 7.75% Senior Notes due 2019 (the 2019 Senior Notes), (ii) $500 million in aggregate principal amount of 6.0% Senior Notes due 2020 (the 2020 Senior Notes), and (iii) $600 million in aggregate principal amount of 6.125% Senior Notes due 2022 (the 2022 Senior Notes, and together with the 2019 Senior Notes and 2020 Senior Notes, our Senior Notes). Our Senior Notes are guaranteed on a senior unsecured basis by all of our domestic restricted subsidiaries, subject to certain exceptions. 

Under the indenture governing our 2019 Senior Notes, we may not pay any dividend on our common units unless, among other things, at the time of and after giving effect to such dividend payment, no default under the indenture has occurred and is continuing or would occur as a consequence of such dividend payment.

At June 30, 2014, we were in compliance with all of our debt covenants applicable to our Credit Facility and our Senior Notes. For additional information regarding our debt covenants, see our 2013 Annual Report on Form 10-K as filed with the SEC.

On July 17, 2014, we filed a registration statement with the SEC under which we are offering to exchange $600 million in aggregate principal amount of registered 6.125% Senior Notes due 2022 for any and all outstanding 2022 Senior Notes, which were issued in a private offering in November 2013. The terms of the exchange notes are substantially identical to the terms of the 2022 Senior Notes, except that the exchange notes will be freely tradable. We expect to complete the exchange offering in August 2014.

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Partners' Capital

6 Months Ended

Jun. 30, 2014

Partners' Capital [Abstract]

Partners' Capital

Partners’ Capital

Equity Distribution Agreement

On July 10, 2014, we entered into an equity distribution agreement with Morgan Stanley & Co. LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC (each, a Manager), under which we may offer and sell from time to time through one or more of the Managers, common units having an aggregate offering price of up to $300.0 million. Common units sold pursuant to this at-the-market (ATM) equity distribution program will be issued under a registration statement that became effective on May 27, 2014. We will pay the Managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under our ATM program. We have not issued any common units under this equity distribution program. Additional information on our ATM equity distribution program is available in our Form 8-K filed with the SEC on July 10, 2014.

Distributions

Our partnership agreement requires us to distribute, within 45 days after the end of each quarter, all available cash (as defined in our partnership agreement) to our common and preferred unitholders of record on the applicable record date. The general partner is not entitled to distributions on its non-economic general partner interest.

Distributions to General Partner

We paid cash distributions to our general partner (representing IDRs and distributions related to common units held by the general partner) of approximately $20.9 million and $9.3 million during the six months endedJune 30, 2014 and 2013.

Distributions to Class A Preferred Unit Holders

Our partnership agreement requires us to make quarterly distributions to our Class A Preferred Unit holders. The holders of our Class A Preferred Units (the Preferred Units) are entitled to receive fixed quarterly distributions of $0.5804 per unit. For the 12 quarters following the quarter ended June 30, 2014 (the Initial Distribution Period), distributions on our Preferred Units can be made in additional Preferred Units, cash, or a combination thereof, at our election. If we elect to pay the quarterly distribution through the issuance of additional Preferred Units, the number of units to be distributed will be calculated as the fixed quarterly distribution of $0.5804 per unit divided by the cash purchase price of $25.10 per unit. We accrue the fair value of such distribution at the end of the quarterly period and adjust the fair value of the distribution on the date the additional Preferred Units are distributed. Distributions on our Preferred Units following the Initial Distribution Period will be made in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to our Preferred Unit holders. If we fail to pay the full amount payable to our Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.7059 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if we fail to pay in full any Class A Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter. For additional information on our Preferred Units, see Class A Preferred Units section below.

On July 23, 2014, the board of directors of our general partner authorized the issuance 42,523 Preferred Units to our Preferred Unit holders for the quarter ending June 30, 2014. In accordance with our partnership agreement, the additional Preferred Units will not be issued until the distribution payment date for the quarter ending September 30, 2014.

Distributions to Limited Partners

The following table presents quarterly cash distributions paid to our limited partners (excluding distributions paid to our general partner on its common units held) during the six months endedJune 30, 2014:

Six Months Ended June 30, 2014
Record Date	Payment Date	Per Unit Rate		Cash Distribution (in millions)
February 7, 2014	February 14, 2014	$	0.41	$	74.1
May 8, 2014	May 15, 2014	$	0.41	74.2
				$	148.3

The following table presents Legacy Crestwood's quarterly cash distributions paid to the limited partners (excluding distributions paid to the general partner on its common units held) during the six months ended ended June 30, 2013:

Six Months Ended June 30, 2013
Record Date	Payment Date	Per Unit Rate		Cash Distribution (in millions)
January 31, 2013	February 12, 2013	$	0.51	$	21.0
April 30, 2013	May 10, 2013	$	0.51	27.4
				$	48.4

On July 23, 2014, we declared a distribution of $0.41 per limited partner unit to be paid on August 14, 2014, to unitholders of record on August 7, 2014 with respect to the second quarter of 2014.

Preferred Equity

Class A Preferred Units

On June 17, 2014, we entered into definitive agreements with a group of investors, including Magnetar Capital, affiliates of GSO Capital Partners LP and GE Energy Financial Services (the Class A Purchasers). Under these agreements, we have agreed to sell to the Class A Purchasers and the Class A Purchasers have agreed to purchase from us up to $500 million of Preferred Units at a fixed price of $25.10 per unit on or before September 30, 2015. Contemporaneously with the closing ofthis equity commitment, on June 17, 2014, the Class A Purchasers purchased 11,952,191 Preferred Units for a cash purchase price of $25.10 per unit resulting in gross proceeds to us of approximately $300 million (net proceeds of approximately $293.7 million after deducting transaction fees and offering expenses).

Subject to certain conditions, holders of the Preferred Units will have the right to convert Preferred Units into (i) common units on a one-for-one basis after June 17, 2017, or (ii) a number of common units determined pursuant to a conversion ratio set forth in our partnership agreement upon the occurrence of certain events, such as a change in control. Also, subject to certain conditions after the full $500 million purchase commitment has been satisfied, we may convert the Preferred Units into common units at a conversion ratio set forth in the partnership agreement, which is based in part on the aggregate principal amount of the Preferred Units outstanding and the weighted average trading price of our common units. 

The Preferred Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each Preferred Unit entitled to one vote for each common unit into which such Preferred Unit is convertible, except that the Preferred Units are entitled to vote as a separate class on any matter on which all unitholders are entitled to vote that adversely affects the rights, powers, privileges or preferences of the Preferred Units in relation to our other securities outstanding.

Additional information on the terms and conditions of the Preferred Units, including distribution, conversion, voting rights and liquidation preferences, is available on our Form 8-Ks filed with the SEC on June 19, 2014 and July 11, 2014, respectively.

On July 9, 2014, we filed a shelf registration statement with the SEC under which holders of the Preferred Units may sell the common units into which the Preferred Units are convertible. The registration statement became effective on July 18, 2014. We registered 26,299,076 common units under the registration statement.

Crestwood Niobrara Preferred Interest

Crestwood Niobrara issued a preferred interest to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE) in conjunction with the acquisition of its investment in Jackalope. The preferred interest is reflected as non-controlling interest in our consolidated financial statements. During the three and six months endedJune 30, 2014, we allocated approximately $3.7 million and $6.8 million of net income to the non-controlling interest, which was based on the overall return attributable to the preferred security.

Crestwood Niobrara will fund 75% of future capital contributions to Jackalope through additional preferred interest issuances to GE (up to a maximum of an additional $20.3 million as of June 30, 2014), with the remainder to be funded through our capital contributions to Crestwood Niobrara. During the six months endedJune 30, 2014, GE made capital contributions of $33.6 million to Crestwood Niobrara in exchange for an equivalent number of preferred units. Through June 30, 2014, GE has made cumulative capital contributions totaling $129.7 million.

Crestwood Niobrara has the option to pay distributions to GE with cash or by issuing additional preferred units through the January 2015 distribution. During the three months ended March 31, 2014 and June 30, 2014, Crestwood Niobrara issued 2,210,294 and 2,536,010 preferred units to GE in lieu of paying a cash distribution. We serve as the managing member of Crestwood Niobrara and, subject to certain restrictions, we have the ability to redeem GE’s preferred interest in either cash or our common units at an amount equal to the face amount of the preferred units plus an applicable return. On July 30, 2014,Crestwood Niobrara issued 3,073,357 preferred units to GE in lieu of paying a cash distribution.

Other Partners’ Capital Transaction

On January 8, 2013, Legacy Crestwood acquired Crestwood Holdings’ 65% membership interest in Crestwood Marcellus Midstream LLC (CMM) for approximately $258.0 million, of which approximately $129.0 million was funded through the issuance of 6,190,469 Class D units and the issuance of 133,060 general partner units to the Legacy Crestwood general partner. We reflected the issuances of the Class D and general partner units as distributions for additional interest in CMM in our consolidated statements of cash flows for the six months endedJune 30, 2013.

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Legal Proceedings

Class Action Lawsuits.Five putative class action lawsuits challenging the Crestwood 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 of the cases named Legacy Crestwood (since merged with the Company), Crestwood Gas Services GP LLC, Crestwood Holdings LLC, the current and former directors of Crestwood Gas Services GP LLC, CEQP, the Company, Crestwood Midstream GP LLC (formerly NRGM GP, LLC), and Intrepid Merger Sub, LLC as defendants. All of the suits were brought by purported holders of common units of Legacy Crestwood, both individually and on behalf of a putative class consisting of holders of common units of Legacy 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 Legacy Crestwood by agreeing to a transaction with inadequate consideration and unfair terms and pursuant to an inadequate process. The lawsuits further alleged that CEQP, the Company, Crestwood Midstream GP LLC, and Intrepid Merger Sub, LLC aided and abetted the Legacy 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 has been granted by the Court, such that the Hawley action has now been 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 matter as In re Crestwood Midstream Partners Unitholder Litigation, Lead Case No. 4:13-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. A final settlement was approved by the Court on May 16, 2014, and the settlement did not have a material impact to our consolidated financial statements.

Arrow Acquisition Class Action Lawsuit. Prior to the completion of the Arrow Acquisition on November 8, 2013, a train transporting over 50,000 barrels of crude oil produced in North Dakota derailed in Lac Megantic, Quebec, Canada on July 6, 2013. The derailment resulted in the death of 47 people, injured numerous others, and caused severe damage to property and the environment.  In October 2013, certain individuals suffering harm in the derailment filed a motion to certify a class action lawsuit in the Superior Court for the District of Megantic, Province of Quebec, Canada, on behalf of all persons suffering loss in the derailment.

In March 2014, the plaintiffs filed their fourth amended motion to name Arrow and numerous other energy companies as additional defendants in the class action lawsuit. The plaintiffs have named at least 53 defendants purportedly involved in the events leading up to the derailment, including the producers and sellers of the crude being transported, the midstream companies that transported the crude from the well head to the rail system, the manufacturers of the rail cars used to transport the crude, the railroad companies involved, the insurers of these companies, and the Canadian Attorney General.  The plaintiffs allege, among other things, that Arrow (i) was a producer of the crude oil being transported on the derailed train, (ii) was negligent in failing to properly classify the crude delivered to the trucks that hauled the crude to the rail loading terminal, and (iii) owed a duty to the petitioners to ensure the safe transportation of the crude being transported.  The motion to authorize the class action and motions in opposition were heard by the Court in June 2014.  The Canadian Attorney General was granted an extension of time to respond and will make their oral argument opposing the motion at the end of August 2014. We do not anticipate a ruling from the Judge on Petitioners' motion to authorize the class action until the fourth quarter of 2014. We believe the claims against us are without merit and will vigorously defend ourselves.  Moreover, to the extent this action proceeds, we believe we have meritorious defenses to the claims.  Because this litigation is in the early stages of the proceeding, we are unable to estimate a reasonably possible loss or range of loss in this matter.  We believe this claim is an insurable event under our insurance policy and we have notified our insurance company of the claim.

We are periodically involved in litigation proceedings. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, then we accrue the estimated amount. The results of litigation proceedings cannot be predicted with certainty. We could incur judgments, enter into settlements or revise our expectations regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations or cash flows in the period in which the amounts are paid and/or accrued. As of June 30, 2014 and December 31, 2013, we had less than $0.1 million accrued for our outstanding legal matters. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures for which we can estimate will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.

Any loss estimates are inherently subjective, based on currently available information, and are subject to management's judgment and various assumptions. Due to the inherently subjective nature of these estimates and the uncertainty and unpredictability surrounding the outcome of legal proceedings, actual results may differ materially from any amounts that have been accrued.

Regulatory Compliance

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

Environmental Compliance

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. We are subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. Our accruals and potential exposures related to our environmental matters were immaterial at June 30, 2014 and December 31, 2013.

On July 4, 2014, we experienced a release of approximately 25,000 barrels of produced water on our Arrow water gathering system located on the Fort Berthold Indian Reservation in North Dakota. We immediately notified the National Response Center, the Three Affiliated Tribes and numerous other regulatory authorities, and thereafter contained and cleaned up the release promptly. We placed the impacted segment of the water line back into service on July 20, 2014. We will continue our long-term remediation efforts to ensure the impacted lands are restored to their prior state, and we will potentially be subject to substantial fines and penalties. We believe that the release is an insurable event under our policies, and we have notified our carriers of the event. Because this matter is in the early stages of remediation, we are unable to estimate a reasonably possible loss or range of loss.

Contingent Consideration - Antero

In connection with the acquisition of Antero Resources (Antero), we agreed to pay Antero conditional consideration in the form of potential additional cash payments of up to $40 million, depending on the achievement of certain defined average annual production levels achieved during 2012, 2013 and 2014. During 2012 and 2013, Antero did not meet the annual production level to earn additional payments. Based on our estimates of Antero’s 2014 production, we believe their production levels will exceed the annual production threshold in the earn-out provision and accordingly, we recognized a liability of $40.0 million and $31.4 million as of June 30, 2014 and December 31, 2013, which we anticipate paying in the first quarter of 2015.

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Certain Balance Sheet Information (Intangible Assets) (Details) (USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	$ 1,034.4	$ 1,025.1
Less: accumulated amortization	93.9	54.3
Total intangible assets, net	940.5	970.8
Customer accounts
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	483.2	476.4
Covenants not to compete
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	5.5	3.0
Gas gathering, compression and processing contracts
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	451.4	451.4
Acquired storage contracts
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	29.0	29.0
Trademarks
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	11.0	11.0
Deferred financing and other costs
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	$ 54.3	$ 54.3

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Segments (Reconciliation of Net Income to EBITDA) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Segment Reporting [Abstract]
Net income	$ 11.7	$ 6.7	$ 17.2	$ 15.6
Interest and debt expense, net	29.0	12.5	57.1	23.9
Provision for income taxes	0.1	0.3	0.8	0.7
Depreciation, amortization and accretion	54.9	20.9	105.7	38.3
EBITDA	$ 95.7	$ 40.4	$ 180.8	$ 78.5

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Basis of Presentation and Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2014

Accounting Policies [Abstract]

Schedule of Error Corrections and Prior Period Adjustments [Table Text Block]

The following table summarizes the reclassification of the amounts previously reported in operating and administrative expenses for the periods presented (in millions):

	Year Ended December 31,
	2013		2012		2011
Operating and administrative expenses as previously reported	$	154.0	$	72.7	$	60.4
Operations and maintenance expenses	73.3		43.1		36.3
General and administrative expenses	80.7		29.6		24.1

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Partners' Capital (Tables)

6 Months Ended

Jun. 30, 2014

Partners' Capital [Abstract]

Schedule of Distributions Made to Members or Limited Partners, by Distribution

The following table presents quarterly cash distributions paid to our limited partners (excluding distributions paid to our general partner on its common units held) during the six months endedJune 30, 2014:

Six Months Ended June 30, 2014
Record Date	Payment Date	Per Unit Rate		Cash Distribution (in millions)
February 7, 2014	February 14, 2014	$	0.41	$	74.1
May 8, 2014	May 15, 2014	$	0.41	74.2
				$	148.3

The following table presents Legacy Crestwood's quarterly cash distributions paid to the limited partners (excluding distributions paid to the general partner on its common units held) during the six months ended ended June 30, 2013:

Six Months Ended June 30, 2013
Record Date	Payment Date	Per Unit Rate		Cash Distribution (in millions)
January 31, 2013	February 12, 2013	$	0.51	$	21.0
April 30, 2013	May 10, 2013	$	0.51	27.4
				$	48.4

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Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			6 Months Ended
	Jun. 30, 2014		Jun. 30, 2013	Jun. 30, 2014		Jun. 30, 2013	Dec. 31, 2013
Related Party Transaction [Line Items]
Operating, administrative and overhead cost	$ 12.9			$ 28.7		$ 0.5
Disclosure Related Party Transaction Additional Information [Abstract]
Gathering and processing revenues	4.1		25.0	8.3		50.6
Related Party Transaction, Due from (to) Related Party [Abstract]
Accounts payable	13.8			13.8			8.7
CEQP
Disclosure Related Party Transaction Additional Information [Abstract]
Gathering and processing revenues	0.7	[1]	24.6	1.6	[1]	50.2
NGL and crude services revenues	3.4	[1]	0.4	6.7	[1]	0.4
Gathering and processing costs of goods sold	9.8	[1]	7.8	20.8	[1]	14.6
General and administrative expenses	4.5	[1]	5.3	8.3	[1]	10.6
Affiliates
Related Party Transaction, Due from (to) Related Party [Abstract]
Accounts receivable	7.2			7.2			1.1
Accounts payable	13.8			13.8			8.7
Crestwood LTIP | CMLP
Related Party Transaction [Line Items]
Allocated Share-based Compensation Expense	$ 1.9		$ 0.2	$ 3.6		$ 0.2

[1] Concurrent with the Crestwood Merger, Quicksilver Resources Inc. (Quicksilver) is no longer a related party, and as a result our transactions with Quicksilver subsequent to June 19, 2013, are now considered non-affiliated transactions.

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Financial Instruments (Schedule of Carrying Values and Estimated Fair Values of Senior Notes) (Details) (Unsecured Debt, USD $) In Millions, unless otherwise specified	Jun. 30, 2014	Dec. 31, 2013
Carrying Amount | 2019 senior unsecured notes
Debt Instrument [Line Items]
Fair value of senior notes	$ 351.1	$ 351.2
Carrying Amount | 2020 senior unsecured notes
Debt Instrument [Line Items]
Fair value of senior notes	504.3	504.7
Carrying Amount | 2022 senior unsecured notes
Debt Instrument [Line Items]
Fair value of senior notes	600.0	600.0
Fair Value | 2019 senior unsecured notes
Debt Instrument [Line Items]
Fair value of senior notes	376.6	379.3
Fair Value | 2020 senior unsecured notes
Debt Instrument [Line Items]
Fair value of senior notes	532.7	513.8
Fair Value | 2022 senior unsecured notes
Debt Instrument [Line Items]
Fair value of senior notes	$ 634.5	$ 617.3

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CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (USD $) In Millions, unless otherwise specified	Total	Preferred Partner	Preferred Partner Capital Unit, Class A [Member]	Limited Partner	Limited Partner Capital Unit, Class A [Member]	Non Controlling Partners	Non Controlling Partners Capital Unit, Class A [Member]	Partners' Capital	Partners' Capital Capital Unit, Class A [Member]
Beginning Balance at Dec. 31, 2013	$ 4,092.1	$ 0		$ 4,092.1		$ 101.0		$ 4,193.1
Increase (Decrease) in Partners' Capital [Roll Forward]
Change in invested capital from Legacy Inergy, net of debt (Note 4)				(5.0)		0		(5.0)
Distributions to general partner		0		(20.9)		0		(20.9)
Distributions to limited partner		0		(148.3)		0		(148.3)
Unit-based compensation charges		0		9.8		0		9.8
Issuance of preferred equity of subsidiary		0	(293.7)	0	0	33.6	0	(33.6)	(293.7)
Taxes paid for unit-based compensation vesting				(1.5)		0		(1.5)
Net income	17.2	1.1		9.3		6.8		17.2
Ending Balance at Jun. 30, 2014	$ 4,230.3	$ 294.8		$ 3,935.5		$ 141.4		$ 4,371.7

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Acquisitions

6 Months Ended

Jun. 30, 2014

Business Combinations [Abstract]

Acquisitions

Acquisitions

2014 Acquisitions

Crude Transportation Acquisitions (Bakken)

Red Rock. On March 21, 2014, we purchased substantially all of the operating assets of Red Rock Transportation Inc. (Red Rock) for approximately $13.8 million, comprised of $12.1 million paid at closing plus deferred payments of $1.7 million. Red Rock is a trucking operation located in Watford City, North Dakota which provides crude oil and produced water hauling services to the oilfields of western North Dakota and eastern Montana. The acquired assets include a fleet of approximately 56 trailer tanks, 22 double bottom body tanks and 44 tractors with 28,000 barrels per day of transportation capacity. In the first quarter of 2014, we finalized the purchase price and allocated approximately $10.6 million of the purchase price to property, plant and equipment and intangible assets and approximately $3.2 million to goodwill. Goodwill recognized relates primarily to anticipated operating synergies between the assets acquired and our existing assets. These assets are included in our NGL and crude services segment.

LT Enterprises. On May 9, 2014, we purchased substantially all of the operating assets of LT Enterprises, Inc. (LT Enterprises) for approximately $10.7 million, comprised of $9.0 million paid at closing plus deferred payments of $1.7 million. LT Enterprises is a trucking operation located in Watford City, North Dakota which provides crude oil and produced water hauling services primarily to the oilfields of western North Dakota. The acquired assets include a fleet of approximately 38 tractors, 51 crude trailers and 17 service vehicles with 20,000 barrels per day of transportation capacity. In addition, we acquired employee housing and 20 acres of greenfield real property located two miles south of Watford City. In the second quarter of 2014, we finalized the purchase price and allocated all of the purchase price to property, plant and equipment and intangible assets. These assets are included in our NGL and crude services segment.

The acquisitions of Red Rock and LT Enterprises were not material to our NGL and crude services segment's results of operations for the three and six months endedJune 30, 2014. In addition, transaction costs related to these acquisitions were not material for the three and six months ended June 30, 2014.

2013 Acquisitions

Crestwood Merger

As described in Note 2, the merger of Legacy Crestwood with and into Legacy Inergy was accounted for as a reverse merger amongst entities under common control. This accounting treatment requires the accounting acquiree (Legacy Inergy) to have its assets and liabilities stated at fair value as well as any other purchase accounting adjustments as of June 19, 2013, the date in which Legacy Crestwood and Legacy Inergy came under common control. The fair value of Legacy Inergy was calculated based on the consolidated enterprise fair value of Legacy Inergy as of June 19, 2013. This consolidated enterprise fair value considered the discounted future cash flows of Legacy Inergy's operations and Legacy Inergy's NYSE-listed stock price, the value of its outstanding senior notes based on quoted market prices for same or similar issuances and the value of its outstanding floating rate debt.

In June 2014, we finalized the Legacy Inergy purchase price allocation. Changes from our preliminary estimates as of December 31, 2013 were not material to our net assets at June 30, 2014. The following table summarizes the final valuation of the assets acquired and liabilities assumed at the merger date (in millions):

Current assets	$	49.1
Property, plant and equipment	1,677.8
Intangible assets	196.0
Other assets	2.9
Total identifiable assets acquired	1,925.8
Current liabilities	30.9
Long-term debt	745.0
Other long-term liabilities	5.3
Total liabilities assumed	781.2
Net identifiable assets acquired	1,144.6
Goodwill	1,532.7
Net assets acquired	$	2,677.3

Of the $1,532.7 million of goodwill, $806.4 million is reflected in our NGL and crude services segment and $726.3 million is reflected in our storage and transportation segment. Goodwill recognized relates primarily to synergies and new expansion opportunities expected to result from the combination of Legacy Inergy and Legacy Crestwood.  During the period from June 19, 2013 to June 30, 2013, we recognized $9.0 million of revenues and $1.8 million of net income related to this reverse merger.

Arrow Acquisition

On November 8, 2013, we acquired Arrow Midstream Holdings, LLC (Arrow) for approximately $750 million, subject to customary capital expenditures and working capital adjustments of approximately $11.3 million, representations, warranties and indemnifications.  The acquisition was consummated by merging one of our wholly-owned subsidiaries with and into Arrow (the Arrow Acquisition), with Arrow continuing as the surviving entity and our wholly-owned subsidiary. The base merger consideration consisted of $550 million in cash and 8,826,125 common units issued to the sellers, subject to adjustment for standard working capital provisions.

In June 2014, we finalized the Arrow Acquisition purchase price allocation. Changes from our preliminary estimates as of December 31, 2013 were not material to our net assets at June 30, 2014. The following table summarizes the final valuation of the assets acquired and liabilities assumed at the acquisition date (in millions):

Current assets	$	192.7
Property, plant and equipment	400.5
Intangible assets	323.4
Other assets	19.5
Total identifiable assets acquired	936.1
Current liabilities	215.8
Assets retirement obligations	1.2
Other long-term liabilities	3.7
Total liabilities assumed	220.7
Net identifiable assets acquired	715.4
Goodwill	45.9
Net assets acquired	$	761.3

The $45.9 million of goodwill is reflected in our NGL and crude services segment. Goodwill recognized relates primarily to anticipated operating synergies between the assets acquired and our existing assets. During the six months endedJune 30, 2014, we also recognized approximately $5.2 million of transaction-related fees primarily related to services provided in 2013 related to this acquisition.

Unaudited Pro Forma Financial Information

The following table represents the pro forma consolidated statement of operations as if the Legacy Inergy reverse merger and the Arrow Acquisition had been included in our consolidated results for the full three and six months endedJune 30, 2013 (in millions, except per unit information):

	Three Months Ended			Six Months Ended
	June 30, 2013			June 30, 2013
Revenues	$	500.9		$	925.6
Net income	$	4.5		$	17.6
Net income per limited partner unit(a):
Basic	$	(0.02	)	$	0.03
Diluted	$	(0.02	)	$	0.03

(a) Basic and diluted net income per limited partner unit for the three and six months endedJune 30, 2013 were computed based on the number of Legacy Inergy common units outstanding plus the number of common units issued by Legacy Inergy to Legacy Crestwood unitholders as part of the Crestwood Merger and the number of units issued in conjunction with the Arrow Acquisition.

These amounts have been calculated after applying our accounting policies and adjusting the results of the acquisitions to reflect the depreciation and amortization based on the estimated fair value adjustments to property, plant and equipment and intangible assets.

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Long-Term Incentive Plan (Tables)

6 Months Ended

Jun. 30, 2014

Equity [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

The following table summarizes information regarding restricted unit activity during the six months endedJune 30, 2014:

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	250,557		$	22.13
Vested - restricted units	(190,818	)	$	22.29
Granted - restricted units	792,034		$	23.39
Forfeited	(41,523	)	$	23.58
Unvested - June 30, 2014	810,250		$	23.25

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Earnings Per Limited Partner Unit (Allocation of Net Income to General and Limited Partners) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		6 Months Ended
	Jun. 30, 2014	Jun. 30, 2013	Jun. 30, 2014	Jun. 30, 2013
Earnings Per Share [Abstract]
Net income attributable to CMLP	$ 8.0	$ 6.7	$ 10.4	$ 15.6
Class A preferred units interest in net income attributable to CMLP	(1.1)	0	(1.1)	0
General partner’s incentive distributions	(7.5)	(7.7)	(15.0)	(12.7)
General partner’s interest in net income attributable to CMLP	0	(0.1)	0	(0.3)
Limited partners’ interest in net income (loss) attributable to CMLP	$ (0.6)	$ (1.1)	$ (5.7)	$ 2.6

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Basis of Presentation and Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2014

Accounting Policies [Abstract]

Principals of Consolidation

Significant Accounting Policies

There were no material changes in our significant accounting policies from those described in our 2013 Annual Report on Form 10-K and no significant accounting pronouncements issued but not yet adopted as of June 30, 2014.