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 September 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

As of November 3, 2014, the registrant had 187,979,748 Common Units and 14,940,238 Class A Preferred Units outstanding.

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 September 30, 2014 and December 31, 2013	3
Consolidated Statements of Operations for the Three and Nine Months Ended September 30, 2014 and 2013	4
Consolidated Statement of Partners’ Capital for the Nine Months Ended September 30, 2014	5
Consolidated Statements of Cash Flows for the Nine Months Ended September 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	34
Item 3 – Quantitative and Qualitative Disclosures About Market Risk	45
Item 4 – Controls and Procedures	45
Part II – Other Information
Item 1 – Legal Proceedings	46
Item 1A – Risk Factors	46
Item 2 – Unregistered Sales of Equity Securities and Use of Proceeds	46
Item 3 – Defaults Upon Senior Securities	46
Item 4 – Mine Safety Disclosures	46
Item 5 – Other Information	46
Item 6 – Exhibits	47
Signature	49

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)
	September 30, 2014		December 31, 2013
	(unaudited)
Assets
Current assets:
Cash and cash equivalents	$	0.1	$	2.7
Accounts receivable	312.8		205.1
Inventory	8.3		7.0
Prepaid expenses and other current assets	20.3		10.2
Total current assets	341.5		225.0
Property, plant and equipment (Note 3)	3,812.9		3,565.7
Less: accumulated depreciation and depletion	313.3		215.6
Property, plant and equipment, net	3,499.6		3,350.1
Intangible assets (Note 3)	1,034.4		1,025.1
Less: accumulated amortization	113.6		54.3
Intangible assets, net	920.8		970.8
Goodwill	1,681.4		1,682.8
Investment in unconsolidated affiliates (Note 5)	231.9		151.4
Other assets	19.4		21.7
Total assets	$	6,694.6	$	6,401.8
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	193.2	$	154.5
Accounts payable - related party (Note 11)	7.4		8.7
Accrued expenses and other liabilities	165.1		148.4
Current portion of long-term debt (Note 7)	0.6		2.9
Total current liabilities	366.3		314.5
Long-term debt, less current portion (Note 7)	1,893.0		1,867.9
Other long-term liabilities	30.0		26.3
Commitments and contingencies (Note 10)
Partners’ capital (Note 8):
Class A preferred units (14,940,238 units issued and outstanding at September 30, 2014)	377.0		—
Partners’ capital (187,956,285 and 187,243,989 limited partner units issued and outstanding at September 30, 2014 and December 31, 2013)	3,862.1		4,092.1
Total Crestwood Midstream Partners LP partners’ capital	4,239.1		4,092.1
Interest of non-controlling partners in subsidiary	166.2		101.0
Total partners’ capital	4,405.3		4,193.1
Total liabilities and partners’ capital	$	6,694.6	$	6,401.8

See accompanying notes.

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						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Revenues:
Gathering and processing	$	83.9		$	47.0		$	245.2		$	140.3
Storage and transportation	44.2			42.1			133.9			47.6
NGL and crude services	605.4			23.5			1,558.8			26.6
Related party (Note 11)	4.9			27.5			13.2			78.1
	738.4			140.1			1,951.1			292.6
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	7.3			5.3			22.8			18.2
Storage and transportation	4.3			4.0			11.3			4.4
NGL and crude services	552.8			9.7			1,426.7			10.6
Related party (Note 11)	11.3			7.6			32.1			22.2
	575.7			26.6			1,492.9			55.4
Expenses:
Operations and maintenance	39.4			21.7			100.1			48.1
General and administrative	18.2			25.2			63.6			44.0
Depreciation, amortization and accretion	55.5			35.1			161.2			73.4
	113.1			82.0			324.9			165.5
Other operating income (expense):
Goodwill impairment	—			(4.1		)	—			(4.1		)
Gain (loss) on long-lived assets, net	(0.9		)	4.4			0.7			4.4
Loss on contingent consideration (Note 10)	—			—			(8.6		)	—
Operating income	48.7			31.8			125.4			72.0
Earnings (loss) from unconsolidated affiliates, net	0.3			(0.4		)	(1.3		)	(0.4		)
Interest and debt expense, net	(27.7		)	(19.5		)	(84.8		)	(43.4		)
Income before income taxes	21.3			11.9			39.3			28.2
Provision for income taxes	—			0.3			0.8			1.0
Net income	21.3			11.6			38.5			27.2
Net income attributable to non-controlling partners	(4.5		)	(1.9		)	(11.3		)	(1.9		)
Net income attributable to Crestwood Midstream Partners LP	16.8			9.7			27.2			25.3
Net income attributable to Class A preferred units	(9.1		)	—			(10.2		)	—
Net income attributable to partners	$	7.7		$	9.7		$	17.0		$	25.3
General partner's interest in net income	$	7.5		$	6.3		$	22.5		$	19.3
Limited partners’ interest in net income (loss)	$	0.2		$	3.4		$	(5.5	)	$	6.0
Net income (loss) per limited partner unit:
Basic	$	—		$	0.02		$	(0.03	)	$	0.06
Diluted	$	—		$	0.02		$	(0.03	)	$	0.06
Weighted-average limited partners’ units outstanding (in thousands):
Basic	187,955			161,575			187,931			101,094
Diluted	187,955			161,575			187,931			101,094

See accompanying notes.

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	—		(31.4		)	—		(31.4		)
Distributions to limited partners	—		(222.4		)	—		(222.4		)
Unit-based compensation charges	—		13.9			—		13.9
Issuance of Class A preferred units	366.8		—			—		366.8
Issuance of preferred equity of subsidiary	—		—			53.9		53.9
Taxes paid for unit-based compensation vesting	—		(1.5		)	—		(1.5		)
Other	—		(0.6		)	—		(0.6		)
Net income	10.2		17.0			11.3		38.5
Balance at September 30, 2014	$	377.0	$	3,862.1		$	166.2	$	4,405.3

See accompanying notes.

5

CRESTWOOD MIDSTREAM PARTNERS LP (FORMERLY INERGY MIDSTREAM, L.P.) CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) (unaudited)
	Nine Months Ended
	September 30,
	2014			2013
Operating activities
Net income	$	38.5		$	27.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion	161.2			73.4
Amortization of debt-related deferred costs and premiums	5.5			3.1
Unit-based compensation charges	13.9			6.5
Goodwill impairment	—			4.1
Gain on long-lived assets	(0.7		)	(4.4		)
Loss on contingent consideration	8.6			—
Loss from unconsolidated affiliates, net	1.3			0.4
Deferred income taxes	0.5			—
Changes in operating assets and liabilities, net of effects from acquisitions	(53.0		)	20.2
Net cash provided by operating activities	175.8			130.5
Investing activities
Acquisitions, net of cash acquired (Note 4)	(19.5		)	0.2
Purchases of property, plant and equipment	(259.3		)	(189.4		)
Investment in unconsolidated affiliates	(81.8		)	(152.5		)
Proceeds from sale of assets	—			11.0
Net cash used in investing activities	(360.6		)	(330.7		)
Financing activities
Proceeds from the issuance of long-term debt	1,410.9			577.2
Principal payments on long-term debt	(1,390.8		)	(568.5		)
Payments on capital leases	(2.6		)	(3.0		)
Payments for debt-related deferred costs	(0.1		)	(0.1		)
Distributions to limited partners	(222.4		)	(110.1		)
Distributions to general partner	(31.4		)	(17.1		)
Distributions for additional interest in Crestwood Marcellus Midstream LLC	—			(129.0		)
Contributions from general partner	—			5.4
Net proceeds from issuance of limited partner units	—			356.7
Net proceeds from issuance of preferred equity of subsidiary	53.9			96.1
Net proceeds from the issuance of Class A preferred units	366.8			—
Taxes paid for unit-based compensation vesting	(1.5		)	(0.7		)
Other	(0.6		)	0.1
Net cash provided by financing activities	182.2			207.0
Net change in cash	(2.6		)	6.8
Cash at beginning of period	2.7			0.1
Cash at end of period	$	0.1		$	6.9
Supplemental schedule of non-cash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(8.1	)	$	31.9

See accompanying notes.

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 September 30, 2014, Crestwood Equity Partners LP (CEQP), which owns our general partner, owns our non-economic general partnership interest, approximately 4% of our common limited partnership units 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 distribution 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 September 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) in New York and Pennsylvania and our 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 NGLs and crude oil gathering, storage, marketing 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 under development 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. 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 September 30, 2014, and for the three and nine months endedSeptember 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 accounting principles generally accepted in the United States of America (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 Securities and Exchange Commission (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 nine months endedSeptember 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 recasted 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 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.

New Accounting Pronouncement Issued But Not Yet Adopted

As of September 30, 2014, the following accounting standard had 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 current revenue recognition guidance. We will adopt the provisions of this standard effective January 1, 2017 and 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 September 30, 2014 and December 31, 2013 (in millions):

	September 30, 2014		December 31, 2013
Gathering systems and pipelines	1,251.9		1,231.1
Facilities and equipment	1,378.5		1,041.0
Buildings, land, rights-of-way, storage contracts and easements	783.4		766.2
Vehicles	13.8		4.1
Construction in process	221.3		360.5
Base gas	37.3		36.3
Salt deposits	120.5		120.5
Office furniture and fixtures	6.2		6.0
	3,812.9		3,565.7
Less: accumulated depreciation and depletion	313.3		215.6
Total property, plant and equipment, net	$	3,499.6	$	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 $3.0 million and $5.0 million included in property, plant and equipment, net at September 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 September 30, 2014 and December 31, 2013 (in millions):

	September 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	113.6		54.3
Total intangible assets, net	$	920.8	$	970.8

Accrued Expenses and Other Liabilities

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

	September 30, 2014		December 31, 2013
Accrued expenses	$	31.9	$	20.0
Accrued property taxes	5.6		7.6
Accrued product purchases payable	1.4		1.6
Tax payable	0.9		10.6
Interest payable	27.4		14.9
Accrued additions to property, plant and equipment	45.8		58.1
Commitments and contingent liabilities (Note 10)	40.0		31.4
Capital leases	1.5		2.6
Deferred revenue	10.6		1.6
Total accrued expenses and other liabilities	$	165.1	$	148.4

Note 4 – Acquisitions and Divestitures

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 nine months endedSeptember 30, 2014. In addition, transaction costs related to these acquisitions were not material for the three and nine months endedSeptember 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. 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 Crestwood and Legacy Inergy.  During the period from June 19, 2013 to September 30, 2013, we recognized $78.0 million of revenues and $7.1 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. 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 three and nine months endedSeptember 30, 2014, we also recognized approximately $0.2 million and $5.4 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 Arrow Acquisition had been included in our consolidated results for the full three and nine months endedSeptember 30, 2013, and as if the results for Legacy Inergy reverse acquisition had been included for the entire nine months endedSeptember 30, 2013 (in millions, except per unit information):

	Three Months Ended		Nine Months Ended
	September 30, 2013		September 30, 2013
Revenues	$	601.2	$	1,526.8
Net income	$	9.6	$	27.2
Net income per limited partner unit(1):
Basic	$	0.02	$	0.07
Diluted	$	0.02	$	0.07

(1) Basic and diluted net income per limited partner unit for the three and nine months endedSeptember 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.

Divestitures

On July 25, 2013, we sold a cryogenic plant and associated equipment for approximately $11.0 million (net of fees) and recognized a gain of approximately $4.4 million during the three months ended September 30, 2013.

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

Crestwood Niobrara acquired its interest in Jackalope in July 2013 for approximately $107.5 million. During the nine months endedSeptember 30, 2014 and 2013, Crestwood Niobrara contributed $78.3 million and $20.6 million to Jackalope to fund its construction projects.

Our investment in Jackalope was $205.6 million and $127.2 million at September 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 Jackalope's net earnings based on our ownership interest and other adjustments recorded by us as discussed below. Our share of Jackalope’s net earnings was approximately $1.2 million and $0.2 million for the three months endedSeptember 30, 2014 and 2013 and $2.4 million and $0.2 million for the nine months endedSeptember 30, 2014 and 2013. As of September 30, 2014, our investment balance in Jackalope exceeded our equity in the underlying net assets of Jackalope by approximately $54.5 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 we recorded amortization expense of approximately $0.8 million and $0.6 million for the three months ended September 30, 2014 and 2013 and $2.3 million and $0.6 million for the nine months endedSeptember 30, 2014 and 2013.

Jackalope is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the nine months endedSeptember 30, 2014 and 2013, Jackalope did not make any distributions to its members.

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

Crestwood Logistics acquired its interest in PRBIC in September 2013 for approximately $22.5 million. During the nine months endedSeptember 30, 2014 and 2013, Crude Logistics contributed approximately $3.5 million and $1.9 million to PRBIC to fund its construction projects.

Our investment in PRBIC was $26.3 million and $24.2 million at September 30, 2014 and December 31, 2013. During the three and nine months endedSeptember 30, 2014, our share of PRBIC’s loss was approximately $0.1 million and $1.4 million. As of September 30, 2014, our investment balance in PRBIC approximated our equity in the underlying net assets of PRBIC. Our share of PRBIC’s net earnings was not material for the three months ended September 30, 2013.

PRBIC is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the nine months endedSeptember 30, 2014 and 2013, PRBIC did not make any distributions to its members.

13

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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 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 CMLP and the (ii) net income attributable to CMLP per limited partner unit based on the number of basic and diluted limited partner units outstanding for the three and nine months endedSeptember 30, 2014 and 2013 (in millions):

Allocation of Net Income Attributable to CMLP
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Net income attributable to CMLP	$	16.8		$	9.7		$	27.2		$	25.3
Class A preferred units interest in net income attributable to CMLP	(9.1		)	—			(10.2		)	—
General partner’s incentive distributions	(7.5		)	(6.2		)	(22.5		)	(18.9		)
General partner’s interest in net income attributable to CMLP	—			(0.1		)	—			(0.4		)
Limited partners’ interest in net income (loss) attributable to CMLP	$	0.2		$	3.4		$	(5.5	)	$	6.0

Earnings Per Limited Partner Unit
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014			2013
Limited partners’ interest in net income (loss)	$	0.2	$	3.4	$	(5.5	)	$	6.0
Weighted-average limited partner units - basic	188.0		161.6		187.9			101.1
Effect of diluted units	—		—		—			—
Weighted-average limited partner units - diluted	188.0		161.6		187.9			101.1
Basic earnings per unit:
Net income (loss) per limited partner	$	—	$	0.02	$	(0.03	)	$	0.06
Diluted earnings per unit:
Net income (loss) per limited partner	$	—	$	0.02	$	(0.03	)	$	0.06

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 nine months endedSeptember 30, 2014, we excluded a weighted-average of 7,191,463 and 5,984,792 common units, representing Crestwood Niobrara's preferred units if converted to common units, from our diluted earnings per unit. During the three and nine months endedSeptember 30, 2014, we also excluded a weighted-average of 12,244,500 and 4,739,285 common units, representing Class A preferred units if converted to common units, from our diluted earnings per unit. During the three and nine months endedSeptember 30, 2013, we excluded a weighted-average of 3,262,275 and 1,099,375 common units,

14

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

representing Crestwood Niobrara's preferred units if converted to common units, from our diluted earnings per unit. 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 September 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.

During the three months endedSeptember 30, 2014, we began entering into daily and short-term forward crude purchase and sale agreements in our NGL and crude services segment related to available capacity on our crude contracts and facilities associated with our operations located in the Bakken and PRB Niobrara Shale plays.

As of September 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 September 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):

	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2019 Senior Notes	$	351.0	$	369.5	$	351.2	$	379.3
2020 Senior Notes	$	504.1	$	507.9	$	504.7	$	513.8
2022 Senior Notes	$	600.0	$	603.0	$	600.0	$	617.3

15

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Long-Term Debt

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

	September 30, 2014		December 31, 2013
Credit Facility	$	435.0	$	414.9
2019 Senior Notes	350.0		350.0
Premium on 2019 Senior Notes	1.0		1.2
2020 Senior Notes	500.0		500.0
Fair value adjustment of 2020 Senior Notes	4.1		4.7
2022 Senior Notes	600.0		600.0
Other	3.5		—
Total debt	1,893.6		1,870.8
Less: current portion	0.6		2.9
Total long-term debt	$	1,893.0	$	1,867.9

Credit Facility

We have a five-year $1 billion senior secured revolving credit facility due in October 2018 (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 September 30, 2014, the balance outstanding on our Credit Facility was $435.0 million and outstanding standby letters of credit were $84.1 million. We had $227.0 million of available capacity under the revolving credit facility at September 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 2.91% and 5.00% at September 30, 2014. The weighted-average interest rate as of September 30, 2014 was 2.92%.

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 to 1.0 and an interest coverage ratio (as defined in our credit agreement) of not less than 2.50 to 1.0. At September 30, 2014, our net debt to consolidated EBITDA (as defined in our credit agreement) was approximately 4.46 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 3.86 to 1.0.

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.

16

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

On July 17, 2014, we filed a registration statement with the SEC under which we offered 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. We completed the exchange offer on August 29, 2014. The terms of the exchange notes are substantially identical to the terms of the 2022 Senior Notes, except that the exchange notes are freely tradable.

At September 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.

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 as of September 30, 2014 and through the date of this filing. 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 $31.4 million and $17.1 million during the nine months endedSeptember 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.

17

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

On July 23, 2014 and October 22, 2014, the board of directors of our general partner authorized the issuance of 42,523 and 345,471 Preferred Units to our Preferred Unit holders for the quarters ended June 30, 2014 and September 30, 2014 in lieu of paying a cash distribution. In accordance with our partnership agreement, the additional Preferred Units will be issued in November 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 nine months endedSeptember 30, 2014:

Nine Months Ended September 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
August 7, 2014	August 14, 2014	$	0.41	74.1
				$	222.4

The following table presents quarterly cash distributions associated with Legacy Crestwood and Legacy Inergy paid to the limited partners (excluding distributions paid to the general partner on its common units held) during the nine months ended ended September 30, 2013:

Nine Months Ended September 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
August 1, 2013	August 9, 2013	$	0.51	27.4
August 7, 2013	August 14, 2013	$	0.40	34.3		(1)
				$	110.1

(1) Represents distributions associated with Legacy Inergy limited partner units.

On October 22, 2014, we declared a distribution of $0.41 per limited partner unit to be paid on November 14, 2014, to unitholders of record on November 7, 2014 with respect to the third 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). On September 22, 2014, the Class A Purchasers purchased 2,988,047 Preferred Units for a cash purchase price of $25.10 per unit resulting in gross proceeds to us of approximately $75.0 million (net proceeds of approximately $73.1 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

18

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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. We allocated net income to the non-controlling interest based on the overall return attributable to the preferred security of approximately $4.5 million and $1.9 million during the three months endedSeptember 30, 2014 and 2013, and $11.3 million and $1.9 million during the nine months endedSeptember 30, 2014 and 2013.

Pursuant to Crestwood Niobrara's agreement with GE, GE made capital contributions to Crestwood Niobrara in exchange for an equivalent number of preferred units. During the three months endedSeptember 30, 2014 and 2013, GE made capital contributions of $20.3 million and $96.1 million to Crestwood Niobrara. During the nine months endedSeptember 30, 2014 and 2013, GE made capital contributions of $53.9 million and $96.1 million to Crestwood Niobrara. As of September 30, 2014, GE has fulfilled its capital contribution commitment to Crestwood Niobrara of $150.0 million and is no longer required to make quarterly contributions to Crestwood Niobrara.

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 and nine months endedSeptember 30, 2014, Crestwood Niobrara issued 3,073,357 and 7,819,661 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 October 31, 2014,Crestwood Niobrara issued 3,599,580 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 statement of cash flows for the nine months endedSeptember 30, 2013.

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.

19

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

During 2014, we have issued restricted unit awards, which were approved by either CMLP's Board compensation committee or pursuant to the authority granted by the Chief Executive Officer, to certain key employees. These awards vest upon continued service with the Company.

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

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	250,557		$	22.13
Vested - restricted units	(190,818	)	$	22.16
Granted - restricted units	838,036		$	23.31
Forfeited	(57,208	)	$	23.49
Unvested - September 30, 2014	840,567		$	23.21

As of September 30, 2014 and December 31, 2013, we had total unamortized compensation expense of approximately $11.6 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. We recognized compensation expense of approximately $2.5 million and $1.7 million during the three months ended September 30, 2014 and 2013 and $8.7 million and $3.2 million during the nine months endedSeptember 30, 2014 and 2013, which is included in general and administrative expenses on our consolidated statements of operations. An additional $1.6 million and $5.2 million of net compensation expense was allocated from CEQP to us during the three and nine months endedSeptember 30, 2014 and an additional $3.1 million and $3.3 million was allocated from CEQP to us during the three and nine months endedSeptember 30, 2013 (see Note 11). We granted restricted units with a grant date fair value of approximately $19.5 million during the nine months endedSeptember 30, 2014.  As of September 30, 2014, we had 6,430,021 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 endedSeptember 30, 2013, we withheld 912 common units and during the nine months endedSeptember 30, 2014 and 2013, we withheld 68,532 and 3,341 common units to satisfy employee tax withholding obligations. There were no common units withheld during the three months endedSeptember 30, 2014.

Employee Unit Purchase Plan

Beginning in September 2014, the board of directors of our general partner made available an employee unit purchase plan under which employees of the general partner may purchase CMLP units through payroll deductions up to a maximum of 10 percent of the employees' eligible compensation. Under the plan, CMLP may purchase its units on the open market for the benefit of participating employees based on their payroll deductions.  In addition, CMLP may contribute an additional 10 percent of participating employees' payroll deductions to purchase additional CMLP units for participating employees. Unless increased by the board of directors of our general partner, the maximum number of units that may be purchased under the plan is 200,000.

Note 10 - Commitments and Contingencies

Legal Proceedings

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

20

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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.  We anticipate a ruling from the Judge on Petitioners' motion to authorize the class action by the end of November 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 September 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

During the three months endedSeptember 30, 2014, we experienced two releases totaling approximately 28,000 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 releases completely and placed the impacted segments of these water lines back into service during the third quarter of2014. During the three months endedSeptember 30, 2014, we recognized $3.7 million of operations and maintenance expense related to these releases, of which $1.7 million was included in other current liabilities on our balance sheet as of September 30, 2014. We will continue our remediation efforts to ensure the impacted lands are restored to their prior state, and we may potentially be subject to fines and penalties. As of September 30, 2014, we had no amounts accrued for fines and penalties. We believe these releases are insurable events under our policies, and we have notified our carriers of these events; however, we have not recorded an insurance receivable as of September 30, 2014.

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

21

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At September 30, 2014, our accrual of approximately $1.7 million was primarily related to the Arrow water releases described above, which is based on our undiscounted estimate of amounts we will spend on compliance with environmental and other regulations. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures (including the Arrow water releases described above) could range from approximately $1.7 million to $2.1 million. Our accrual and potential exposure related to our environmental matters was immaterial at December 31, 2013.

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 $40.0 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 September 30, 2014 and December 31, 2013, which we anticipate paying in the first quarter of 2015.

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 $14.0 million and $42.7 million of costs for the three and nine months endedSeptember 30, 2014. Included in this amount was $1.6 million and $5.2 million of net unit-based compensation charges for the three and nine months endedSeptember 30, 2014. During the three and nine months endedSeptember 30, 2013, CEQP allocated to us $5.0 million and $5.5 million of costs, including $3.1 million and $3.3 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 nine months endedSeptember 30, 2014 and 2013 (in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014(1)		2013		2014(1)		2013
Gathering and processing revenues	$	1.4	$	24.1	$	3.0	$	74.3
NGL and crude services revenues	$	3.5	$	3.4	$	10.2	$	3.8
Gathering and processing costs of product/services sold	$	11.3	$	7.6	$	32.1	$	22.2
General and administrative expenses	$	4.5	$	5.9	$	12.8	$	16.5

(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.

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

	September 30, 2014		December 31, 2013
Accounts receivable	$	2.8	$	1.1
Accounts payable	$	7.4	$	8.7

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

22

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 12 - Segments

Financial Information

We have three operating and reportable 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 NGLs and crude oil gathering, storage, marketing 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				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
Net income	$	21.3	$	11.6	$	38.5	$	27.2
Add:
Interest and debt expense, net	27.7		19.5		84.8		43.4
Provision for income taxes	—		0.3		0.8		1.0
Depreciation, amortization and accretion	55.5		35.1		161.2		73.4
EBITDA	$	104.5	$	66.5	$	285.3	$	145.0

23

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

	Three Months Ended September 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	85.3		$	44.2	$	608.9		$	—		$	738.4
Costs of product/services sold	18.6			4.3		552.8			—			575.7
Operations and maintenance expense	15.9			4.2		19.3			—			39.4
General and administrative expense	—			—		—			18.2			18.2
Loss on long-lived assets	(0.9		)	—		—			—			(0.9		)
Earnings (loss) from unconsolidated affiliates, net	0.4			—		(0.1		)	—			0.3
EBITDA	$	50.3		$	35.7	$	36.7		$	(18.2	)	$	104.5
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	2,026.1		$	1,951.2	$	2,553.7		$	163.6		$	6,694.6
Cash expenditures for property, plant and equipment	$	57.5		$	2.2	$	34.8		$	0.1		$	94.6

	Three Months Ended September 30, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services		Corporate			Total
Revenues	$	71.1		$	42.1	$	26.9	$	—		$	140.1
Costs of product/services sold	12.9			4.0		9.7		—			26.6
Operations and maintenance expense	14.9			4.7		2.1		—			21.7
General and administrative expense	—			—		—		25.2			25.2
Goodwill impairment	(4.1		)	—		—		—			(4.1		)
Gain on long-lived assets	4.4			—		—		—			4.4
Loss from unconsolidated affiliates, net	(0.4		)	—		—		—			(0.4		)
EBITDA	$	43.2		$	33.4	$	15.1	$	(25.2	)	$	66.5
Goodwill	$	99.6		$	744.1	$	609.1	$	—		$	1,452.8
Total assets	$	1,856.0		$	2,003.0	$	1,257.4	$	46.4		$	5,162.8
Cash expenditures for property, plant and equipment	$	84.1		$	5.7	$	16.0	$	0.1		$	105.9

24

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

	Nine Months Ended September 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	248.2		$	133.9	$	1,569.0		$	—		$	1,951.1
Costs of product/services sold	54.9			11.3		1,426.7			—			1,492.9
Operations and maintenance expense	44.0			12.9		43.2			—			100.1
General and administrative expense	—			—		—			63.6			63.6
Gain on long-lived assets	0.1			0.6		—			—			0.7
Loss on contingent consideration	(8.6		)	—		—			—			(8.6		)
Earnings (loss) from unconsolidated affiliates, net	0.1			—		(1.4		)	—			(1.3		)
EBITDA	$	140.9		$	110.3	$	97.7		$	(63.6	)	$	285.3
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	2,026.1		$	1,951.2	$	2,553.7		$	163.6		$	6,694.6
Cash expenditures for property, plant and equipment	$	178.6		$	4.7	$	72.3		$	3.7		$	259.3

	Nine Months Ended September 30, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services		Corporate			Total
Revenues	$	214.6		$	47.6	$	30.4	$	—		$	292.6
Costs of product/services sold	40.4			4.4		10.6		—			55.4
Operations and maintenance expense	40.5			5.3		2.3		—			48.1
General and administrative expense	—			—		—		44.0			44.0
Goodwill impairment	(4.1		)	—		—		—			(4.1		)
Gain on long-lived assets	4.4			—		—		—			4.4
Loss from unconsolidated affiliates, net	(0.4		)	—		—		—			(0.4		)
EBITDA	$	133.6		$	37.9	$	17.5	$	(44.0	)	$	145.0
Goodwill	$	99.6		$	744.1	$	609.1	$	—		$	1,452.8
Total assets	$	1,856.0		$	2,003.0	$	1,257.4	$	46.4		$	5,162.8
Cash expenditures for property, plant and equipment	$	164.0		$	7.9	$	17.0	$	0.5		$	189.4

Note 13 – Condensed Consolidating Financial Information

Crestwood is a holding company and owns no operating assets and has no significant operations independent of its 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 (collectively, 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 September 30, 2014 and December 31, 2013, and for the three and nine months endedSeptember 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.

25

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Balance Sheet
September 30, 2014
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—	$	0.1		$	—	$	—		$	0.1
Accounts receivable	579.1		295.4			0.1		(561.8		)	312.8
Inventories	—		8.3			—		—			8.3
Other current assets	—		20.3			—		—			20.3
Total current assets	579.1		324.1			0.1		(561.8		)	341.5
Property, plant and equipment, net	5.9		3,493.7			—		—			3,499.6
Goodwill and intangible assets, net	—		2,602.2			—		—			2,602.2
Investment in consolidated affiliates	6,571.5		—			—		(6,571.5		)	—
Investment in unconsolidated affiliates	—		—			231.9		—			231.9
Other assets	—		19.4			—		—			19.4
Total assets	$	7,156.5	$	6,439.4		$	232.0	$	(7,133.3	)	$	6,694.6
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	855.5	$	(93.2	)	$	0.1	$	(561.8	)	$	200.6
Other current liabilities	1.0		164.7			—		—			165.7
Total current liabilities	856.5		71.5			0.1		(561.8		)	366.3
Long-term liabilities:
Long-term debt, less current portion	1,893.0		—			—		—			1,893.0
Other long-term liabilities	1.7		28.3			—		—			30.0
Total long-term liabilities	1,894.7		28.3			—		—			1,923.0
Partners' capital	4,239.1		6,339.6			65.7		(6,405.3		)	4,239.1
Interest of non-controlling partners in subsidiaries	166.2		—			166.2		(166.2		)	166.2
Total partners' capital	4,405.3		6,339.6			231.9		(6,571.5		)	4,405.3
Total liabilities and partners' capital	$	7,156.5	$	6,439.4		$	232.0	$	(7,133.3	)	$	6,694.6

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 September 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	83.9		$	—		$	—		$	83.9
Storage and transportation	—			44.2			—			—			44.2
NGL and crude services	—			605.4			—			—			605.4
Related party	—			4.9			—			—			4.9
	—			738.4			—			—			738.4
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			7.3			—			—			7.3
Storage and transportation	—			4.3			—			—			4.3
NGL and crude services	—			552.8			—			—			552.8
Related party	—			11.3			—			—			11.3
	—			575.7			—			—			575.7
Expenses:
Operations and maintenance	—			39.4			—			—			39.4
General and administrative	(0.8		)	19.0			—			—			18.2
Depreciation, amortization and accretion	0.3			55.2			—			—			55.5
	(0.5		)	113.6			—			—			113.1
Other operating income (expense):
Other	—			(0.9		)	—			—			(0.9		)
Operating income	0.5			48.2			—			—			48.7
Interest and debt expense, net	(27.8		)	0.1			—			—			(27.7		)
Equity in net income (loss) of subsidiary	48.6			—			—			(48.6		)	—
Other	—			—			0.3			—			0.3
Income (loss) before income taxes	21.3			48.3			0.3			(48.6		)	21.3
Provision for income taxes	—			—			—			—			—
Net income (loss)	21.3			48.3			0.3			(48.6		)	21.3
Net income attributable to non-controlling partners	—			—			(4.5		)	—			(4.5		)
Net income (loss) attributable to Crestwood Midstream Partners LP	21.3			48.3			(4.2		)	(48.6		)	16.8
Net income attributable to Class A preferred units	(9.1		)	—			—			—			(9.1		)
Net income (loss) attributable to partners	$	12.2		$	48.3		$	(4.2	)	$	(48.6	)	$	7.7

28

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Three Months Ended September 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	47.0		$	—		$	—		$	47.0
Storage and transportation	—			42.1			—			—			42.1
NGL and crude services	—			23.5			—			—			23.5
Related party	—			27.5			—			—			27.5
	—			140.1			—			—			140.1
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			5.3			—			—			5.3
Storage and transportation	—			4.0			—			—			4.0
NGL and crude services	—			9.7			—			—			9.7
Related party	—			7.6			—			—			7.6
	—			26.6			—			—			26.6
Expenses:
Operations and maintenance	—			21.7			—			—			21.7
General and administrative	9.4			15.8			—			—			25.2
Depreciation, amortization and accretion	0.2			34.9			—			—			35.1
	9.6			72.4			—			—			82.0
Other operating income (expense):
Other	—			0.3			—			—			0.3
Operating income (loss)	(9.6		)	41.4			—			—			31.8
Interest and debt expense, net	(18.4		)	(1.1		)	—			—			(19.5		)
Equity in net income (loss) of subsidiary	39.6			—			—			(39.6		)	—
Other	—			—			(0.4		)	—			(0.4		)
Income (loss) before income taxes	11.6			40.3			(0.4		)	(39.6		)	11.9
Provision for income taxes	—			0.3			—			—			0.3
Net income (loss)	11.6			40.0			(0.4		)	(39.6		)	11.6
Net income attributable to non-controlling partners	—			—			(1.9		)	—			(1.9		)
Net income (loss) attributable to Crestwood Midstream Partners LP	$	11.6		$	40.0		$	(2.3	)	$	(39.6	)	$	9.7

29

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Nine Months Ended September 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	245.2		$	—		$	—		$	245.2
Storage and transportation	—			133.9			—			—			133.9
NGL and crude services	—			1,558.8			—			—			1,558.8
Related party	—			13.2			—			—			13.2
	—			1,951.1			—			—			1,951.1
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			22.8			—			—			22.8
Storage and transportation	—			11.3			—			—			11.3
NGL and crude services	—			1,426.7			—			—			1,426.7
Related party	—			32.1			—			—			32.1
	—			1,492.9			—			—			1,492.9
Expenses:
Operations and maintenance	—			100.1			—			—			100.1
General and administrative	(3.8		)	67.4			—			—			63.6
Depreciation, amortization and accretion	0.7			160.5			—			—			161.2
	(3.1		)	328.0			—			—			324.9
Other operating income (expense):
Loss on contingent consideration	—			(8.6		)	—			—			(8.6		)
Other	—			0.7			—			—			0.7
Operating income	3.1			122.3			—			—			125.4
Interest and debt expense, net	(85.1		)	0.3			—			—			(84.8		)
Equity in net income (loss) of subsidiary	120.5			—			—			(120.5		)	—
Other	—			—			(1.3		)	—			(1.3		)
Income (loss) before income taxes	38.5			122.6			(1.3		)	(120.5		)	39.3
Provision for income taxes	—			0.8			—			—			0.8
Net income (loss)	38.5			121.8			(1.3		)	(120.5		)	38.5
Net income attributable to non-controlling partners	—			—			(11.3		)	—			(11.3		)
Net income (loss) attributable to Crestwood Midstream Partners LP	38.5			121.8			(12.6		)	(120.5		)	27.2
Net income attributable to Class A preferred units	(10.2		)	—			—			—			(10.2		)
Net income (loss) attributable to partners	$	28.3		$	121.8		$	(12.6	)	$	(120.5	)	$	17.0

30

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Nine Months Ended September 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	140.3		$	—		$	—		$	140.3
Storage and transportation	—			47.6			—			—			47.6
NGL and crude services	—			26.6			—			—			26.6
Related party	—			78.1			—			—			78.1
	—			292.6			—			—			292.6
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			18.2			—			—			18.2
Storage and transportation	—			4.4			—			—			4.4
NGL and crude services	—			10.6			—			—			10.6
Related party	—			22.2			—			—			22.2
	—			55.4			—			—			55.4
Expenses:
Operations and maintenance	—			48.1			—			—			48.1
General and administrative	24.0			20.0			—			—			44.0
Depreciation, amortization and accretion	0.6			72.8			—			—			73.4
	24.6			140.9			—			—			165.5
Other operating income (expense):
Other	—			0.3			—			—			0.3
Operating income (loss)	(24.6		)	96.6			—			—			72.0
Interest and debt expense, net	(39.9		)	(3.5		)	—			—			(43.4		)
Equity in net income (loss) of subsidiary	91.7			—			—			(91.7		)	—
Other	—			—			(0.4		)	—			(0.4		)
Income (loss) before income taxes	27.2			93.1			(0.4		)	(91.7		)	28.2
Provision for income taxes	—			1.0			—			—			1.0
Net income (loss)	27.2			92.1			(0.4		)	(91.7		)	27.2
Net income attributable to non-controlling partners	—			—			(1.9		)	—			(1.9		)
Net income (loss) attributable to Crestwood Midstream Partners LP	$	27.2		$	92.1		$	(2.3	)	$	(91.7	)	$	25.3

31

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(27.6	)	$	203.4		$	—		$	—		$	175.8
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(19.5		)	—			—			(19.5		)
Purchases of property, plant and equipment	(3.7		)	(255.6		)	—			—			(259.3		)
Investment in unconsolidated affiliates	—			(3.5		)	(78.3		)	—			(81.8		)
Capital contribution from consolidated affiliates	(23.4		)	(3.5		)	—			26.9			—
Net change in receivables from affiliates	(313.7		)	—			—			313.7			—
Net cash provided by (used in) investing activities	(340.8		)	(282.1		)	(78.3		)	340.6			(360.6		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2.5			1,408.4			—			—			1,410.9
Principal payments on long-term debt	—			(1,390.8		)	—			—			(1,390.8		)
Distributions paid	—			(253.8		)	—			—			(253.8		)
Contributions from parent	—			3.5			23.4			(26.9		)	—
Net proceeds from issuance of preferred equity of subsidiary	—			—			53.9			—			53.9
Net proceeds from issuance of Class A preferred units	366.8			—			—			—			366.8
Payments on capital leases	(0.9		)	(1.7		)	—			—			(2.6		)
Taxes paid for unit-based compensation vesting	—			(1.5		)	—			—			(1.5		)
Payments for debt-related deferred costs	(0.1		)	—			—			—			(0.1		)
Net change in payables to affiliates	—			313.7			—			(313.7		)	—
Other	—			(0.6		)	—			—			(0.6		)
Net cash provided by (used in) financing activities	368.3			77.2			77.3			(340.6		)	182.2
Net change in cash	(0.1		)	(1.5		)	(1.0		)	—			(2.6		)
Cash at beginning of period	0.1			1.6			1.0			—			2.7
Cash at end of period	$	—		$	0.1		$	—		$	—		$	0.1

32

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

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(18.7	)	$	183.0		$	—		$	(33.8	)	$	130.5
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			0.2			—			—			0.2
Purchases of property, plant and equipment	(0.5		)	(188.9		)	—			—			(189.4		)
Investment in unconsolidated affiliates	—			(24.4		)	(128.1		)	—			(152.5		)
Capital contribution from consolidated affiliates	(82.0		)	—			—			82.0			—
Proceeds from sale of assets	—			11.0			—			—			11.0
Net change in receivables from affiliates	57.4			—			—			(57.4		)	—
Net cash provided by (used in) investing activities	(25.1		)	(202.1		)	(128.1		)	24.6			(330.7		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	343.5			233.7			—			—			577.2
Principal payments on long-term debt	(194.0		)	(374.5		)	—			—			(568.5		)
Distributions paid	(90.3		)	(70.7		)	—			33.8			(127.2		)
Distributions for additional interest in Crestwood Marcellus Midstream LLC	(129.0		)	—			—			—			(129.0		)
Contributions from parent	—			55.4			32.0			(82.0		)	5.4
Net proceeds from issuance of common units	118.5			238.2			—			—			356.7
Net proceeds from issuance of preferred equity of subsidiary	—			—			96.1			—			96.1
Payments on capital leases	(0.3		)	(2.7		)	—			—			(3.0		)
Taxes paid for unit-based compensation vesting	—			(0.7		)	—			—			(0.7		)
Payments for debt-related deferred costs	(0.1		)	—			—			—			(0.1		)
Net change in payables to affiliates	—			(57.4		)	—			57.4			—
Other	—			0.1			—			—			0.1
Net cash provided by financing activities	48.3			21.4			128.1			9.2			207.0
Net change in cash	4.5			2.3			—			—			6.8
Cash at beginning of period	—			0.1			—			—			0.1
Cash at end of period	$	4.5		$	2.4		$	—		$	—		$	6.9

33

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 our 2013 Annual Report on Form 10-K of Crestwood Midstream Partners LP.

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.

For additional factors that could cause actual results to be materially different from those described in the forward-looking statements, see Part I, Item 1A. Risk Factors of our 2013 Annual Report on Form 10-K.

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, transportation and marketing operations, NGL storage facility and salt production business.

34

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 southwest portion of the Marcellus Shale, we have completed several expansions on our Antero gathering systems that have increased total gathering capacity. For the three and nine months ended September 30, 2014, we gathered approximately 645 MMcf/d and 587 MMcf/d on our Marcellus gathering systems. Antero continues to develop production in the Marcellus Shale to connect additional wells to our systems.

• 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 commissioned and placed into service in November 2014. During the three and nine months endedSeptember 30, 2014, gathering volumes on the Jackalope gas gathering system were 60 MMcf/d and 53 MMcf/d reflecting continued development by Chesapeake and RKI. Chesapeake continues to operate drilling rigs on our dedicated acreage and we expect to connect additional wells 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. In mid-July 2014, we substantially completed a Phase 2 expansion of our Willow Lake project which included a 20 MMcf/d cryogenic processing facility and expansion of 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 at a cost of approximately $19 million. We are also actively working with area producers, particularly those targeting the Bone Spring and Wolfcamp formations, for a potential Phase 3 expansion. 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 volumes remained relatively flat during the third quarter of 2014 with average quarterly gathering volumes of 419 MMcf/d. Volumes gathered for Quicksilver, Tokyo Gas and Eni S.p.A averaged 318 MMcf/d during the quarter ended September 30, 2014, a 2% decrease from the prior quarter. The decrease was largely attributable to the temporary shut-in of volumes during the third quarter of 2014 related to completion activities on newly drilled wells. Our remaining volumes gathered in the Barnett Shale during the quarter ended September 30, 2014 were primarily under contracts with Devon Energy Corporation. Quicksilver continues to operate a drilling rig and a workover rig on our Alliance gathering system. Quicksilver is current on all payments due to us to date.

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, providing access to the Marcellus Shale and key Northeast market locations.

We continued to experience high demand for storage and transportation services through September 30, 2014 due to continued growth in Marcellus Shale production and the strategic location of our facilities.  During the third quarter of 2014, total firm throughput from our storage and transportation services averaged approximately 1.6 Bcf/d. We are currently expanding our storage and transportation throughput on our Northeast storage and transportation assets to access total Marcellus dry gas supplies of approximately 3.3 Bcf/d. 

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.

35

On October 1, 2014, we announced a non-binding open season for the proposed MARC II Pipeline, a 30-mile greenfield natural gas pipeline designed to transport Marcellus dry gas to northeastern demand markets.  As proposed, the MARC II Pipeline would transport natural gas volumes approximately 30 miles from the southern terminus of our MARC I Pipeline to the proposed PennEast Pipeline, a new interconnect on Transcontinental Gas Pipe Line Company, LLC's (Transco) Leidy Line, and Transco’s proposed Atlantic Sunrise Expansion Project in Lucerne County, Pennsylvania.  On October 20, 2014, we concluded the open season and received non-binding expressions of interest for firm transportation service on the MARC II Pipeline in excess of 700 MMcf/d.  Subject to FERC authorization, sufficient binding shipper commitments, and certain other factors beyond our control, we anticipate an in-service date for the MARC II Pipeline in the fourth quarter of 2017.

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). Arrow producers continued to aggressively drill and complete wells on the Arrow gathering system. Crude oil, natural gas and produced water gathering volumes averaged 65 MBbls/d, 40 MMcf/d, and 20 MBbls/d, respectively, during the third quarter 2014. These volumes represent increases of 17%, 38%, and 6%, respectively, compared to the second quarter of 2014. In September 2014, we began construction of a 200,000 barrel crude oil storage tank on the Arrow gathering system. On September 1, 2014, the Tesoro High Plains Pipeline (THPP) was placed into service and we commenced shipping up to 10,000 Bbls/d of crude oil under our firm transportation agreement with THPP.

• COLT Hub (Bakken). In the first quarter of 2014, 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) and have since experienced continuing growth on the average daily loading volumes from 98,000 Bbls/d in the first quarter of 2014 to 117,000 Bbls/d during the third quarter of 2014. In October 2014, the COLT Hub loaded its 1,000th crude oil unit train located in North Dakota. We expect to complete the installation of a new release and departure track at the COLT Hub in November 2014, which will provide greater operational flexibility to our customers and the BNSF Railroad and consequently further improve utilization rates.

• Transportation Fleet (Bakken). We expect the Red Rock and LT Enterprises 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.  As we prepare for another colder-than-average winter in the Northeast, we remain optimistic that the political headwinds that have delayed our project over the past several quarters will subside following the mid-term election and the New York Department of Environmental Conservation (DEC) will be permitted to issue the approvals required for us to begin the project. On August 11, 2014, the DEC announced that it would convene an issues conference to determine if there are any significant and substantive issues that require an adjudicatory hearing.  The issues conference will be held in Horseheads, New York on February 12, 2015. We have approximately $35.4 million of costs related to the Finger Lakes NGL

36

storage facility included in property, plant and equipment on our balance sheet as of September 30, 2014, excluding goodwill associated with the facility.

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 and the impact of certain significant items, such as non-cash equity compensation expenses, gains and impairments of long-lived assets and goodwill, losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, 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.

37

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 September 30, 2013 reflect the operations of Legacy Crestwood for the entire period, and the operations of Legacy Inergy from June 19, 2013 to September 30, 2013. The following table summarizes our results of operations for the three and nine months endedSeptember 30, 2014 and 2013 (in millions):

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Revenues	$	738.4		$	140.1		$	1,951.1		$	292.6
Costs of product/services sold	575.7			26.6			1,492.9			55.4
Operations and maintenance expense	39.4			21.7			100.1			48.1
General and administrative expense	18.2			25.2			63.6			44.0
Depreciation, amortization and accretion	55.5			35.1			161.2			73.4
Goodwill impairment	—			(4.1		)	—			(4.1		)
Gain (loss) on long-lived assets, net	(0.9		)	4.4			0.7			4.4
Loss on contingent consideration	—			—			(8.6		)	—
Operating income	48.7			31.8			125.4			72.0
Earnings (loss) from unconsolidated affiliates, net	0.3			(0.4		)	(1.3		)	(0.4		)
Interest and debt expense, net	(27.7		)	(19.5		)	(84.8		)	(43.4		)
Provision for income taxes	—			(0.3		)	(0.8		)	(1.0		)
Net income	$	21.3		$	11.6		$	38.5		$	27.2
Add:
Interest and debt expense, net	27.7			19.5			84.8			43.4
Provision for income taxes	—			0.3			0.8			1.0
Depreciation, amortization and accretion	55.5			35.1			161.2			73.4
EBITDA	$	104.5		$	66.5		$	285.3		$	145.0
Non-cash equity compensation expense	4.1			4.8			13.9			6.5
(Gain) loss on long-lived assets, net	0.9			(4.4		)	(0.7		)	(4.4		)
Goodwill impairment	—			4.1			—			4.1
Loss on contingent consideration	—			—			8.6			—
(Earnings) loss from unconsolidated affiliates, net	(0.3		)	0.4			1.3			0.4
Adjusted EBITDA from unconsolidated affiliates, net	1.9			0.6			4.0			0.6
Significant transaction and environmental related costs and other items	5.1			13.3			12.4			18.8
Adjusted EBITDA	$	116.2		$	85.3		$	324.8		$	171.0

38

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
EBITDA:
Net cash provided by operating activities	$	80.4		$	62.0		$	175.8		$	130.5
Net changes in operating assets and liabilities	3.0			(9.4		)	53.0			(20.2		)
Amortization of debt-related deferred costs and premiums	(1.9		)	(1.1		)	(5.5		)	(3.1		)
Interest and debt expense, net	27.7			19.5			84.8			43.4
Non-cash equity compensation expense	(4.1		)	(4.8		)	(13.9		)	(6.5		)
Gain (loss) on long-lived assets, net	(0.9		)	4.4			0.7			4.4
Goodwill impairment	—			(4.1		)	—			(4.1		)
Loss on contingent consideration	—			—			(8.6		)	—
Earnings (loss) from unconsolidated affiliates, net	0.3			(0.4		)	(1.3		)	(0.4		)
Deferred income taxes	—			—			(0.5		)	—
Provision for income taxes	—			0.3			0.8			1.0
Other non-cash income	—			0.1			—			—
EBITDA	$	104.5		$	66.5		$	285.3		$	145.0
Non-cash equity compensation expense	4.1			4.8			13.9			6.5
(Gain) loss on long-lived assets, net	0.9			(4.4		)	(0.7		)	(4.4		)
Goodwill impairment	—			4.1			—			4.1
Loss on contingent consideration	—			—			8.6			—
(Earnings) loss from unconsolidated affiliates, net	(0.3		)	0.4			1.3			0.4
Adjusted EBITDA from unconsolidated affiliates, net	1.9			0.6			4.0			0.6
Significant transaction and environmental related costs and other items	5.1			13.3			12.4			18.8
Adjusted EBITDA	$	116.2		$	85.3		$	324.8		$	171.0

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

	Three Months Ended								Three Months Ended
	September 30, 2014								September 30, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Gathering and Processing			Storage and Transportation		NGL and Crude Services
Revenues	$	85.3		$	44.2	$	608.9		$	71.1		$	42.1	$	26.9
Costs of product/services sold	18.6			4.3		552.8			12.9			4.0		9.7
Operations and maintenance expense	15.9			4.2		19.3			14.9			4.7		2.1
Goodwill impairment	—			—		—			(4.1		)	—		—
Gain (loss) on long-lived assets, net	(0.9		)	—		—			4.4			—		—
Earnings (loss) from unconsolidated affiliates	0.4			—		(0.1		)	(0.4		)	—		—
EBITDA	$	50.3		$	35.7	$	36.7		$	43.2		$	33.4	$	15.1

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	Nine Months Ended								Nine Months Ended
	September 30, 2014								September 30, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Gathering and Processing			Storage and Transportation		NGL and Crude Services
Revenues	$	248.2		$	133.9	$	1,569.0		$	214.6		$	47.6	$	30.4
Costs of product/services sold	54.9			11.3		1,426.7			40.4			4.4		10.6
Operations and maintenance expense	44.0			12.9		43.2			40.5			5.3		2.3
Goodwill impairment	—			—		—			(4.1		)	—		—
Gain on long-lived assets	0.1			0.6		—			4.4			—		—
Loss on contingent consideration	(8.6		)	—		—			—			—		—
Earnings (loss) from unconsolidated affiliates	0.1			—		(1.4		)	(0.4		)	—		—
EBITDA	$	140.9		$	110.3	$	97.7		$	133.6		$	37.9	$	17.5

Segment Results

Below is a discussion of the factors that impacted EBITDA by segment as follows: (i) for the three and nine months endedSeptember 30, 2014 compared to the same periods in 2013 for our gathering and processing segment; and (ii) for the three months ended September 30, 2014 compared to the same period in 2013 for our storage and transportation and NGL and crude services segments.

Gathering and Processing

EBITDA for our G&P segment increased by approximately $7 million for both the three and nine months endedSeptember 30, 2014 compared to the same periods in 2013, largely due to the increase in our G&P segment’s revenues of approximately $14.2 million (or 20%) and $33.6 million (or 16%) for those same periods. The increases in our G&P revenues were primarily driven by higher gathering and compression volumes during the three and nine months endedSeptember 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 nine months ended September 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 nine months ended September 30, 2013 to 0.8 Bcf/d and 0.7 Bcf/d during the same periods in 2014. The increases in our G&P gathering and compression volumes were primarily due to several new compressor stations placed in service during 2013 and 2014 in the Marcellus Shale and new wells connected to our systems during 2014.

Partially offsetting the increases in our G&P segment’s revenues were higher costs of product/services sold during the three and nine months endedSeptember 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 and increased production at Granite Wash due to new wells connected during 2014. Operations and maintenance expense in our gathering and processing segment increased approximately $1.0 million and $3.5 million during the three and nine months endedSeptember 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 nine months endedSeptember 30, 2014, we had a $8.6 million loss on contingent consideration in connection with the acquisition of the Antero assets.

During the three and nine months ended September 30, 2013, our G&P segment EBITDA was also impacted by a $4.4 million gain on the sale of a cryogenic plant and associated equipment, partially offset by a $4.1 million impairment of goodwill on our Sabine System as a result of a decrease in anticipated revenues due primarily to our inability to renew and extend a significant revenue contract that expired in June 2013.

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 September 30, 2014 compared to the same period in 2013.

EBITDA for our storage and transportation segment increased by approximately 7% during the three months ended September 30, 2014 compared to the same period in 2013. The increase in our storage and transportation segment's EBITDA

40

was due to higher revenues primarily 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 September 30, 2014, total firm throughput from our storage and transportation services averaged approximately 1.6 Bcf/d compared to 1.3 Bcf/d during the same period in 2013.

Costs of product/services sold and operations and maintenance expenses for our storage and transportation segment were relatively flat during the three months ended September 30, 2014 compared to the same period in 2013.

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 September 30, 2014 compared to the same period in 2013.

EBITDA for our NGL and crude services segment increased by approximately $21.6 million during the three months ended September 30, 2014 compared to the same period in 2013. The increase in our NGL and crude services segment's EBITDA was primarily due to higher volumes on our COLT Hub as a result of our expansion of this facility and increased utilization of non-firm capacity on the system. We also experienced higher revenues as a result of the Arrow acquisition on November 8, 2013. Arrow contributed revenues of approximately $563.3 million for the three months ended September 30, 2014. Our NGL and crude services segment EBITDA does not reflect the results of our Arrow operations for the three months ended September 30, 2013.

Partially offsetting the increases in our NGL and crude services segment's revenues were (i) higher costs of product/services sold primarily related to higher crude volumes gathered and sold on the COLT Hub; (ii) higher costs of product/services sold and operations and maintenance expenses from our Arrow operations of approximately $549.1 million; and (iii) higher operations and maintenance expenses due to the acquisitions of Red Rock and LT Enterprises in 2014.

Other Results

Our consolidated EBITDA for the three and nine months endedSeptember 30, 2014 was $104.5 million and $285.3 million, an increase of $38.0 million and $140.3 million compared to the same periods in 2013. Our consolidated Adjusted EBITDA for the three and nine months endedSeptember 30, 2014 was $116.2 million and $324.8 million, an increase of $30.9 million and $153.8 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. Our general and administrative expenses decreased from $25.2 million during the three months ended September 30, 2013 to $18.2 million during the three months ended September 30, 2014 due to lower legal and other consulting expenses related to the Crestwood Merger. During the nine months ended September 30, 2014 compared to the same period in 2013, we experienced an increase in our general and administrative expenses which was driven by the assets acquired as a result of the Crestwood Merger and the Arrow Acquisition in 2013. In addition, we recognized legal and other consulting expenses primarily related to the Arrow Acquisition, which were approximately $5.4 million for the nine months ended September 30, 2014. We also had increases in payroll and related benefit costs, which reflects the increased scope of our business operations, and an increase $7.4 million of expenses related to our equity compensation plans during the nine months ended September 30, 2014 compared to the same period in 2013.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense - During the three and nine months endedSeptember 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 nine months endedSeptember 30, 2014 compared to the same periods 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					Nine Months Ended
	September 30,					September 30,
	2014		2013			2014		2013
Credit facilities	$	4.4	$	6.7		$	13.4	$	15.6
Senior notes	23.5		14.6			70.4		29.6
Capital lease interest	—		0.1			0.1		0.2
Other debt-related costs	1.0		(0.1		)	4.8		—
Gross interest and debt expense	28.9		21.3			88.7		45.4
Less: capitalized interest	1.2		1.8			3.9		2.0
Interest and debt expense, net	$	27.7	$	19.5		$	84.8	$	43.4

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 September 30, 2014, we had $227.0 million of available capacity under the Credit Facility considering our most restrictive debt covenants under the facility. In addition, as of September 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 million (or approximately $293.7 million of net proceeds after transaction fees and offering expenses). On September 22, 2014, we sold an additional 2,988,047 Preferred Units to the investors that generated gross proceeds of approximately $75.0 million (or approximately $73.1 million of net proceeds). 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 $125 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.

As of September 30, 2014, we were in compliance with all our debt covenants related to our Credit Facility and our Senior Notes. See Item 1, Financial Statements, Note 7 for a more detailed description of our credit facility. We believe our current liquidity sources and operating cash flows will be sufficient to fund our future operating and capital requirements.

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

	Nine Months Ended
	September 30,
	2014			2013
Net cash provided by operating activities	$	175.8		$	130.5
Net cash used in investing activities	(360.6		)	(330.7		)
Net cash provided by financing activities	182.2			207.0

Operating Activities

During the nine months endedSeptember 30, 2014, we experienced an increase in our operating cash flows compared to the same period in 2013 primarily attributable to the Crestwood Merger and the Arrow Acquisition which occurred in 2013. These transactions resulted in higher operating revenues of approximately $1,624.9 million, partially offset by (i) higher costs of products/services sold, operations and maintenance expenses and general and administrative expenses of approximately $1,491.1 million and (ii) a decrease in cash associated with net changes in working capital of approximately $73.2 million. In addition, our interest paid during the nine months ended September 30, 2014 increased compared to the same period in 2013 due to higher outstanding balances on our credit facilities.

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 nine months endedSeptember 30, 2014 (in millions):

Growth capital	$	217.5
Maintenance capital	11.4
Other (1)	30.4
Total	$	259.3

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

During the first half of 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. During the nine months ended September 30, 2013, we paid approximately $130.0 million to acquire investments in our unconsolidated affiliates. We also made capital contributions during the nine months ended September 30, 2014 and 2013 of approximately $81.8 million and $22.5 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 nine months endedSeptember 30, 2014 and 2013, included the following:

Equity Transactions

• $126.6 million increase in distributions to partners during the nine months endedSeptember 30, 2014 compared to the same period in 2013;

• $366.8 millionnet proceeds from the issuances of Class A Preferred Unitsduring June and September of 2014;

• $53.9 million and $96.1 million in proceeds from the issuance of preferred security units to GE during the nine months endedSeptember 30, 2014 and 2013;  

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

• $238.2 million net proceeds from the issuance of Legacy Inergy common units during the nine months endedSeptember 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

• $11.4 million increase in net borrowings of long-term debt during the nine months endedSeptember 30, 2014 compared to the same period in 2013.

Critical Accounting Estimates

Our critical accounting estimates are consistent with those described in our 2013 Annual Report on Form 10-K other than as follows.

Goodwill Impairment

Our goodwill represents the excess of the amount we paid for a business over the fair value of the net identifiable assets

acquired. We evaluate goodwill for impairment annually on December 31, and whenever events indicate that the fair value of a reporting unit could be less than its carrying amount. This evaluation requires us to compare the fair value of a reporting unit to is carrying value (including goodwill). If the fair value exceeds the carrying amount, goodwill of the reporting unit is not considered impaired. In conjunction with the reverse merger, we modified our segments and now our financial statements reflect three operating and reportable segments; (i) gathering and processing operations; (ii) NGL and crude services operations; and (iii) storage and transportation operations. We have identified nine reporting units within these three operating and reportable segments that contain goodwill.

As described above, during interim periods we evaluate our reporting units for events and changes that could indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount. Although we do not believe that it is more likely than not that any of our reporting units have a fair value that is less than its carrying amount at September 30, 2014, we believe that a 5% decrease in the estimated future cash flows or a 1% increase in the discount rate used to estimate the fair value of our reporting units would not have resulted in a material impairment of our goodwill related to any of our reporting units, other than potentially the $14.2 million of goodwill related to our Granite Wash reporting unit and $14.8 million of goodwill related to our US Salt reporting unit, given that the operating performance of these reporting units were lower than what was originally anticipated for them during the nine months ended September 30, 2014. We expect that the operating performance of Granite Wash and US Salt will increase from their current levels in the future.

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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 September 30, 2014 other than as follows.

During the three months ended September 30, 2014, we began entering into daily and short-term forward crude purchase and sale agreements in our NGL and crude services segment related to available capacity on our crude contracts and facilities for our operations located in the Bakken and PRB Niobrara Shale plays. We enter into such contracts to reduce the effect of price volatility on our product costs and protect the value of our inventory positions. We attempt to balance our contractual portfolio by purchasing volumes only when we have a matching purchase commitment from our marketing customers. We had no outstanding positions related to these activities as of September 30, 2014 as all positions had settled prior to September 30, 2014.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As of September 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 September 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 nine months endedSeptember 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 incorporated herein by reference.

Item 1A. Risk Factors

There have been no material updates to the Risk Factors previously disclosed in “Part I, Item 1A. Risk Factors” of our 2013 Annual Report on Form 10-K and our Quarterly Report on Form 10-Q for the period ended June 30, 2014.

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

On September 22, 2014, a group of investors including Magnetar Capital, affiliates of GSO Capital Partners LP and GE Energy Financial Services purchased an additional 2,988,047 Preferred Units for a cash purchase price of $25.10 per unit resulting in gross proceeds to us of approximately $75.0 million (net proceeds of approximately $73.1 million after deducting transaction fees and offering expenses).

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

46

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)
*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

47

*

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.

48

SIGNATURE

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

		CRESTWOOD MIDSTREAM PARTNERS LP
		By:	CRESTWOOD MIDSTREAM GP LLC
			(its general partner)
Date:	November 6, 2014	By:	/s/ MICHAEL J. CAMPBELL
			Michael J. Campbell
			Senior Vice President and Chief Financial Officer
			(Duly Authorized Officer and Principal Financial Officer)

49

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 September 30, 2014						Nine Months Ended September 30, 2014
	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	$	21.0		$	12.3		$	40.6		$	28.6
Add:
Fixed charges	29.9			22.5			90.6			47.9
Amortized capitalized interest	—			0.1			0.1			0.1
Less:
Capitalized interest	(1.2		)	(1.8		)	(3.9		)	(2.0		)
Non-controlling interest in pre-tax income of subsidiary with no fixed charges (2)	(4.5		)	(1.9		)	(11.3		)	(1.9		)
Total earnings available for fixed charges	$	45.2		$	31.2		$	116.1		$	72.7
Fixed charges:
Interest and debt expense	29.0			21.9			88.8			46.0
Interest component of rent	0.9			0.6			1.8			1.9
Total fixed charges	$	29.9		$	22.5		$	90.6		$	47.9
Ratio of earnings to fixed charges(1)	1.5			1.4			1.3			1.5

(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: November 6, 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: November 6, 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 September 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
November 6, 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 September 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
November 6, 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		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Earnings Per Share [Abstract]
Limited partners’ interest in net income (loss) attributable to CMLP after incentive distributions	$ 0.2	$ 3.4	$ (5.5)	$ 6.0
Basic (units)	187,955,000	161,575,000	187,931,000	101,094,000
Incremental Common Shares Attributable to Share-based Payment Arrangements	0	0	0	0
Diluted (units)	187,955,000	161,575,000	187,931,000	101,094,000
Basic, in dollars per unit	$ 0.00	$ 0.02	$ (0.03)	$ 0.06
Diluted, in dollars per unit	$ 0.00	$ 0.02	$ (0.03)	$ 0.06

XML

Condensed Consolidating Financial Information (Condensed Consolidating Balance Sheet) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2013	Dec. 31, 2012
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	$ 0.1	$ 2.7	$ 6.9	$ 0.1
Accounts receivable	312.8	205.1
Inventory	8.3	7.0
Prepaid expenses and other current assets	20.3	10.2
Total current assets	341.5	225.0
Property, plant and equipment, net	3,499.6	3,350.1
Goodwill and intangible assets, net	2,602.2	2,653.6
Investment in Consolidated Subsidiaries	0	0
Investment in unconsolidated affiliates (Note 5)	231.9	151.4
Other assets	19.4	21.7
Total assets	6,694.6	6,401.8	5,162.8
Accounts payable	200.6	163.2
Other current liabilities	165.7	151.3
Total current liabilities	366.3	314.5
Long-term debt, less current portion	1,893.0	1,867.9
Other long-term liabilities	30.0	26.3
Total long-term liabilities	1,923.0	1,894.2
Partners' Capital	4,239.1	4,092.1
Interest of non-controlling partners in subsidiary	166.2	101.0
Total partners’ capital	4,405.3	4,193.1
Total liabilities and partners’ capital	6,694.6	6,401.8
Parent
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	0	0.1	4.5	0
Accounts receivable	579.1	466.8
Inventory	0	0
Prepaid expenses and other current assets	0	0
Total current assets	579.1	466.9
Property, plant and equipment, net	5.9	4.8
Goodwill and intangible assets, net	0	0
Investment in Consolidated Subsidiaries	6,571.5	6,385.2
Investment in unconsolidated affiliates (Note 5)	0	0
Other assets	0	0
Total assets	7,156.5	6,856.9
Accounts payable	855.5	782.7
Other current liabilities	1.0	11.5
Total current liabilities	856.5	794.2
Long-term debt, less current portion	1,893.0	1,867.9
Other long-term liabilities	1.7	1.7
Total long-term liabilities	1,894.7	1,869.6
Partners' Capital	4,239.1	4,092.1
Interest of non-controlling partners in subsidiary	166.2	101.0
Total partners’ capital	4,405.3	4,193.1
Total liabilities and partners’ capital	7,156.5	6,856.9
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	0.1	1.6	2.4	0.1
Accounts receivable	295.4	197.8
Inventory	8.3	7.0
Prepaid expenses and other current assets	20.3	10.2
Total current assets	324.1	216.6
Property, plant and equipment, net	3,493.7	3,345.3
Goodwill and intangible assets, net	2,602.2	2,653.6
Investment in Consolidated Subsidiaries	0	0
Investment in unconsolidated affiliates (Note 5)	0	0
Other assets	19.4	21.7
Total assets	6,439.4	6,237.2
Accounts payable	(93.2)	(159.8)
Other current liabilities	164.7	139.6
Total current liabilities	71.5	(20.2)
Long-term debt, less current portion	0	0
Other long-term liabilities	28.3	24.6
Total long-term liabilities	28.3	24.6
Partners' Capital	6,339.6	6,232.8
Interest of non-controlling partners in subsidiary	0	0
Total partners’ capital	6,339.6	6,232.8
Total liabilities and partners’ capital	6,439.4	6,237.2
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	0	1.0	0	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)	231.9	151.4
Other assets	0	0
Total assets	232.0	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	65.7	51.4
Interest of non-controlling partners in subsidiary	166.2	101.0
Total partners’ capital	231.9	152.4
Total liabilities and partners’ capital	232.0	152.6
Consolidation, Eliminations
Condensed Financial Statements, Captions [Line Items]
Cash and cash equivalents	0	0	0	0
Accounts receivable	(561.8)	(459.7)
Inventory	0	0
Prepaid expenses and other current assets	0	0
Total current assets	(561.8)	(459.7)
Property, plant and equipment, net	0	0
Goodwill and intangible assets, net	0	0
Investment in Consolidated Subsidiaries	(6,571.5)	(6,385.2)
Investment in unconsolidated affiliates (Note 5)	0	0
Other assets	0	0
Total assets	(7,133.3)	(6,844.9)
Accounts payable	(561.8)	(459.7)
Other current liabilities	0	0
Total current liabilities	(561.8)	(459.7)
Long-term debt, less current portion	0	0
Other long-term liabilities	0	0
Total long-term liabilities	0	0
Partners' Capital	(6,405.3)	(6,284.2)
Interest of non-controlling partners in subsidiary	(166.2)	(101.0)
Total partners’ capital	(6,571.5)	(6,385.2)
Total liabilities and partners’ capital	(7,133.3)	(6,844.9)
Consolidated Entities [Member]
Condensed Financial Statements, Captions [Line Items]
Total liabilities and partners’ capital		$ 6,401.8

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Commitments and Contingencies (Details) (USD $) In Millions, unless otherwise specified					1 Months Ended
	Sep. 30, 2014	Dec. 31, 2013	Sep. 30, 2014 Antero	Dec. 31, 2013 Antero	Mar. 31, 2014 Arrow Acquisition Class Action Lawsuit defendant	Nov. 08, 2013 Arrow Acquisition Class Action Lawsuit bbl people
Schedule Of Commitments And Contingencies [Line Items]
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
Business Combination, Contingent Consideration, Liability, Current			40.0
Contingent Consideration Classified as Equity, Fair Value Disclosure			$ 40.0	$ 31.4

XML

Condensed Consolidating Financial Information (Condensed Consolidating Statement of Operations) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Condensed Financial Statements, Captions [Line Items]
Gathering and processing	$ 83.9	$ 47.0	$ 245.2	$ 140.3
Storage and transportation	44.2	42.1	133.9	47.6
NGL and crude services	605.4	23.5	1,558.8	26.6
Related party (Note 11)	4.9	27.5	13.2	78.1
Revenues	738.4	140.1	1,951.1	292.6
Gathering and processing	7.3	5.3	22.8	18.2
Storage and transportation	4.3	4.0	11.3	4.4
NGL and crude services	552.8	9.7	1,426.7	10.6
Related party	(11.3)	(7.6)	(32.1)	(22.2)
Cost of Revenue	575.7	26.6	1,492.9	55.4
Operations and maintenance	39.4	21.7	100.1	48.1	73.3	43.1	36.3
Operations and maintenance expense	39.4	21.7	100.1	48.1
General and administrative expense	18.2	25.2	63.6	44.0	80.7	29.6	24.1
Depreciation, amortization and accretion	55.5	35.1	161.2	73.4
Costs and Expenses, Total	113.1	82.0	324.9	165.5
Loss on contingent consideration (Note 10)	0	0	(8.6)	0
Other	(0.9)	0.3	0.7	0.3
Operating income	48.7	31.8	125.4	72.0
Interest and debt expense, net	(27.7)	(19.5)	(84.8)	(43.4)
Equity in net income (loss) of subsidiary	0	0	0	0
Other	0.3	(0.4)	(1.3)	(0.4)
Income before income taxes	21.3	11.9	39.3	28.2
Provision for income taxes	0	0.3	0.8	1.0
Net income	21.3	11.6	38.5	27.2
Net income attributable to non-controlling partners	(4.5)	(1.9)	(11.3)	(1.9)
Net income attributable to Crestwood Midstream Partners LP	16.8	9.7	27.2	25.3
Net income attributable to Class A preferred units	(9.1)	0	(10.2)	0
Net Income (Loss), Partners Interest in Net Income	7.7	9.7	17.0	25.3
Parent
Condensed Financial Statements, Captions [Line Items]
Gathering and processing	0	0	0	0
Storage and transportation	0	0	0	0
NGL and crude services	0	0	0	0
Related party (Note 11)	0	0	0	0
Revenues	0	0	0	0
Gathering and processing	0	0	0	0
Storage and transportation	0	0	0	0
NGL and crude services	0	0	0	0
Related party	0	0	0	0
Cost of Revenue	0	0	0	0
Operations and maintenance	0	0	0	0
General and administrative expense	(0.8)	9.4	(3.8)	24.0
Depreciation, amortization and accretion	0.3	0.2	0.7	0.6
Costs and Expenses, Total	(0.5)	9.6	(3.1)	24.6
Loss on contingent consideration (Note 10)			0
Other	0	0	0	0
Operating income	0.5	(9.6)	3.1	(24.6)
Interest and debt expense, net	(27.8)	(18.4)	(85.1)	(39.9)
Equity in net income (loss) of subsidiary	48.6	39.6	120.5	91.7
Other	0	0	0	0
Income before income taxes	21.3	11.6	38.5	27.2
Provision for income taxes	0	0	0	0
Net income	21.3	11.6	38.5	27.2
Net income attributable to non-controlling partners	0	0	0	0
Net income attributable to Crestwood Midstream Partners LP	21.3	11.6	38.5	27.2
Net income attributable to Class A preferred units	(9.1)		(10.2)
Net Income (Loss), Partners Interest in Net Income	12.2		28.3
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Gathering and processing	83.9	47.0	245.2	140.3
Storage and transportation	44.2	42.1	133.9	47.6
NGL and crude services	605.4	23.5	1,558.8	26.6
Related party (Note 11)	4.9	27.5	13.2	78.1
Revenues	738.4	140.1	1,951.1	292.6
Gathering and processing	7.3	5.3	22.8	18.2
Storage and transportation	4.3	4.0	11.3	4.4
NGL and crude services	552.8	9.7	1,426.7	10.6
Related party	(11.3)	(7.6)	(32.1)	(22.2)
Cost of Revenue	575.7	26.6	1,492.9	55.4
Operations and maintenance	39.4	21.7	100.1	48.1
General and administrative expense	19.0	15.8	67.4	20.0
Depreciation, amortization and accretion	55.2	34.9	160.5	72.8
Costs and Expenses, Total	113.6	72.4	328.0	140.9
Loss on contingent consideration (Note 10)			(8.6)
Other	(0.9)	0.3	0.7	0.3
Operating income	48.2	41.4	122.3	96.6
Interest and debt expense, net	0.1	(1.1)	0.3	(3.5)
Equity in net income (loss) of subsidiary	0	0	0	0
Other	0	0	0	0
Income before income taxes	48.3	40.3	122.6	93.1
Provision for income taxes	0	0.3	0.8	1.0
Net income	48.3	40.0	121.8	92.1
Net income attributable to non-controlling partners	0	0	0	0
Net income attributable to Crestwood Midstream Partners LP	48.3	40.0	121.8	92.1
Net income attributable to Class A preferred units	0		0
Net Income (Loss), Partners Interest in Net Income	48.3		121.8
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Gathering and processing	0	0	0	0
Storage and transportation	0	0	0	0
NGL and crude services	0	0	0	0
Related party (Note 11)	0	0	0	0
Revenues	0	0	0	0
Gathering and processing	0	0	0	0
Storage and transportation	0	0	0	0
NGL and crude services	0	0	0	0
Related party	0	0	0	0
Cost of Revenue	0	0	0	0
Operations and maintenance	0	0	0	0
General and administrative expense	0	0	0	0
Depreciation, amortization and accretion	0	0	0	0
Costs and Expenses, Total	0	0	0	0
Loss on contingent consideration (Note 10)			0
Other	0	0	0	0
Operating income	0	0	0	0
Interest and debt expense, net	0	0	0	0
Equity in net income (loss) of subsidiary	0	0	0	0
Other	0.3	(0.4)	(1.3)	(0.4)
Income before income taxes	0.3	(0.4)	(1.3)	(0.4)
Provision for income taxes	0	0	0	0
Net income	0.3	(0.4)	(1.3)	(0.4)
Net income attributable to non-controlling partners	(4.5)	(1.9)	(11.3)	(1.9)
Net income attributable to Crestwood Midstream Partners LP	(4.2)	(2.3)	(12.6)	(2.3)
Net income attributable to Class A preferred units	0		0
Net Income (Loss), Partners Interest in Net Income	(4.2)		(12.6)
Consolidation, Eliminations
Condensed Financial Statements, Captions [Line Items]
Gathering and processing	0	0	0	0
Storage and transportation	0	0	0	0
NGL and crude services	0	0	0	0
Related party (Note 11)	0	0	0	0
Revenues	0	0	0	0
Gathering and processing	0	0	0	0
Storage and transportation	0	0	0	0
NGL and crude services	0	0	0	0
Related party	0	0	0	0
Cost of Revenue	0	0	0	0
Operations and maintenance	0	0	0	0
General and administrative expense	0	0	0	0
Depreciation, amortization and accretion	0	0	0	0
Costs and Expenses, Total	0	0	0	0
Loss on contingent consideration (Note 10)			0
Other	0	0	0	0
Operating income	0	0	0	0
Interest and debt expense, net	0	0	0	0
Equity in net income (loss) of subsidiary	(48.6)	(39.6)	(120.5)	(91.7)
Other	0	0	0	0
Income before income taxes	(48.6)	(39.6)	(120.5)	(91.7)
Provision for income taxes	0	0	0	0
Net income	(48.6)	(39.6)	(120.5)	(91.7)
Net income attributable to non-controlling partners	0	0	0	0
Net income attributable to Crestwood Midstream Partners LP	(48.6)	(39.6)	(120.5)	(91.7)
Net income attributable to Class A preferred units	0		0
Net Income (Loss), Partners Interest in Net Income	$ (48.6)		$ (120.5)

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Long-Term Incentive Plan (Narrative) (Details) (USD $) In Millions, except Share data, unless otherwise specified	1 Months Ended	9 Months Ended		3 Months Ended		9 Months Ended		3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014 Crestwood LTIP	Sep. 30, 2013 Crestwood LTIP	Sep. 30, 2014 Crestwood LTIP	Sep. 30, 2013 Crestwood LTIP	Sep. 30, 2014 Crestwood LTIP CMLP	Sep. 30, 2013 Crestwood LTIP CMLP	Sep. 30, 2014 Crestwood LTIP CMLP	Sep. 30, 2013 Crestwood LTIP CMLP	Sep. 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												$ 11.6	$ 1.8
Employee Service Share-based Compensation, Nonvested Awards, Total Compensation Cost Not yet Recognized, Period for Recognition						3 years
Unit-based compensation charges		13.9	6.5	2.5	1.7	8.7	3.2
Allocated Share-based Compensation Expense								1.6	3.1	5.2	3.3
Share-based Compensation Arrangement, Equity Instruments Other than Options, Grants in Period, Fair Value												$ 19.5
Common Stock, Capital Shares Reserved for Future Issuance												6,430,021
Shares Paid for Tax Withholding for Share Based Compensation				0	912	68,532	3,341
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	10.00%
Defined Contribution Plan, Employer Matching Contribution, Percent of Match	10.00%
Defined Contribution Plan, Maximum Purchasable Units	200,000	200,000

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Certain Balance Sheet Information (Property Plant and Equipment) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	$ 3,812.9	$ 3,565.7
Less: accumulated depreciation and depletion	313.3	215.6
Property, plant and equipment, net	3,499.6	3,350.1
Capital Leased Assets, Gross	3.0	5.0
Gathering systems and pipelines
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	1,251.9	1,231.1
Facilities and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	1,378.5	1,041.0
Buildings, land, rights-of-way, storage contracts and easements
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	783.4	766.2
Vehicles
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	13.8	4.1
Construction in process
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	221.3	360.5
Base gas
Property, Plant and Equipment [Line Items]
Property, plant and equipment (Note 3)	37.3	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)	$ 6.2	$ 6.0

XML

Financial Instruments (Tables)

9 Months Ended

Sep. 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):

	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2019 Senior Notes	$	351.0	$	369.5	$	351.2	$	379.3
2020 Senior Notes	$	504.1	$	507.9	$	504.7	$	513.8
2022 Senior Notes	$	600.0	$	603.0	$	600.0	$	617.3

Schedule of Debt

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

	September 30, 2014		December 31, 2013
Credit Facility	$	435.0	$	414.9
2019 Senior Notes	350.0		350.0
Premium on 2019 Senior Notes	1.0		1.2
2020 Senior Notes	500.0		500.0
Fair value adjustment of 2020 Senior Notes	4.1		4.7
2022 Senior Notes	600.0		600.0
Other	3.5		—
Total debt	1,893.6		1,870.8
Less: current portion	0.6		2.9
Total long-term debt	$	1,893.0	$	1,867.9

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Related Party Transactions (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended			9 Months Ended
	Sep. 30, 2014		Sep. 30, 2013	Sep. 30, 2014		Sep. 30, 2013	Dec. 31, 2013
Disclosure Related Party Transaction Additional Information [Abstract]
Gathering and processing revenues	$ 4.9		$ 27.5	$ 13.2		$ 78.1
Related Party Transaction, Due from (to) Related Party [Abstract]
Accounts payable	7.4			7.4			8.7
CEQP
Disclosure Related Party Transaction Additional Information [Abstract]
Gathering and processing revenues	1.4	[1]	24.1	3.0	[1]	74.3
NGL and crude services revenues	3.5	[1]	3.4	10.2	[1]	3.8
Gathering and processing costs of product/services sold	11.3	[1]	7.6	32.1	[1]	22.2
General and administrative expenses	4.5	[1]	5.9	12.8	[1]	16.5
Affiliates
Related Party Transaction, Due from (to) Related Party [Abstract]
Accounts receivable	2.8			2.8			1.1
Accounts payable	7.4			7.4			8.7
Crestwood LTIP | CMLP
Related Party Transaction [Line Items]
Operating, administrative and overhead cost	14.0		5.0	42.7		5.5
Allocated Share-based Compensation Expense	$ 1.6		$ 3.1	$ 5.2		$ 3.3

[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 (Debt) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Total debt	$ 1,893.6	$ 1,870.8
Less: current portion	0.6	2.9
Total long-term debt	1,893.0	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	1.0	1.2
Senior Notes | 2020 Senior Notes
Debt Instrument [Line Items]
Senior notes	500.0	500.0
Fair value adjustment of senior notes	4.1	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	$ 435.0	$ 414.9

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Investments in Unconsolidated Affiliates (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended			3 Months Ended		1 Months Ended	9 Months Ended		1 Months Ended	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2014 Jackalope Gas Gathering Services, LLC	Sep. 30, 2013 Jackalope Gas Gathering Services, LLC	Sep. 30, 2014 Jackalope Gas Gathering Services, LLC	Sep. 30, 2013 Jackalope Gas Gathering Services, LLC	Dec. 31, 2013 Jackalope Gas Gathering Services, LLC	Sep. 30, 2014 PRBIC	Dec. 31, 2013 PRBIC	Jul. 31, 2013 Crestwood Niobrara LLC Jackalope Gas Gathering Services, LLC	Sep. 30, 2014 Crestwood Niobrara LLC Jackalope Gas Gathering Services, LLC	Sep. 30, 2013 Crestwood Niobrara LLC Jackalope Gas Gathering Services, LLC	Sep. 30, 2013 Crude Logistics LLC	Sep. 30, 2014 Crude Logistics LLC PRBIC	Sep. 30, 2013 Crude Logistics LLC PRBIC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage											50.00%			50.00%
Investment in unconsolidated affiliates (Note 5)	$ 231.9		$ 231.9		$ 151.4	$ 205.6		$ 205.6		$ 127.2	$ 26.3	$ 24.2
Share of Net Earnings In Unconsolidated Affiliate						1.2	0.2	2.4	0.2
Difference between carrying amount and underlying equity						54.5		54.5
Amortization						0.8	0.6	2.3	0.6
Investment in unconsolidated affiliates in period			81.8	152.5									107.5	78.3	20.6	22.5	3.5	1.9
Earnings (loss) from unconsolidated affiliates, net	$ 0.3	$ (0.4)	$ (1.3)	$ (0.4)							$ (0.1)

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Segments (Reconciliation of Net Income to EBITDA) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Segment Reporting [Abstract]
Net income	$ 21.3	$ 11.6	$ 38.5	$ 27.2
Interest and debt expense, net	27.7	19.5	84.8	43.4
Provision for income taxes	0	0.3	0.8	1.0
Depreciation, amortization and accretion	55.5	35.1	161.2	73.4
EBITDA	$ 104.5	$ 66.5	$ 285.3	$ 145.0

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Long-Term Incentive Plan (Restricted Unit Activity) (Details) (Crestwood LTIP, Restricted units, USD $)	9 Months Ended
	Sep. 30, 2014
Crestwood LTIP | Restricted units
Units
Unvested - January 1, 2014	250,557
Vested - restricted units	(190,818)
Granted - restricted units	838,036
Forfeited	(57,208)
Unvested - September 30, 2014	840,567
Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	$ 22.13
Vested - restricted units	$ 22.16
Granted - restricted units	$ 23.31
Forfeited	$ 23.49
Unvested - September 30, 2014	$ 23.21

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Certain Balance Sheet Information

9 Months Ended

Sep. 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 September 30, 2014 and December 31, 2013 (in millions):

	September 30, 2014		December 31, 2013
Gathering systems and pipelines	1,251.9		1,231.1
Facilities and equipment	1,378.5		1,041.0
Buildings, land, rights-of-way, storage contracts and easements	783.4		766.2
Vehicles	13.8		4.1
Construction in process	221.3		360.5
Base gas	37.3		36.3
Salt deposits	120.5		120.5
Office furniture and fixtures	6.2		6.0
	3,812.9		3,565.7
Less: accumulated depreciation and depletion	313.3		215.6
Total property, plant and equipment, net	$	3,499.6	$	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 $3.0 million and $5.0 million included in property, plant and equipment, net at September 30, 2014 and December 31, 2013.

Intangible Assets

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

	September 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	113.6		54.3
Total intangible assets, net	$	920.8	$	970.8

Accrued Expenses and Other Liabilities

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

	September 30, 2014		December 31, 2013
Accrued expenses	$	31.9	$	20.0
Accrued property taxes	5.6		7.6
Accrued product purchases payable	1.4		1.6
Tax payable	0.9		10.6
Interest payable	27.4		14.9
Accrued additions to property, plant and equipment	45.8		58.1
Commitments and contingent liabilities (Note 10)	40.0		31.4
Capital leases	1.5		2.6
Deferred revenue	10.6		1.6
Total accrued expenses and other liabilities	$	165.1	$	148.4

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Financial Instruments (Narrative) (Details) (USD $)	9 Months Ended	0 Months Ended	9 Months Ended
	Sep. 30, 2014 Crestwood Midstream Revolver	Oct. 07, 2013 Crestwood Midstream Revolver Revolver	Sep. 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	Jul. 17, 2014 2022 Senior Notes Senior Notes	Oct. 22, 2013 2022 Senior Notes Senior Notes	Sep. 30, 2014 Minimum Crestwood Midstream Revolver Revolver	Sep. 30, 2014 Maximum Crestwood Midstream Revolver Revolver
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			435,000,000	414,900,000
Letters of credit outstanding			84,100,000
Remaining borrowing capacity			227,000,000
Line of Credit Facility, Interest Rate at Period End											2.91%	5.00%
Weighted average interest rate			2.92%
Maximum leverage ratio			5.0
Minimum interest coverage ratio			2.50
Current debt to EBITDA ratio	4.46
Consolidated EBITDA to interest expense ratio	3.86
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)

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Reportable Segments

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

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
Net income	$	21.3	$	11.6	$	38.5	$	27.2
Add:
Interest and debt expense, net	27.7		19.5		84.8		43.4
Provision for income taxes	—		0.3		0.8		1.0
Depreciation, amortization and accretion	55.5		35.1		161.2		73.4
EBITDA	$	104.5	$	66.5	$	285.3	$	145.0

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

	Three Months Ended September 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	85.3		$	44.2	$	608.9		$	—		$	738.4
Costs of product/services sold	18.6			4.3		552.8			—			575.7
Operations and maintenance expense	15.9			4.2		19.3			—			39.4
General and administrative expense	—			—		—			18.2			18.2
Loss on long-lived assets	(0.9		)	—		—			—			(0.9		)
Earnings (loss) from unconsolidated affiliates, net	0.4			—		(0.1		)	—			0.3
EBITDA	$	50.3		$	35.7	$	36.7		$	(18.2	)	$	104.5
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	2,026.1		$	1,951.2	$	2,553.7		$	163.6		$	6,694.6
Cash expenditures for property, plant and equipment	$	57.5		$	2.2	$	34.8		$	0.1		$	94.6

	Three Months Ended September 30, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services		Corporate			Total
Revenues	$	71.1		$	42.1	$	26.9	$	—		$	140.1
Costs of product/services sold	12.9			4.0		9.7		—			26.6
Operations and maintenance expense	14.9			4.7		2.1		—			21.7
General and administrative expense	—			—		—		25.2			25.2
Goodwill impairment	(4.1		)	—		—		—			(4.1		)
Gain on long-lived assets	4.4			—		—		—			4.4
Loss from unconsolidated affiliates, net	(0.4		)	—		—		—			(0.4		)
EBITDA	$	43.2		$	33.4	$	15.1	$	(25.2	)	$	66.5
Goodwill	$	99.6		$	744.1	$	609.1	$	—		$	1,452.8
Total assets	$	1,856.0		$	2,003.0	$	1,257.4	$	46.4		$	5,162.8
Cash expenditures for property, plant and equipment	$	84.1		$	5.7	$	16.0	$	0.1		$	105.9

	Nine Months Ended September 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	248.2		$	133.9	$	1,569.0		$	—		$	1,951.1
Costs of product/services sold	54.9			11.3		1,426.7			—			1,492.9
Operations and maintenance expense	44.0			12.9		43.2			—			100.1
General and administrative expense	—			—		—			63.6			63.6
Gain on long-lived assets	0.1			0.6		—			—			0.7
Loss on contingent consideration	(8.6		)	—		—			—			(8.6		)
Earnings (loss) from unconsolidated affiliates, net	0.1			—		(1.4		)	—			(1.3		)
EBITDA	$	140.9		$	110.3	$	97.7		$	(63.6	)	$	285.3
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	2,026.1		$	1,951.2	$	2,553.7		$	163.6		$	6,694.6
Cash expenditures for property, plant and equipment	$	178.6		$	4.7	$	72.3		$	3.7		$	259.3

	Nine Months Ended September 30, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services		Corporate			Total
Revenues	$	214.6		$	47.6	$	30.4	$	—		$	292.6
Costs of product/services sold	40.4			4.4		10.6		—			55.4
Operations and maintenance expense	40.5			5.3		2.3		—			48.1
General and administrative expense	—			—		—		44.0			44.0
Goodwill impairment	(4.1		)	—		—		—			(4.1		)
Gain on long-lived assets	4.4			—		—		—			4.4
Loss from unconsolidated affiliates, net	(0.4		)	—		—		—			(0.4		)
EBITDA	$	133.6		$	37.9	$	17.5	$	(44.0	)	$	145.0
Goodwill	$	99.6		$	744.1	$	609.1	$	—		$	1,452.8
Total assets	$	1,856.0		$	2,003.0	$	1,257.4	$	46.4		$	5,162.8
Cash expenditures for property, plant and equipment	$	164.0		$	7.9	$	17.0	$	0.5		$	189.4

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Related Party Transactions (Tables)

9 Months Ended

Sep. 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 nine months endedSeptember 30, 2014 and 2013 (in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014(1)		2013		2014(1)		2013
Gathering and processing revenues	$	1.4	$	24.1	$	3.0	$	74.3
NGL and crude services revenues	$	3.5	$	3.4	$	10.2	$	3.8
Gathering and processing costs of product/services sold	$	11.3	$	7.6	$	32.1	$	22.2
General and administrative expenses	$	4.5	$	5.9	$	12.8	$	16.5

(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.

Schedule of Related Party Receivables and Payables

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

	September 30, 2014		December 31, 2013
Accounts receivable	$	2.8	$	1.1
Accounts payable	$	7.4	$	8.7

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Condensed Consolidating Financial Information (Condensed Consolidating Statements of Cash Flows) (Details) (USD $) In Millions, unless otherwise specified	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	$ 175.8	$ 130.5
Acquisitions, net of cash acquired	(19.5)	0.2
Purchases of property, plant and equipment	(259.3)	(189.4)
Investment in unconsolidated affiliates	(81.8)	(152.5)
Capital contribution from consolidated affiliate	0	0
Proceeds from sale of assets	0	11.0
Net change in receivables from affiliates	0	0
Net cash used in investing activities	(360.6)	(330.7)
Proceeds from the issuance of long-term debt	1,410.9	577.2
Principal payments on long-term debt	(1,390.8)	(568.5)
Distributions paid	(253.8)	(127.2)
Contributions from parent	0	5.4
Net proceeds from issuance of common units		356.7
Net proceeds from issuance of preferred equity of subsidiary	53.9	96.1
Net proceeds from the issuance of Class A preferred units	366.8
Payments on capital leases	(2.6)	(3.0)
Taxes paid for unit-based compensation vesting	(1.5)	(0.7)
Payments of Debt Issuance Costs	0.1	0.1
Payments of Financing Costs		(0.1)
Net change in payables to affiliate	0	0
Other	(0.6)	0.1
Net cash provided by financing activities	182.2	207.0
Net change in cash	(2.6)	6.8
Cash at beginning of period	2.7	0.1
Cash at end of period	0.1	6.9
Distributions for additional interest in Crestwood Marcellus Midstream LLC	0	(129.0)
Parent
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	(27.6)	(18.7)
Acquisitions, net of cash acquired	0	0
Purchases of property, plant and equipment	(3.7)	(0.5)
Investment in unconsolidated affiliates	0	0
Capital contribution from consolidated affiliate	(23.4)	(82.0)
Proceeds from sale of assets		0
Net change in receivables from affiliates	(313.7)	57.4
Net cash used in investing activities	(340.8)	(25.1)
Proceeds from the issuance of long-term debt	2.5	343.5
Principal payments on long-term debt	0	(194.0)
Distributions paid	0	(90.3)
Contributions from parent	0	0
Net proceeds from issuance of common units		118.5
Net proceeds from issuance of preferred equity of subsidiary	0	0
Net proceeds from the issuance of Class A preferred units	366.8
Payments on capital leases	(0.9)	(0.3)
Taxes paid for unit-based compensation vesting	0	0
Payments of Debt Issuance Costs	0.1
Payments of Financing Costs		(0.1)
Net change in payables to affiliate	0	0
Other	0	0
Net cash provided by financing activities	368.3	48.3
Net change in cash	(0.1)	4.5
Cash at beginning of period	0.1	0
Cash at end of period	0	4.5
Distributions for additional interest in Crestwood Marcellus Midstream LLC		(129.0)
Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	203.4	183.0
Acquisitions, net of cash acquired	(19.5)	0.2
Purchases of property, plant and equipment	(255.6)	(188.9)
Investment in unconsolidated affiliates	(3.5)	(24.4)
Capital contribution from consolidated affiliate	(3.5)	0
Proceeds from sale of assets		11.0
Net change in receivables from affiliates	0	0
Net cash used in investing activities	(282.1)	(202.1)
Proceeds from the issuance of long-term debt	1,408.4	233.7
Principal payments on long-term debt	(1,390.8)	(374.5)
Distributions paid	(253.8)	(70.7)
Contributions from parent	3.5	55.4
Net proceeds from issuance of common units		238.2
Net proceeds from issuance of preferred equity of subsidiary	0	0
Net proceeds from the issuance of Class A preferred units	0
Payments on capital leases	(1.7)	(2.7)
Taxes paid for unit-based compensation vesting	(1.5)	(0.7)
Payments of Debt Issuance Costs	0
Payments of Financing Costs		0
Net change in payables to affiliate	313.7	(57.4)
Other	(0.6)	0.1
Net cash provided by financing activities	77.2	21.4
Net change in cash	(1.5)	2.3
Cash at beginning of period	1.6	0.1
Cash at end of period	0.1	2.4
Distributions for additional interest in Crestwood Marcellus Midstream LLC		0
Non-Guarantor Subsidiaries
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	0	0
Acquisitions, net of cash acquired	0	0
Purchases of property, plant and equipment	0	0
Investment in unconsolidated affiliates	(78.3)	(128.1)
Capital contribution from consolidated affiliate	0	0
Proceeds from sale of assets		0
Net change in receivables from affiliates	0	0
Net cash used in investing activities	(78.3)	(128.1)
Proceeds from the issuance of long-term debt	0	0
Principal payments on long-term debt	0	0
Distributions paid	0	0
Contributions from parent	23.4	32.0
Net proceeds from issuance of common units		0
Net proceeds from issuance of preferred equity of subsidiary	53.9	96.1
Net proceeds from the issuance of Class A preferred units	0
Payments on capital leases	0	0
Taxes paid for unit-based compensation vesting	0	0
Payments of Debt Issuance Costs	0
Payments of Financing Costs		0
Net change in payables to affiliate	0	0
Other	0	0
Net cash provided by financing activities	77.3	128.1
Net change in cash	(1.0)	0
Cash at beginning of period	1.0	0
Cash at end of period	0	0
Distributions for additional interest in Crestwood Marcellus Midstream LLC		0
Consolidation, Eliminations
Condensed Financial Statements, Captions [Line Items]
Net cash provided by operating activities	0	(33.8)
Acquisitions, net of cash acquired	0	0
Purchases of property, plant and equipment	0	0
Investment in unconsolidated affiliates	0	0
Capital contribution from consolidated affiliate	26.9	82.0
Proceeds from sale of assets		0
Net change in receivables from affiliates	313.7	(57.4)
Net cash used in investing activities	340.6	24.6
Proceeds from the issuance of long-term debt	0	0
Principal payments on long-term debt	0	0
Distributions paid	0	33.8
Contributions from parent	(26.9)	(82.0)
Net proceeds from issuance of common units		0
Net proceeds from issuance of preferred equity of subsidiary	0	0
Net proceeds from the issuance of Class A preferred units	0
Payments on capital leases	0	0
Taxes paid for unit-based compensation vesting	0	0
Payments of Debt Issuance Costs	0
Payments of Financing Costs		0
Net change in payables to affiliate	(313.7)	57.4
Other	0	0
Net cash provided by financing activities	(340.6)	9.2
Net change in cash	0	0
Cash at beginning of period	0	0
Cash at end of period	0	0
Distributions for additional interest in Crestwood Marcellus Midstream LLC		$ 0

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Partners' Capital (Narrative) (Details) (USD $)	0 Months Ended																		3 Months Ended		9 Months Ended				0 Months Ended						3 Months Ended	9 Months Ended	3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended		0 Months Ended		9 Months Ended	0 Months Ended		9 Months Ended	0 Months Ended
	Aug. 14, 2014	Aug. 07, 2014	Jul. 10, 2014	May 15, 2014	May 08, 2014	Feb. 14, 2014	Feb. 07, 2014	Aug. 14, 2013		Aug. 09, 2013	Aug. 07, 2013		Aug. 01, 2013	May 10, 2013	Apr. 30, 2013	Feb. 12, 2013	Jan. 31, 2013	Jan. 08, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Jul. 10, 2014	Jan. 08, 2013	Jan. 08, 2013 Legacy Crestwood Credit Facility	Jun. 17, 2014 Preferred Units, Class A	Jul. 18, 2014 Common Unit	Jan. 08, 2013 Preferred Units, Class D	Jan. 08, 2013 General Partner	Jul. 23, 2014 Preferred Units	Sep. 30, 2014 Crestwood Niobrara LLC Preferred Units, Class D	Sep. 30, 2014 Crestwood Niobrara LLC Preferred Units, Class D	Sep. 30, 2014 Jackalope Gas Gathering Services, LLC	Sep. 30, 2013 Jackalope Gas Gathering Services, LLC	Sep. 30, 2014 Jackalope Gas Gathering Services, LLC	Sep. 30, 2013 Jackalope Gas Gathering Services, LLC	Sep. 30, 2014 Jackalope Gas Gathering Services, LLC Preferred Units	Sep. 30, 2014 Jackalope Gas Gathering Services, LLC Crestwood Niobrara LLC	Sep. 30, 2013 Jackalope Gas Gathering Services, LLC Crestwood Niobrara LLC	Sep. 30, 2013 Jackalope Gas Gathering Services, LLC Crestwood Niobrara LLC	Sep. 30, 2014 Jackalope Gas Gathering Services, LLC Crestwood Niobrara LLC Preferred Units	Jun. 17, 2014 Preferred Partner	Sep. 30, 2014 Preferred Partner	Sep. 30, 2014 Preferred Partner Preferred Units, Class A	Sep. 22, 2014 Class A Purchasers Preferred Units, Class A	Jun. 17, 2014 Class A Purchasers Maximum Preferred Units, Class A	Sep. 30, 2014 Limited Partner	Oct. 31, 2014 Subsequent event Crestwood Niobrara LLC Preferred Units	Oct. 22, 2014 Subsequent event 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																																										$ 2,988,047	$ 500,000,000
Offering Costs, Partnership Interests																							0.020
Maximum Period For Distribution Of Available Cash																					45 days
Distributions to general partner																					31,400,000	17,100,000																									31,400,000
Distribution Made to Limited Partner, Date of Record		Aug. 07, 2014			May 08, 2014		Feb. 07, 2014				Aug. 07, 2013	[1]	Aug. 01, 2013		Apr. 30, 2013		Jan. 31, 2013
Per unit rate, in dollars per unit	$ 0.41			$ 0.41		$ 0.41		$ 0.40	[1]	$ 0.51				$ 0.51		$ 0.51
Contribution from issuance of units																																					150,000,000				53,900,000
Net Income (Loss) Attributable to Noncontrolling Interest																			4,500,000	1,900,000	11,300,000	1,900,000											4,500,000	1,900,000	11,300,000	1,900,000
Funds from Capital Contributions, Maximum																																						20,300,000	96,100,000	96,100,000
Distribution Made to Member or Limited Partner, Cash Distributions Paid	74,100,000			74,200,000.00		74,100,000.00		34,300,000	[1]	27,400,000				27,400,000		21,000,000					222,400,000	110,100,000
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	42,523	3,073,357	7,819,661																3,599,580	345,471
Distribution Made to Limited Partner, Distribution Date	Aug. 14, 2014			May 15, 2014		Feb. 14, 2014		Aug. 14, 2013	[1]	Aug. 09, 2013				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			$ 25.10
Proceeds from Issuance of Preferred Limited Partners Units, Gross																										300,000,000																			75,000,000
Net proceeds from the issuance of Class A preferred units																					$ 366,800,000					$ 293,700,000																			$ 73,100,000
Partners' Capital, Contingent Distribution Amount Per Share																																											$ 0.7059
Partner's Capital, Unpaid Distribution, Accrual Percentage																																										2.8125%

[1] Represents distributions associated with Legacy Inergy limited partner units.

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Condensed Consolidating Financial Information (Tables)

9 Months Ended

Sep. 30, 2014

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Consolidating Balance Sheet

Condensed Consolidating Balance Sheet
September 30, 2014
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—	$	0.1		$	—	$	—		$	0.1
Accounts receivable	579.1		295.4			0.1		(561.8		)	312.8
Inventories	—		8.3			—		—			8.3
Other current assets	—		20.3			—		—			20.3
Total current assets	579.1		324.1			0.1		(561.8		)	341.5
Property, plant and equipment, net	5.9		3,493.7			—		—			3,499.6
Goodwill and intangible assets, net	—		2,602.2			—		—			2,602.2
Investment in consolidated affiliates	6,571.5		—			—		(6,571.5		)	—
Investment in unconsolidated affiliates	—		—			231.9		—			231.9
Other assets	—		19.4			—		—			19.4
Total assets	$	7,156.5	$	6,439.4		$	232.0	$	(7,133.3	)	$	6,694.6
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	855.5	$	(93.2	)	$	0.1	$	(561.8	)	$	200.6
Other current liabilities	1.0		164.7			—		—			165.7
Total current liabilities	856.5		71.5			0.1		(561.8		)	366.3
Long-term liabilities:
Long-term debt, less current portion	1,893.0		—			—		—			1,893.0
Other long-term liabilities	1.7		28.3			—		—			30.0
Total long-term liabilities	1,894.7		28.3			—		—			1,923.0
Partners' capital	4,239.1		6,339.6			65.7		(6,405.3		)	4,239.1
Interest of non-controlling partners in subsidiaries	166.2		—			166.2		(166.2		)	166.2
Total partners' capital	4,405.3		6,339.6			231.9		(6,571.5		)	4,405.3
Total liabilities and partners' capital	$	7,156.5	$	6,439.4		$	232.0	$	(7,133.3	)	$	6,694.6

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 September 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	83.9		$	—		$	—		$	83.9
Storage and transportation	—			44.2			—			—			44.2
NGL and crude services	—			605.4			—			—			605.4
Related party	—			4.9			—			—			4.9
	—			738.4			—			—			738.4
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			7.3			—			—			7.3
Storage and transportation	—			4.3			—			—			4.3
NGL and crude services	—			552.8			—			—			552.8
Related party	—			11.3			—			—			11.3
	—			575.7			—			—			575.7
Expenses:
Operations and maintenance	—			39.4			—			—			39.4
General and administrative	(0.8		)	19.0			—			—			18.2
Depreciation, amortization and accretion	0.3			55.2			—			—			55.5
	(0.5		)	113.6			—			—			113.1
Other operating income (expense):
Other	—			(0.9		)	—			—			(0.9		)
Operating income	0.5			48.2			—			—			48.7
Interest and debt expense, net	(27.8		)	0.1			—			—			(27.7		)
Equity in net income (loss) of subsidiary	48.6			—			—			(48.6		)	—
Other	—			—			0.3			—			0.3
Income (loss) before income taxes	21.3			48.3			0.3			(48.6		)	21.3
Provision for income taxes	—			—			—			—			—
Net income (loss)	21.3			48.3			0.3			(48.6		)	21.3
Net income attributable to non-controlling partners	—			—			(4.5		)	—			(4.5		)
Net income (loss) attributable to Crestwood Midstream Partners LP	21.3			48.3			(4.2		)	(48.6		)	16.8
Net income attributable to Class A preferred units	(9.1		)	—			—			—			(9.1		)
Net income (loss) attributable to partners	$	12.2		$	48.3		$	(4.2	)	$	(48.6	)	$	7.7

Condensed Consolidating Statements of Operations
Three Months Ended September 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	47.0		$	—		$	—		$	47.0
Storage and transportation	—			42.1			—			—			42.1
NGL and crude services	—			23.5			—			—			23.5
Related party	—			27.5			—			—			27.5
	—			140.1			—			—			140.1
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			5.3			—			—			5.3
Storage and transportation	—			4.0			—			—			4.0
NGL and crude services	—			9.7			—			—			9.7
Related party	—			7.6			—			—			7.6
	—			26.6			—			—			26.6
Expenses:
Operations and maintenance	—			21.7			—			—			21.7
General and administrative	9.4			15.8			—			—			25.2
Depreciation, amortization and accretion	0.2			34.9			—			—			35.1
	9.6			72.4			—			—			82.0
Other operating income (expense):
Other	—			0.3			—			—			0.3
Operating income (loss)	(9.6		)	41.4			—			—			31.8
Interest and debt expense, net	(18.4		)	(1.1		)	—			—			(19.5		)
Equity in net income (loss) of subsidiary	39.6			—			—			(39.6		)	—
Other	—			—			(0.4		)	—			(0.4		)
Income (loss) before income taxes	11.6			40.3			(0.4		)	(39.6		)	11.9
Provision for income taxes	—			0.3			—			—			0.3
Net income (loss)	11.6			40.0			(0.4		)	(39.6		)	11.6
Net income attributable to non-controlling partners	—			—			(1.9		)	—			(1.9		)
Net income (loss) attributable to Crestwood Midstream Partners LP	$	11.6		$	40.0		$	(2.3	)	$	(39.6	)	$	9.7

Condensed Consolidating Statements of Operations
Nine Months Ended September 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	245.2		$	—		$	—		$	245.2
Storage and transportation	—			133.9			—			—			133.9
NGL and crude services	—			1,558.8			—			—			1,558.8
Related party	—			13.2			—			—			13.2
	—			1,951.1			—			—			1,951.1
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			22.8			—			—			22.8
Storage and transportation	—			11.3			—			—			11.3
NGL and crude services	—			1,426.7			—			—			1,426.7
Related party	—			32.1			—			—			32.1
	—			1,492.9			—			—			1,492.9
Expenses:
Operations and maintenance	—			100.1			—			—			100.1
General and administrative	(3.8		)	67.4			—			—			63.6
Depreciation, amortization and accretion	0.7			160.5			—			—			161.2
	(3.1		)	328.0			—			—			324.9
Other operating income (expense):
Loss on contingent consideration	—			(8.6		)	—			—			(8.6		)
Other	—			0.7			—			—			0.7
Operating income	3.1			122.3			—			—			125.4
Interest and debt expense, net	(85.1		)	0.3			—			—			(84.8		)
Equity in net income (loss) of subsidiary	120.5			—			—			(120.5		)	—
Other	—			—			(1.3		)	—			(1.3		)
Income (loss) before income taxes	38.5			122.6			(1.3		)	(120.5		)	39.3
Provision for income taxes	—			0.8			—			—			0.8
Net income (loss)	38.5			121.8			(1.3		)	(120.5		)	38.5
Net income attributable to non-controlling partners	—			—			(11.3		)	—			(11.3		)
Net income (loss) attributable to Crestwood Midstream Partners LP	38.5			121.8			(12.6		)	(120.5		)	27.2
Net income attributable to Class A preferred units	(10.2		)	—			—			—			(10.2		)
Net income (loss) attributable to partners	$	28.3		$	121.8		$	(12.6	)	$	(120.5	)	$	17.0

Consolidating Statement of Cash Flows

Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(27.6	)	$	203.4		$	—		$	—		$	175.8
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(19.5		)	—			—			(19.5		)
Purchases of property, plant and equipment	(3.7		)	(255.6		)	—			—			(259.3		)
Investment in unconsolidated affiliates	—			(3.5		)	(78.3		)	—			(81.8		)
Capital contribution from consolidated affiliates	(23.4		)	(3.5		)	—			26.9			—
Net change in receivables from affiliates	(313.7		)	—			—			313.7			—
Net cash provided by (used in) investing activities	(340.8		)	(282.1		)	(78.3		)	340.6			(360.6		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2.5			1,408.4			—			—			1,410.9
Principal payments on long-term debt	—			(1,390.8		)	—			—			(1,390.8		)
Distributions paid	—			(253.8		)	—			—			(253.8		)
Contributions from parent	—			3.5			23.4			(26.9		)	—
Net proceeds from issuance of preferred equity of subsidiary	—			—			53.9			—			53.9
Net proceeds from issuance of Class A preferred units	366.8			—			—			—			366.8
Payments on capital leases	(0.9		)	(1.7		)	—			—			(2.6		)
Taxes paid for unit-based compensation vesting	—			(1.5		)	—			—			(1.5		)
Payments for debt-related deferred costs	(0.1		)	—			—			—			(0.1		)
Net change in payables to affiliates	—			313.7			—			(313.7		)	—
Other	—			(0.6		)	—			—			(0.6		)
Net cash provided by (used in) financing activities	368.3			77.2			77.3			(340.6		)	182.2
Net change in cash	(0.1		)	(1.5		)	(1.0		)	—			(2.6		)
Cash at beginning of period	0.1			1.6			1.0			—			2.7
Cash at end of period	$	—		$	0.1		$	—		$	—		$	0.1

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

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Basis of Presentation and Summary of Significant Accounting Policies

9 Months Ended

Sep. 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. 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 September 30, 2014, and for the three and nine months endedSeptember 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 accounting principles generally accepted in the United States of America (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 Securities and Exchange Commission (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 nine months endedSeptember 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 recasted 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 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.

New Accounting Pronouncement Issued But Not Yet Adopted

As of September 30, 2014, the following accounting standard had 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 current revenue recognition guidance. We will adopt the provisions of this standard effective January 1, 2017 and 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		9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Operating and administrative expenses as previously reported	$ 39.4	$ 21.7	$ 100.1	$ 48.1
Operations and maintenance expenses	39.4	21.7	100.1	48.1	73.3	43.1	36.3
General and administrative expense	18.2	25.2	63.6	44.0	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	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2014
Crestwood Niobrara LLC
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	7,191,463	5,984,792
Preferred Units
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	12,244,500	4,739,285
Preferred Units | Crestwood Niobrara LLC
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Antidilutive Securities Excluded from Computation of Earnings Per Share, Amount	3,262,275	1,099,375
Distribution Rights | CEQP
Antidilutive Securities Excluded from Computation of Earnings Per Share [Line Items]
Percentage of distribution entitled to receive		100.00%

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Segments (Schedule of Reportable Segment Data) (Details) (USD $) In Millions, unless otherwise specified	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Segment Reporting Information [Line Items]
Revenues	$ 738.4	$ 140.1	$ 1,951.1	$ 292.6
Costs of product/services sold	575.7	26.6	1,492.9	55.4
Operations and maintenance expense	39.4	21.7	100.1	48.1
General and administrative expense	18.2	25.2	63.6	44.0	80.7	29.6	24.1
Goodwill impairment	0	(4.1)	0	(4.1)
Gain (loss) on long-lived assets, net	(0.9)	4.4	0.7	4.4
Loss on contingent consideration			(8.6)	0
Earnings (loss) from unconsolidated affiliates, net	0.3	(0.4)	(1.3)	(0.4)
EBITDA	104.5	66.5	285.3	145.0
Goodwill	1,681.4	1,452.8	1,681.4	1,452.8	1,682.8
Total assets	6,694.6	5,162.8	6,694.6	5,162.8	6,401.8
Cash expenditures for property, plant and equipment	94.6	105.9	259.3	189.4
Gathering and Processing
Segment Reporting Information [Line Items]
Revenues	85.3	71.1	248.2	214.6
Costs of product/services sold	18.6	12.9	54.9	40.4
Operations and maintenance expense	15.9	14.9	44.0	40.5
General and administrative expense	0	0	0	0
Goodwill impairment		(4.1)		(4.1)
Gain (loss) on long-lived assets, net	(0.9)	4.4	0.1	4.4
Loss on contingent consideration			(8.6)
Earnings (loss) from unconsolidated affiliates, net	0.4	(0.4)	0.1	(0.4)
EBITDA	50.3	43.2	140.9	133.6
Goodwill	99.6	99.6	99.6	99.6
Total assets	2,026.1	1,856.0	2,026.1	1,856.0
Cash expenditures for property, plant and equipment	57.5	84.1	178.6	164.0
Storage and Transportation
Segment Reporting Information [Line Items]
Revenues	44.2	42.1	133.9	47.6
Costs of product/services sold	4.3	4.0	11.3	4.4
Operations and maintenance expense	4.2	4.7	12.9	5.3
General and administrative expense	0	0	0	0
Goodwill impairment		0		0
Gain (loss) on long-lived assets, net	0	0	0.6	0
Loss on contingent consideration			0
Earnings (loss) from unconsolidated affiliates, net	0	0	0	0
EBITDA	35.7	33.4	110.3	37.9
Goodwill	726.3	744.1	726.3	744.1
Total assets	1,951.2	2,003.0	1,951.2	2,003.0
Cash expenditures for property, plant and equipment	2.2	5.7	4.7	7.9
NGL and Crude Services
Segment Reporting Information [Line Items]
Revenues	608.9	26.9	1,569.0	30.4
Costs of product/services sold	552.8	9.7	1,426.7	10.6
Operations and maintenance expense	19.3	2.1	43.2	2.3
General and administrative expense	0	0	0	0
Goodwill impairment		0		0
Gain (loss) on long-lived assets, net	0	0	0	0
Loss on contingent consideration			0
Earnings (loss) from unconsolidated affiliates, net	(0.1)	0	(1.4)	0
EBITDA	36.7	15.1	97.7	17.5
Goodwill	855.5	609.1	855.5	609.1
Total assets	2,553.7	1,257.4	2,553.7	1,257.4
Cash expenditures for property, plant and equipment	34.8	16.0	72.3	17.0
Corporate
Segment Reporting Information [Line Items]
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	18.2	25.2	63.6	44.0
Goodwill impairment		0		0
Gain (loss) on long-lived assets, net	0	0	0	0
Loss on contingent consideration			0
Earnings (loss) from unconsolidated affiliates, net	0	0	0	0
EBITDA	(18.2)	(25.2)	(63.6)	(44.0)
Goodwill	0	0	0	0
Total assets	163.6	46.4	163.6	46.4
Cash expenditures for property, plant and equipment	$ 0.1	$ 0.1	$ 3.7	$ 0.5

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CONSOLIDATED BALANCE SHEETS (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Current assets:
Cash and cash equivalents	$ 0.1	$ 2.7
Accounts receivable	312.8	205.1
Inventory	8.3	7.0
Prepaid expenses and other current assets	20.3	10.2
Total current assets	341.5	225.0
Property, plant and equipment (Note 3)	3,812.9	3,565.7
Less: accumulated depreciation and depletion	313.3	215.6
Property, plant and equipment, net	3,499.6	3,350.1
Intangible assets:
Intangible assets (Note 3)	1,034.4	1,025.1
Less: accumulated amortization	113.6	54.3
Intangible assets, net	920.8	970.8
Goodwill	1,681.4	1,682.8
Investment in unconsolidated affiliates (Note 5)	231.9	151.4
Other assets	19.4	21.7
Total assets	6,694.6	6,401.8
Current liabilities:
Accounts payable	193.2	154.5
Accounts payable - related party (Note 11)	7.4	8.7
Accrued expenses and other liabilities	165.1	148.4
Current portion of long-term debt (Note 7)	0.6	2.9
Total current liabilities	366.3	314.5
Long-term debt, less current portion (Note 7)	1,893.0	1,867.9
Other long-term liabilities	30.0	26.3
Commitments and contingencies (Note 10)
Partners’ capital (Note 8):
Class A preferred units (14,940,238 units issued and outstanding at September 30, 2014)	377.0	0
Partners’ capital (187,956,285 and 187,243,989 limited partner units issued and outstanding at September 30, 2014 and December 31, 2013)	3,862.1	4,092.1
Total Crestwood Midstream Partners LP partners’ capital	4,239.1	4,092.1
Interest of non-controlling partners in subsidiary	166.2	101.0
Total partners’ capital	4,405.3	4,193.1
Total liabilities and partners’ capital	$ 6,694.6	$ 6,401.8

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Partners' Capital (Schedule of Partnership Distributions) (Details) (USD $)	0 Months Ended																9 Months Ended		0 Months Ended
	Aug. 14, 2014	Aug. 07, 2014	May 15, 2014	May 08, 2014	Feb. 14, 2014	Feb. 07, 2014	Aug. 14, 2013		Aug. 09, 2013	Aug. 07, 2013		Aug. 01, 2013	May 10, 2013	Apr. 30, 2013	Feb. 12, 2013	Jan. 31, 2013	Sep. 30, 2014	Sep. 30, 2013	Oct. 22, 2014 Dividend Paid Cash distribution Subsequent event
Limited Partners' Capital Account [Line Items]
Distribution Made to Limited Partner, Date of Record		Aug. 07, 2014		May 08, 2014		Feb. 07, 2014				Aug. 07, 2013	[1]	Aug. 01, 2013		Apr. 30, 2013		Jan. 31, 2013
Distribution Made to Limited Partner, Distribution Date	Aug. 14, 2014		May 15, 2014		Feb. 14, 2014		Aug. 14, 2013	[1]	Aug. 09, 2013				May 10, 2013		Feb. 12, 2013
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.41		$ 0.41		$ 0.41		$ 0.40	[1]	$ 0.51				$ 0.51		$ 0.51
Distribution Made to Member or Limited Partner, Cash Distributions Paid	$ 74,100,000		$ 74,200,000.00		$ 74,100,000.00		$ 34,300,000	[1]	$ 27,400,000				$ 27,400,000		$ 21,000,000		$ 222,400,000	$ 110,100,000
Distributions to limited partners																	$ 222,400,000	$ 110,100,000
Disclosure Partners Capital Summary Of Quarterly Distributions Of Available Cash [Abstract]
Distribution declared per limited partner unit																			$ 0.41

[1] Represents distributions associated with Legacy Inergy limited partner units.

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CONSOLIDATED STATEMENTS OF CASH FLOWS (USD $)	9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013
Operating activities
Net income	$ 38,500,000	$ 27,200,000
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion	161,200,000	73,400,000
Amortization of debt-related deferred costs and premiums	5,500,000	3,100,000
Unit-based compensation charges	13,900,000	6,500,000
Goodwill impairment	0	4,100,000
Gain on long-lived assets	(700,000)	(4,400,000)
Loss on contingent consideration	8,600,000	0
Loss from unconsolidated affiliates, net	1,300,000	400,000
Deferred income taxes	500,000	0
Changes in operating assets and liabilities, net of effects from acquisitions	(53,000,000)	20,200,000
Net cash provided by operating activities	175,800,000	130,500,000
Investing activities
Acquisitions, net of cash acquired (Note 4)	(19,500,000)	200,000
Purchases of property, plant and equipment	(259,300,000)	(189,400,000)
Investment in unconsolidated affiliates	(81,800,000)	(152,500,000)
Proceeds from sale of assets	0	11,000,000
Net cash used in investing activities	(360,600,000)	(330,700,000)
Financing activities
Proceeds from the issuance of long-term debt	1,410,900,000	577,200,000
Principal payments on long-term debt	(1,390,800,000)	(568,500,000)
Payments on capital leases	(2,600,000)	(3,000,000)
Payments for debt-related deferred costs	(100,000)	(100,000)
Distributions to limited partners	(222,400,000)	(110,100,000)
Distributions to general partner	(31,400,000)	(17,100,000)
Distributions for additional interest in Crestwood Marcellus Midstream LLC	0	(129,000,000)
Contributions from general partner	0	5,400,000
Net proceeds from issuance of limited partner units	0	356,700,000
Net proceeds from issuance of preferred equity of subsidiary	53,900,000	96,100,000
Net proceeds from the issuance of Class A preferred units	366,800,000
Taxes paid for unit-based compensation vesting	(1,500,000)	(700,000)
Other	(600,000)	100,000
Net cash provided by financing activities	182,200,000	207,000,000
Net change in cash	(2,600,000)	6,800,000
Cash at beginning of period	2,700,000	100,000
Cash at end of period	100,000	6,900,000
Supplemental schedule of non-cash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	(8,100,000)	31,900,000
Preferred Stock
Financing activities
Net proceeds from issuance of preferred equity of subsidiary	53,900,000	96,100,000
Preferred Units, Class A
Financing activities
Net proceeds from the issuance of Class A preferred units	$ 366,800,000	$ 0

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Certain Balance Sheet Information (Accrued Expenses and Other Liabilities) (Details) (USD $) In Millions, unless otherwise specified	Sep. 30, 2014	Dec. 31, 2013
Payables and Accruals [Abstract]
Accrued expenses	$ 31.9	$ 20.0
Accrued property taxes	5.6	7.6
Accrued product purchases payable	1.4	1.6
Tax payable	0.9	10.6
Interest payable	27.4	14.9
Accrued additions to property, plant and equipment	45.8	58.1
Commitments and contingent liabilities (Note 10)	40.0	31.4
Capital leases	1.5	2.6
Deferred revenue	10.6	1.6
Total accrued expenses and other liabilities	$ 165.1	$ 148.4

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Certain Balance Sheet Information (Tables)

9 Months Ended

Sep. 30, 2014

Balance Sheet Related Disclosures [Abstract]

Components of Property, Plant and Equipment

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

	September 30, 2014		December 31, 2013
Gathering systems and pipelines	1,251.9		1,231.1
Facilities and equipment	1,378.5		1,041.0
Buildings, land, rights-of-way, storage contracts and easements	783.4		766.2
Vehicles	13.8		4.1
Construction in process	221.3		360.5
Base gas	37.3		36.3
Salt deposits	120.5		120.5
Office furniture and fixtures	6.2		6.0
	3,812.9		3,565.7
Less: accumulated depreciation and depletion	313.3		215.6
Total property, plant and equipment, net	$	3,499.6	$	3,350.1

Components of Intangible Assets

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

	September 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	113.6		54.3
Total intangible assets, net	$	920.8	$	970.8

Components of Accrued Expenses and Other Liabilities

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

	September 30, 2014		December 31, 2013
Accrued expenses	$	31.9	$	20.0
Accrued property taxes	5.6		7.6
Accrued product purchases payable	1.4		1.6
Tax payable	0.9		10.6
Interest payable	27.4		14.9
Accrued additions to property, plant and equipment	45.8		58.1
Commitments and contingent liabilities (Note 10)	40.0		31.4
Capital leases	1.5		2.6
Deferred revenue	10.6		1.6
Total accrued expenses and other liabilities	$	165.1	$	148.4

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Acquisitions and Divestitures (Details) (USD $)	0 Months Ended		3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended		0 Months Ended					0 Months Ended		0 Months Ended	3 Months Ended	9 Months Ended	3 Months Ended		9 Months Ended			3 Months Ended		9 Months Ended
	Jul. 25, 2014	Jan. 08, 2013	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013	Dec. 31, 2013	Sep. 30, 2013 Arrow Midstream Holdings, LLC and Inergy Midstream		Sep. 30, 2013 Arrow Midstream Holdings, LLC and Inergy Midstream		Mar. 21, 2014 Red Rock Transportation, Inc tractor trailer_tanks bbl double_bottom_body_tanks	May 09, 2014 LT Enterprises	May 09, 2014 LT Enterprises tractor acre	May 09, 2014 LT Enterprises crude_trailer	May 09, 2014 LT Enterprises service_vehicles bbl	Jun. 30, 2013 Inergy Midstream	Jun. 19, 2013 Inergy Midstream	Nov. 08, 2013 Arrow Midstream Holdings, LLC	Sep. 30, 2014 Arrow Midstream Holdings, LLC	Sep. 30, 2014 Arrow Midstream Holdings, LLC	Sep. 30, 2014 NGL and Crude Services Operations	Sep. 30, 2013 NGL and Crude Services Operations	Sep. 30, 2014 NGL and Crude Services Operations	Sep. 30, 2013 NGL and Crude Services Operations	Jun. 30, 2014 NGL and Crude Services Operations Inergy Midstream	Sep. 30, 2014 Storage and Transportation	Sep. 30, 2013 Storage and Transportation	Sep. 30, 2014 Storage and Transportation	Sep. 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												22		38	51	17
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	1,452,800,000	1,681,400,000	1,452,800,000	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	744,100,000	726,300,000	744,100,000	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	6,200,000	22,500,000	18,900,000													8,826,125
Business Acquisition, Pro Forma Information [Abstract]
Revenue								601,200,000		1,526,800,000
Net income								9,600,000		27,200,000
Basic (usd per unit)								$ 0.02	[1]	$ 0.07	[1]
Diluted (usd per unit)								$ 0.02	[1]	$ 0.07	[1]
Business Combination, Acquisition Related Costs																				200,000	5,400,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Land, Area														20	20	20
Revenues			738,400,000	140,100,000	1,951,100,000	292,600,000											78,000,000					608,900,000	26,900,000	1,569,000,000	30,400,000		44,200,000	42,100,000	133,900,000	47,600,000
Net income			21,300,000	11,600,000	38,500,000	27,200,000											7,100,000
Divestitures [Abstract]
Proceeds from Sale of Property, Plant, and Equipment	11,000,000
Gain (Loss) on Disposition of Property Plant Equipment			$ 4,400,000

[1] Basic and diluted net income per limited partner unit for the three and nine months ended September 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)

9 Months Ended

Sep. 30, 2014

Earnings Per Share [Abstract]

Schedule of Other Nonoperating Income (Expense)

The tables below show the (i) allocation of net income attributable to CMLP and the (ii) net income attributable to CMLP per limited partner unit based on the number of basic and diluted limited partner units outstanding for the three and nine months endedSeptember 30, 2014 and 2013 (in millions):

Allocation of Net Income Attributable to CMLP
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Net income attributable to CMLP	$	16.8		$	9.7		$	27.2		$	25.3
Class A preferred units interest in net income attributable to CMLP	(9.1		)	—			(10.2		)	—
General partner’s incentive distributions	(7.5		)	(6.2		)	(22.5		)	(18.9		)
General partner’s interest in net income attributable to CMLP	—			(0.1		)	—			(0.4		)
Limited partners’ interest in net income (loss) attributable to CMLP	$	0.2		$	3.4		$	(5.5	)	$	6.0

Schedule of Earnings Per Share Reconciliation

Earnings Per Limited Partner Unit
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014			2013
Limited partners’ interest in net income (loss)	$	0.2	$	3.4	$	(5.5	)	$	6.0
Weighted-average limited partner units - basic	188.0		161.6		187.9			101.1
Effect of diluted units	—		—		—			—
Weighted-average limited partner units - diluted	188.0		161.6		187.9			101.1
Basic earnings per unit:
Net income (loss) per limited partner	$	—	$	0.02	$	(0.03	)	$	0.06
Diluted earnings per unit:
Net income (loss) per limited partner	$	—	$	0.02	$	(0.03	)	$	0.06

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Business Description

9 Months Ended

Sep. 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 September 30, 2014, Crestwood Equity Partners LP (CEQP), which owns our general partner, owns our non-economic general partnership interest, approximately 4% of our common limited partnership units 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 distribution 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 September 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) in New York and Pennsylvania and our 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 NGLs and crude oil gathering, storage, marketing 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 under development 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)	Sep. 30, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Preferred units, issued	14,940,238
Preferred units, outstanding	14,940,238
Common units, issued	187,956,285	187,243,989
Common units, outstanding	187,956,285	187,243,989

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Related Party Transactions

9 Months Ended

Sep. 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 $14.0 million and $42.7 million of costs for the three and nine months endedSeptember 30, 2014. Included in this amount was $1.6 million and $5.2 million of net unit-based compensation charges for the three and nine months endedSeptember 30, 2014. During the three and nine months endedSeptember 30, 2013, CEQP allocated to us $5.0 million and $5.5 million of costs, including $3.1 million and $3.3 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 nine months endedSeptember 30, 2014 and 2013 (in millions):

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014(1)		2013		2014(1)		2013
Gathering and processing revenues	$	1.4	$	24.1	$	3.0	$	74.3
NGL and crude services revenues	$	3.5	$	3.4	$	10.2	$	3.8
Gathering and processing costs of product/services sold	$	11.3	$	7.6	$	32.1	$	22.2
General and administrative expenses	$	4.5	$	5.9	$	12.8	$	16.5

(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.

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

	September 30, 2014		December 31, 2013
Accounts receivable	$	2.8	$	1.1
Accounts payable	$	7.4	$	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	9 Months Ended
	Sep. 30, 2014	Nov. 03, 2014 Limited Partner Units	Nov. 03, 2014 Preferred Units, Class A
Document Information [Line Items]
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	Sep. 30, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		187,979,748	14,940,238

XML

Segments

9 Months Ended

Sep. 30, 2014

Segment Reporting [Abstract]

Segments

Segments

Financial Information

We have three operating and reportable 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 NGLs and crude oil gathering, storage, marketing 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				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014		2013
Net income	$	21.3	$	11.6	$	38.5	$	27.2
Add:
Interest and debt expense, net	27.7		19.5		84.8		43.4
Provision for income taxes	—		0.3		0.8		1.0
Depreciation, amortization and accretion	55.5		35.1		161.2		73.4
EBITDA	$	104.5	$	66.5	$	285.3	$	145.0

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

	Three Months Ended September 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	85.3		$	44.2	$	608.9		$	—		$	738.4
Costs of product/services sold	18.6			4.3		552.8			—			575.7
Operations and maintenance expense	15.9			4.2		19.3			—			39.4
General and administrative expense	—			—		—			18.2			18.2
Loss on long-lived assets	(0.9		)	—		—			—			(0.9		)
Earnings (loss) from unconsolidated affiliates, net	0.4			—		(0.1		)	—			0.3
EBITDA	$	50.3		$	35.7	$	36.7		$	(18.2	)	$	104.5
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	2,026.1		$	1,951.2	$	2,553.7		$	163.6		$	6,694.6
Cash expenditures for property, plant and equipment	$	57.5		$	2.2	$	34.8		$	0.1		$	94.6

	Three Months Ended September 30, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services		Corporate			Total
Revenues	$	71.1		$	42.1	$	26.9	$	—		$	140.1
Costs of product/services sold	12.9			4.0		9.7		—			26.6
Operations and maintenance expense	14.9			4.7		2.1		—			21.7
General and administrative expense	—			—		—		25.2			25.2
Goodwill impairment	(4.1		)	—		—		—			(4.1		)
Gain on long-lived assets	4.4			—		—		—			4.4
Loss from unconsolidated affiliates, net	(0.4		)	—		—		—			(0.4		)
EBITDA	$	43.2		$	33.4	$	15.1	$	(25.2	)	$	66.5
Goodwill	$	99.6		$	744.1	$	609.1	$	—		$	1,452.8
Total assets	$	1,856.0		$	2,003.0	$	1,257.4	$	46.4		$	5,162.8
Cash expenditures for property, plant and equipment	$	84.1		$	5.7	$	16.0	$	0.1		$	105.9

	Nine Months Ended September 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	248.2		$	133.9	$	1,569.0		$	—		$	1,951.1
Costs of product/services sold	54.9			11.3		1,426.7			—			1,492.9
Operations and maintenance expense	44.0			12.9		43.2			—			100.1
General and administrative expense	—			—		—			63.6			63.6
Gain on long-lived assets	0.1			0.6		—			—			0.7
Loss on contingent consideration	(8.6		)	—		—			—			(8.6		)
Earnings (loss) from unconsolidated affiliates, net	0.1			—		(1.4		)	—			(1.3		)
EBITDA	$	140.9		$	110.3	$	97.7		$	(63.6	)	$	285.3
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	2,026.1		$	1,951.2	$	2,553.7		$	163.6		$	6,694.6
Cash expenditures for property, plant and equipment	$	178.6		$	4.7	$	72.3		$	3.7		$	259.3

	Nine Months Ended September 30, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services		Corporate			Total
Revenues	$	214.6		$	47.6	$	30.4	$	—		$	292.6
Costs of product/services sold	40.4			4.4		10.6		—			55.4
Operations and maintenance expense	40.5			5.3		2.3		—			48.1
General and administrative expense	—			—		—		44.0			44.0
Goodwill impairment	(4.1		)	—		—		—			(4.1		)
Gain on long-lived assets	4.4			—		—		—			4.4
Loss from unconsolidated affiliates, net	(0.4		)	—		—		—			(0.4		)
EBITDA	$	133.6		$	37.9	$	17.5	$	(44.0	)	$	145.0
Goodwill	$	99.6		$	744.1	$	609.1	$	—		$	1,452.8
Total assets	$	1,856.0		$	2,003.0	$	1,257.4	$	46.4		$	5,162.8
Cash expenditures for property, plant and equipment	$	164.0		$	7.9	$	17.0	$	0.5		$	189.4

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CONSOLIDATED STATEMENTS OF OPERATIONS (USD $) In Millions, except Share data in Thousands, unless otherwise specified	3 Months Ended		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Revenues:
Gathering and processing	$ 83.9	$ 47.0	$ 245.2	$ 140.3
Storage and transportation	44.2	42.1	133.9	47.6
NGL and crude services	605.4	23.5	1,558.8	26.6
Related party (Note 11)	4.9	27.5	13.2	78.1
Revenues	738.4	140.1	1,951.1	292.6
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	7.3	5.3	22.8	18.2
Storage and transportation	4.3	4.0	11.3	4.4
NGL and crude services	552.8	9.7	1,426.7	10.6
Related party (Note 11)	11.3	7.6	32.1	22.2
Cost of Revenue	575.7	26.6	1,492.9	55.4
Expenses:
Operations and maintenance	39.4	21.7	100.1	48.1
General and administrative	18.2	25.2	63.6	44.0
Depreciation, amortization and accretion	55.5	35.1	161.2	73.4
Costs and Expenses, Total	113.1	82.0	324.9	165.5
Other operating income (expense):
Goodwill impairment	0	4.1	0	4.1
Gain (loss) on long-lived assets, net	(0.9)	4.4	0.7	4.4
Loss on contingent consideration (Note 10)	0	0	(8.6)	0
Operating income	48.7	31.8	125.4	72.0
Earnings (loss) from unconsolidated affiliates, net	0.3	(0.4)	(1.3)	(0.4)
Interest and debt expense, net	(27.7)	(19.5)	(84.8)	(43.4)
Income before income taxes	21.3	11.9	39.3	28.2
Provision for income taxes	0	0.3	0.8	1.0
Net income	21.3	11.6	38.5	27.2
Net income attributable to non-controlling partners	(4.5)	(1.9)	(11.3)	(1.9)
Net income attributable to Crestwood Midstream Partners LP	16.8	9.7	27.2	25.3
Net income attributable to Class A preferred units	(9.1)	0	(10.2)	0
Net income attributable to partners	7.7	9.7	17.0	25.3
Partners’ interest information:
General partner's interest in net income	7.5	6.3	22.5	19.3
Limited partners’ interest in net income (loss)	$ 0.2	$ 3.4	$ (5.5)	$ 6.0
Net income (loss) per limited partner unit:
Basic (usd per unit)	$ 0.00	$ 0.02	$ (0.03)	$ 0.06
Diluted (usd per unit)	$ 0.00	$ 0.02	$ (0.03)	$ 0.06
Weighted-average limited partners’ units outstanding:
Basic (units)	187,955	161,575	187,931	101,094
Diluted (units)	187,955	161,575	187,931	101,094

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Earnings Per Limited Partner Unit Earnings Per Limited Partner Unit

9 Months Ended

Sep. 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 CMLP and the (ii) net income attributable to CMLP per limited partner unit based on the number of basic and diluted limited partner units outstanding for the three and nine months endedSeptember 30, 2014 and 2013 (in millions):

Allocation of Net Income Attributable to CMLP
	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2014			2013			2014			2013
Net income attributable to CMLP	$	16.8		$	9.7		$	27.2		$	25.3
Class A preferred units interest in net income attributable to CMLP	(9.1		)	—			(10.2		)	—
General partner’s incentive distributions	(7.5		)	(6.2		)	(22.5		)	(18.9		)
General partner’s interest in net income attributable to CMLP	—			(0.1		)	—			(0.4		)
Limited partners’ interest in net income (loss) attributable to CMLP	$	0.2		$	3.4		$	(5.5	)	$	6.0

Earnings Per Limited Partner Unit
	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2014		2013		2014			2013
Limited partners’ interest in net income (loss)	$	0.2	$	3.4	$	(5.5	)	$	6.0
Weighted-average limited partner units - basic	188.0		161.6		187.9			101.1
Effect of diluted units	—		—		—			—
Weighted-average limited partner units - diluted	188.0		161.6		187.9			101.1
Basic earnings per unit:
Net income (loss) per limited partner	$	—	$	0.02	$	(0.03	)	$	0.06
Diluted earnings per unit:
Net income (loss) per limited partner	$	—	$	0.02	$	(0.03	)	$	0.06

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 nine months endedSeptember 30, 2014, we excluded a weighted-average of 7,191,463 and 5,984,792 common units, representing Crestwood Niobrara's preferred units if converted to common units, from our diluted earnings per unit. During the three and nine months endedSeptember 30, 2014, we also excluded a weighted-average of 12,244,500 and 4,739,285 common units, representing Class A preferred units if converted to common units, from our diluted earnings per unit. During the three and nine months endedSeptember 30, 2013, we excluded a weighted-average of 3,262,275 and 1,099,375 common units, representing Crestwood Niobrara's preferred units if converted to common units, from our diluted earnings per unit. 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)

9 Months Ended

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

Crestwood Niobrara acquired its interest in Jackalope in July 2013 for approximately $107.5 million. During the nine months endedSeptember 30, 2014 and 2013, Crestwood Niobrara contributed $78.3 million and $20.6 million to Jackalope to fund its construction projects.

Our investment in Jackalope was $205.6 million and $127.2 million at September 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 Jackalope's net earnings based on our ownership interest and other adjustments recorded by us as discussed below. Our share of Jackalope’s net earnings was approximately $1.2 million and $0.2 million for the three months endedSeptember 30, 2014 and 2013 and $2.4 million and $0.2 million for the nine months endedSeptember 30, 2014 and 2013. As of September 30, 2014, our investment balance in Jackalope exceeded our equity in the underlying net assets of Jackalope by approximately $54.5 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 we recorded amortization expense of approximately $0.8 million and $0.6 million for the three months ended September 30, 2014 and 2013 and $2.3 million and $0.6 million for the nine months endedSeptember 30, 2014 and 2013.

Jackalope is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the nine months endedSeptember 30, 2014 and 2013, Jackalope did not make any distributions to its members.

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

Crestwood Logistics acquired its interest in PRBIC in September 2013 for approximately $22.5 million. During the nine months endedSeptember 30, 2014 and 2013, Crude Logistics contributed approximately $3.5 million and $1.9 million to PRBIC to fund its construction projects.

Our investment in PRBIC was $26.3 million and $24.2 million at September 30, 2014 and December 31, 2013. During the three and nine months endedSeptember 30, 2014, our share of PRBIC’s loss was approximately $0.1 million and $1.4 million. As of September 30, 2014, our investment balance in PRBIC approximated our equity in the underlying net assets of PRBIC. Our share of PRBIC’s net earnings was not material for the three months ended September 30, 2013.

PRBIC is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the nine months endedSeptember 30, 2014 and 2013, PRBIC did not make any distributions to its members.

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Acquisitions and Divestitures (Tables)

9 Months Ended

Sep. 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 Arrow Acquisition had been included in our consolidated results for the full three and nine months endedSeptember 30, 2013, and as if the results for Legacy Inergy reverse acquisition had been included for the entire nine months endedSeptember 30, 2013 (in millions, except per unit information):

	Three Months Ended		Nine Months Ended
	September 30, 2013		September 30, 2013
Revenues	$	601.2	$	1,526.8
Net income	$	9.6	$	27.2
Net income per limited partner unit(1):
Basic	$	0.02	$	0.07
Diluted	$	0.02	$	0.07

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)

9 Months Ended

Sep. 30, 2014

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Consolidating Financial Information

Condensed Consolidating Financial Information

Crestwood is a holding company and owns no operating assets and has no significant operations independent of its 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 (collectively, 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 September 30, 2014 and December 31, 2013, and for the three and nine months endedSeptember 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.

Condensed Consolidating Balance Sheet
September 30, 2014
(in millions)
	Parent		Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash and cash equivalents	$	—	$	0.1		$	—	$	—		$	0.1
Accounts receivable	579.1		295.4			0.1		(561.8		)	312.8
Inventories	—		8.3			—		—			8.3
Other current assets	—		20.3			—		—			20.3
Total current assets	579.1		324.1			0.1		(561.8		)	341.5
Property, plant and equipment, net	5.9		3,493.7			—		—			3,499.6
Goodwill and intangible assets, net	—		2,602.2			—		—			2,602.2
Investment in consolidated affiliates	6,571.5		—			—		(6,571.5		)	—
Investment in unconsolidated affiliates	—		—			231.9		—			231.9
Other assets	—		19.4			—		—			19.4
Total assets	$	7,156.5	$	6,439.4		$	232.0	$	(7,133.3	)	$	6,694.6
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	855.5	$	(93.2	)	$	0.1	$	(561.8	)	$	200.6
Other current liabilities	1.0		164.7			—		—			165.7
Total current liabilities	856.5		71.5			0.1		(561.8		)	366.3
Long-term liabilities:
Long-term debt, less current portion	1,893.0		—			—		—			1,893.0
Other long-term liabilities	1.7		28.3			—		—			30.0
Total long-term liabilities	1,894.7		28.3			—		—			1,923.0
Partners' capital	4,239.1		6,339.6			65.7		(6,405.3		)	4,239.1
Interest of non-controlling partners in subsidiaries	166.2		—			166.2		(166.2		)	166.2
Total partners' capital	4,405.3		6,339.6			231.9		(6,571.5		)	4,405.3
Total liabilities and partners' capital	$	7,156.5	$	6,439.4		$	232.0	$	(7,133.3	)	$	6,694.6

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 September 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	83.9		$	—		$	—		$	83.9
Storage and transportation	—			44.2			—			—			44.2
NGL and crude services	—			605.4			—			—			605.4
Related party	—			4.9			—			—			4.9
	—			738.4			—			—			738.4
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			7.3			—			—			7.3
Storage and transportation	—			4.3			—			—			4.3
NGL and crude services	—			552.8			—			—			552.8
Related party	—			11.3			—			—			11.3
	—			575.7			—			—			575.7
Expenses:
Operations and maintenance	—			39.4			—			—			39.4
General and administrative	(0.8		)	19.0			—			—			18.2
Depreciation, amortization and accretion	0.3			55.2			—			—			55.5
	(0.5		)	113.6			—			—			113.1
Other operating income (expense):
Other	—			(0.9		)	—			—			(0.9		)
Operating income	0.5			48.2			—			—			48.7
Interest and debt expense, net	(27.8		)	0.1			—			—			(27.7		)
Equity in net income (loss) of subsidiary	48.6			—			—			(48.6		)	—
Other	—			—			0.3			—			0.3
Income (loss) before income taxes	21.3			48.3			0.3			(48.6		)	21.3
Provision for income taxes	—			—			—			—			—
Net income (loss)	21.3			48.3			0.3			(48.6		)	21.3
Net income attributable to non-controlling partners	—			—			(4.5		)	—			(4.5		)
Net income (loss) attributable to Crestwood Midstream Partners LP	21.3			48.3			(4.2		)	(48.6		)	16.8
Net income attributable to Class A preferred units	(9.1		)	—			—			—			(9.1		)
Net income (loss) attributable to partners	$	12.2		$	48.3		$	(4.2	)	$	(48.6	)	$	7.7

Condensed Consolidating Statements of Operations
Three Months Ended September 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	47.0		$	—		$	—		$	47.0
Storage and transportation	—			42.1			—			—			42.1
NGL and crude services	—			23.5			—			—			23.5
Related party	—			27.5			—			—			27.5
	—			140.1			—			—			140.1
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			5.3			—			—			5.3
Storage and transportation	—			4.0			—			—			4.0
NGL and crude services	—			9.7			—			—			9.7
Related party	—			7.6			—			—			7.6
	—			26.6			—			—			26.6
Expenses:
Operations and maintenance	—			21.7			—			—			21.7
General and administrative	9.4			15.8			—			—			25.2
Depreciation, amortization and accretion	0.2			34.9			—			—			35.1
	9.6			72.4			—			—			82.0
Other operating income (expense):
Other	—			0.3			—			—			0.3
Operating income (loss)	(9.6		)	41.4			—			—			31.8
Interest and debt expense, net	(18.4		)	(1.1		)	—			—			(19.5		)
Equity in net income (loss) of subsidiary	39.6			—			—			(39.6		)	—
Other	—			—			(0.4		)	—			(0.4		)
Income (loss) before income taxes	11.6			40.3			(0.4		)	(39.6		)	11.9
Provision for income taxes	—			0.3			—			—			0.3
Net income (loss)	11.6			40.0			(0.4		)	(39.6		)	11.6
Net income attributable to non-controlling partners	—			—			(1.9		)	—			(1.9		)
Net income (loss) attributable to Crestwood Midstream Partners LP	$	11.6		$	40.0		$	(2.3	)	$	(39.6	)	$	9.7

Condensed Consolidating Statements of Operations
Nine Months Ended September 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	245.2		$	—		$	—		$	245.2
Storage and transportation	—			133.9			—			—			133.9
NGL and crude services	—			1,558.8			—			—			1,558.8
Related party	—			13.2			—			—			13.2
	—			1,951.1			—			—			1,951.1
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			22.8			—			—			22.8
Storage and transportation	—			11.3			—			—			11.3
NGL and crude services	—			1,426.7			—			—			1,426.7
Related party	—			32.1			—			—			32.1
	—			1,492.9			—			—			1,492.9
Expenses:
Operations and maintenance	—			100.1			—			—			100.1
General and administrative	(3.8		)	67.4			—			—			63.6
Depreciation, amortization and accretion	0.7			160.5			—			—			161.2
	(3.1		)	328.0			—			—			324.9
Other operating income (expense):
Loss on contingent consideration	—			(8.6		)	—			—			(8.6		)
Other	—			0.7			—			—			0.7
Operating income	3.1			122.3			—			—			125.4
Interest and debt expense, net	(85.1		)	0.3			—			—			(84.8		)
Equity in net income (loss) of subsidiary	120.5			—			—			(120.5		)	—
Other	—			—			(1.3		)	—			(1.3		)
Income (loss) before income taxes	38.5			122.6			(1.3		)	(120.5		)	39.3
Provision for income taxes	—			0.8			—			—			0.8
Net income (loss)	38.5			121.8			(1.3		)	(120.5		)	38.5
Net income attributable to non-controlling partners	—			—			(11.3		)	—			(11.3		)
Net income (loss) attributable to Crestwood Midstream Partners LP	38.5			121.8			(12.6		)	(120.5		)	27.2
Net income attributable to Class A preferred units	(10.2		)	—			—			—			(10.2		)
Net income (loss) attributable to partners	$	28.3		$	121.8		$	(12.6	)	$	(120.5	)	$	17.0

Condensed Consolidating Statements of Operations
Nine Months Ended September 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	140.3		$	—		$	—		$	140.3
Storage and transportation	—			47.6			—			—			47.6
NGL and crude services	—			26.6			—			—			26.6
Related party	—			78.1			—			—			78.1
	—			292.6			—			—			292.6
Costs of product/services sold (excluding depreciation, amortization and accretion as shown below):
Gathering and processing	—			18.2			—			—			18.2
Storage and transportation	—			4.4			—			—			4.4
NGL and crude services	—			10.6			—			—			10.6
Related party	—			22.2			—			—			22.2
	—			55.4			—			—			55.4
Expenses:
Operations and maintenance	—			48.1			—			—			48.1
General and administrative	24.0			20.0			—			—			44.0
Depreciation, amortization and accretion	0.6			72.8			—			—			73.4
	24.6			140.9			—			—			165.5
Other operating income (expense):
Other	—			0.3			—			—			0.3
Operating income (loss)	(24.6		)	96.6			—			—			72.0
Interest and debt expense, net	(39.9		)	(3.5		)	—			—			(43.4		)
Equity in net income (loss) of subsidiary	91.7			—			—			(91.7		)	—
Other	—			—			(0.4		)	—			(0.4		)
Income (loss) before income taxes	27.2			93.1			(0.4		)	(91.7		)	28.2
Provision for income taxes	—			1.0			—			—			1.0
Net income (loss)	27.2			92.1			(0.4		)	(91.7		)	27.2
Net income attributable to non-controlling partners	—			—			(1.9		)	—			(1.9		)
Net income (loss) attributable to Crestwood Midstream Partners LP	$	27.2		$	92.1		$	(2.3	)	$	(91.7	)	$	25.3

Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(27.6	)	$	203.4		$	—		$	—		$	175.8
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(19.5		)	—			—			(19.5		)
Purchases of property, plant and equipment	(3.7		)	(255.6		)	—			—			(259.3		)
Investment in unconsolidated affiliates	—			(3.5		)	(78.3		)	—			(81.8		)
Capital contribution from consolidated affiliates	(23.4		)	(3.5		)	—			26.9			—
Net change in receivables from affiliates	(313.7		)	—			—			313.7			—
Net cash provided by (used in) investing activities	(340.8		)	(282.1		)	(78.3		)	340.6			(360.6		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2.5			1,408.4			—			—			1,410.9
Principal payments on long-term debt	—			(1,390.8		)	—			—			(1,390.8		)
Distributions paid	—			(253.8		)	—			—			(253.8		)
Contributions from parent	—			3.5			23.4			(26.9		)	—
Net proceeds from issuance of preferred equity of subsidiary	—			—			53.9			—			53.9
Net proceeds from issuance of Class A preferred units	366.8			—			—			—			366.8
Payments on capital leases	(0.9		)	(1.7		)	—			—			(2.6		)
Taxes paid for unit-based compensation vesting	—			(1.5		)	—			—			(1.5		)
Payments for debt-related deferred costs	(0.1		)	—			—			—			(0.1		)
Net change in payables to affiliates	—			313.7			—			(313.7		)	—
Other	—			(0.6		)	—			—			(0.6		)
Net cash provided by (used in) financing activities	368.3			77.2			77.3			(340.6		)	182.2
Net change in cash	(0.1		)	(1.5		)	(1.0		)	—			(2.6		)
Cash at beginning of period	0.1			1.6			1.0			—			2.7
Cash at end of period	$	—		$	0.1		$	—		$	—		$	0.1

Condensed Consolidating Statements of Cash Flows
Nine Months Ended September 30, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(18.7	)	$	183.0		$	—		$	(33.8	)	$	130.5
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			0.2			—			—			0.2
Purchases of property, plant and equipment	(0.5		)	(188.9		)	—			—			(189.4		)
Investment in unconsolidated affiliates	—			(24.4		)	(128.1		)	—			(152.5		)
Capital contribution from consolidated affiliates	(82.0		)	—			—			82.0			—
Proceeds from sale of assets	—			11.0			—			—			11.0
Net change in receivables from affiliates	57.4			—			—			(57.4		)	—
Net cash provided by (used in) investing activities	(25.1		)	(202.1		)	(128.1		)	24.6			(330.7		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	343.5			233.7			—			—			577.2
Principal payments on long-term debt	(194.0		)	(374.5		)	—			—			(568.5		)
Distributions paid	(90.3		)	(70.7		)	—			33.8			(127.2		)
Distributions for additional interest in Crestwood Marcellus Midstream LLC	(129.0		)	—			—			—			(129.0		)
Contributions from parent	—			55.4			32.0			(82.0		)	5.4
Net proceeds from issuance of common units	118.5			238.2			—			—			356.7
Net proceeds from issuance of preferred equity of subsidiary	—			—			96.1			—			96.1
Payments on capital leases	(0.3		)	(2.7		)	—			—			(3.0		)
Taxes paid for unit-based compensation vesting	—			(0.7		)	—			—			(0.7		)
Payments for debt-related deferred costs	(0.1		)	—			—			—			(0.1		)
Net change in payables to affiliates	—			(57.4		)	—			57.4			—
Other	—			0.1			—			—			0.1
Net cash provided by financing activities	48.3			21.4			128.1			9.2			207.0
Net change in cash	4.5			2.3			—			—			6.8
Cash at beginning of period	—			0.1			—			—			0.1
Cash at end of period	$	4.5		$	2.4		$	—		$	—		$	6.9

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Long-Term Incentive Plan (Notes)

9 Months Ended

Sep. 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.

During 2014, we have issued restricted unit awards, which were approved by either CMLP's Board compensation committee or pursuant to the authority granted by the Chief Executive Officer, to certain key employees. These awards vest upon continued service with the Company.

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

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	250,557		$	22.13
Vested - restricted units	(190,818	)	$	22.16
Granted - restricted units	838,036		$	23.31
Forfeited	(57,208	)	$	23.49
Unvested - September 30, 2014	840,567		$	23.21

As of September 30, 2014 and December 31, 2013, we had total unamortized compensation expense of approximately $11.6 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. We recognized compensation expense of approximately $2.5 million and $1.7 million during the three months ended September 30, 2014 and 2013 and $8.7 million and $3.2 million during the nine months endedSeptember 30, 2014 and 2013, which is included in general and administrative expenses on our consolidated statements of operations. An additional $1.6 million and $5.2 million of net compensation expense was allocated from CEQP to us during the three and nine months endedSeptember 30, 2014 and an additional $3.1 million and $3.3 million was allocated from CEQP to us during the three and nine months endedSeptember 30, 2013 (see Note 11). We granted restricted units with a grant date fair value of approximately $19.5 million during the nine months endedSeptember 30, 2014.  As of September 30, 2014, we had 6,430,021 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 endedSeptember 30, 2013, we withheld 912 common units and during the nine months endedSeptember 30, 2014 and 2013, we withheld 68,532 and 3,341 common units to satisfy employee tax withholding obligations. There were no common units withheld during the three months endedSeptember 30, 2014.

Employee Unit Purchase Plan

Beginning in September 2014, the board of directors of our general partner made available an employee unit purchase plan under which employees of the general partner may purchase CMLP units through payroll deductions up to a maximum of 10 percent of the employees' eligible compensation. Under the plan, CMLP may purchase its units on the open market for the benefit of participating employees based on their payroll deductions.  In addition, CMLP may contribute an additional 10 percent of participating employees' payroll deductions to purchase additional CMLP units for participating employees. Unless increased by the board of directors of our general partner, the maximum number of units that may be purchased under the plan is 200,000.

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Financial Instruments

9 Months Ended

Sep. 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 September 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.

During the three months endedSeptember 30, 2014, we began entering into daily and short-term forward crude purchase and sale agreements in our NGL and crude services segment related to available capacity on our crude contracts and facilities associated with our operations located in the Bakken and PRB Niobrara Shale plays.

As of September 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 September 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):

	September 30, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2019 Senior Notes	$	351.0	$	369.5	$	351.2	$	379.3
2020 Senior Notes	$	504.1	$	507.9	$	504.7	$	513.8
2022 Senior Notes	$	600.0	$	603.0	$	600.0	$	617.3

Long-Term Debt

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

	September 30, 2014		December 31, 2013
Credit Facility	$	435.0	$	414.9
2019 Senior Notes	350.0		350.0
Premium on 2019 Senior Notes	1.0		1.2
2020 Senior Notes	500.0		500.0
Fair value adjustment of 2020 Senior Notes	4.1		4.7
2022 Senior Notes	600.0		600.0
Other	3.5		—
Total debt	1,893.6		1,870.8
Less: current portion	0.6		2.9
Total long-term debt	$	1,893.0	$	1,867.9

Credit Facility

We have a five-year $1 billion senior secured revolving credit facility due in October 2018 (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 September 30, 2014, the balance outstanding on our Credit Facility was $435.0 million and outstanding standby letters of credit were $84.1 million. We had $227.0 million of available capacity under the revolving credit facility at September 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 2.91% and 5.00% at September 30, 2014. The weighted-average interest rate as of September 30, 2014 was 2.92%.

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 to 1.0 and an interest coverage ratio (as defined in our credit agreement) of not less than 2.50 to 1.0. At September 30, 2014, our net debt to consolidated EBITDA (as defined in our credit agreement) was approximately 4.46 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 3.86 to 1.0.

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.

On July 17, 2014, we filed a registration statement with the SEC under which we offered 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. We completed the exchange offer on August 29, 2014. The terms of the exchange notes are substantially identical to the terms of the 2022 Senior Notes, except that the exchange notes are freely tradable.

At September 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.

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Partners' Capital

9 Months Ended

Sep. 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 as of September 30, 2014 and through the date of this filing. 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 $31.4 million and $17.1 million during the nine months endedSeptember 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 and October 22, 2014, the board of directors of our general partner authorized the issuance of 42,523 and 345,471 Preferred Units to our Preferred Unit holders for the quarters ended June 30, 2014 and September 30, 2014 in lieu of paying a cash distribution. In accordance with our partnership agreement, the additional Preferred Units will be issued in November 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 nine months endedSeptember 30, 2014:

Nine Months Ended September 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
August 7, 2014	August 14, 2014	$	0.41	74.1
				$	222.4

The following table presents quarterly cash distributions associated with Legacy Crestwood and Legacy Inergy paid to the limited partners (excluding distributions paid to the general partner on its common units held) during the nine months ended ended September 30, 2013:

Nine Months Ended September 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
August 1, 2013	August 9, 2013	$	0.51	27.4
August 7, 2013	August 14, 2013	$	0.40	34.3		(1)
				$	110.1

(1) Represents distributions associated with Legacy Inergy limited partner units.

On October 22, 2014, we declared a distribution of $0.41 per limited partner unit to be paid on November 14, 2014, to unitholders of record on November 7, 2014 with respect to the third 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). On September 22, 2014, the Class A Purchasers purchased 2,988,047 Preferred Units for a cash purchase price of $25.10 per unit resulting in gross proceeds to us of approximately $75.0 million (net proceeds of approximately $73.1 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. We allocated net income to the non-controlling interest based on the overall return attributable to the preferred security of approximately $4.5 million and $1.9 million during the three months endedSeptember 30, 2014 and 2013, and $11.3 million and $1.9 million during the nine months endedSeptember 30, 2014 and 2013.

Pursuant to Crestwood Niobrara's agreement with GE, GE made capital contributions to Crestwood Niobrara in exchange for an equivalent number of preferred units. During the three months endedSeptember 30, 2014 and 2013, GE made capital contributions of $20.3 million and $96.1 million to Crestwood Niobrara. During the nine months endedSeptember 30, 2014 and 2013, GE made capital contributions of $53.9 million and $96.1 million to Crestwood Niobrara. As of September 30, 2014, GE has fulfilled its capital contribution commitment to Crestwood Niobrara of $150.0 million and is no longer required to make quarterly contributions to Crestwood Niobrara.

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 and nine months endedSeptember 30, 2014, Crestwood Niobrara issued 3,073,357 and 7,819,661 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 October 31, 2014,Crestwood Niobrara issued 3,599,580 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 statement of cash flows for the nine months endedSeptember 30, 2013.

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Commitments and Contingencies

9 Months Ended

Sep. 30, 2014

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Legal Proceedings

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.  We anticipate a ruling from the Judge on Petitioners' motion to authorize the class action by the end of November 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 September 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

During the three months endedSeptember 30, 2014, we experienced two releases totaling approximately 28,000 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 releases completely and placed the impacted segments of these water lines back into service during the third quarter of2014. During the three months endedSeptember 30, 2014, we recognized $3.7 million of operations and maintenance expense related to these releases, of which $1.7 million was included in other current liabilities on our balance sheet as of September 30, 2014. We will continue our remediation efforts to ensure the impacted lands are restored to their prior state, and we may potentially be subject to fines and penalties. As of September 30, 2014, we had no amounts accrued for fines and penalties. We believe these releases are insurable events under our policies, and we have notified our carriers of these events; however, we have not recorded an insurance receivable as of September 30, 2014.

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. We are subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At September 30, 2014, our accrual of approximately $1.7 million was primarily related to the Arrow water releases described above, which is based on our undiscounted estimate of amounts we will spend on compliance with environmental and other regulations. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures (including the Arrow water releases described above) could range from approximately $1.7 million to $2.1 million. Our accrual and potential exposure related to our environmental matters was immaterial at December 31, 2013.

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 $40.0 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 September 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	Sep. 30, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	$ 1,034.4	$ 1,025.1
Less: accumulated amortization	113.6	54.3
Total intangible assets, net	920.8	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 (Narrative) (Details)	9 Months Ended
	Sep. 30, 2014 segment
Segment Reporting Information [Line Items]
Number of operating segments	3

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

9 Months Ended

Sep. 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)

9 Months Ended

Sep. 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 nine months endedSeptember 30, 2014:

Nine Months Ended September 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
August 7, 2014	August 14, 2014	$	0.41	74.1
				$	222.4

The following table presents quarterly cash distributions associated with Legacy Crestwood and Legacy Inergy paid to the limited partners (excluding distributions paid to the general partner on its common units held) during the nine months ended ended September 30, 2013:

Nine Months Ended September 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
August 1, 2013	August 9, 2013	$	0.51	27.4
August 7, 2013	August 14, 2013	$	0.40	34.3		(1)
				$	110.1

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Commitments and Contingencies Environmental Compliance (Details) (Fort Berthold Indian Reservation, USD $) In Millions, unless otherwise specified	3 Months Ended	9 Months Ended
	Sep. 30, 2014 Release bbl	Sep. 30, 2014 bbl
Fort Berthold Indian Reservation
Site Contingency [Line Items]
Number of releases of produced water	2
Number of barrels of produced water	28,000	28,000
Environmental remediation expense	$ 3.7
Accrual for environmental loss contingencies	1.7	1.7
Low estimate of environmental liability		1.7
High estimate of environmental liability		$ 2.1

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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	Sep. 30, 2014	Dec. 31, 2013
Carrying Amount | 2019 senior unsecured notes
Debt Instrument [Line Items]
Fair value of senior notes	$ 351.0	$ 351.2
Carrying Amount | 2020 senior unsecured notes
Debt Instrument [Line Items]
Fair value of senior notes	504.1	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	369.5	379.3
Fair Value | 2020 senior unsecured notes
Debt Instrument [Line Items]
Fair value of senior notes	507.9	513.8
Fair Value | 2022 senior unsecured notes
Debt Instrument [Line Items]
Fair value of senior notes	$ 603.0	$ 617.3

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CONSOLIDATED STATEMENT OF PARTNERS' CAPITAL (USD $) In Millions, unless otherwise specified	Total	Preferred Units, Class A	Preferred Partner	Preferred Partner Preferred Units, Class A	Limited Partner	Limited Partner Preferred Units, Class A	Non Controlling Partners	Non Controlling Partners Preferred Units, Class A	Partners' Capital	Partners' Capital Preferred Units, Class A
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)			0		(5.0)		0		(5.0)
Distributions to general partner	(31.4)		0		(31.4)		0		(31.4)
Distributions to limited partners	(222.4)		0		(222.4)		0		(222.4)
Unit-based compensation charges			0		13.9		0		13.9
Issuance of Class A preferred units	(366.8)	(366.8)		366.8		0		0		366.8
Issuance of preferred equity of subsidiary			0		0		(53.9)		(53.9)
Taxes paid for unit-based compensation vesting	1.5		0		(1.5)		0		(1.5)
Other			0		(0.6)		0		(0.6)
Net income	38.5		10.2		17.0		11.3		38.5
Ending Balance at Sep. 30, 2014	$ 4,239.1		$ 377.0		$ 3,862.1		$ 166.2		$ 4,405.3

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Acquisitions and Divestitures

9 Months Ended

Sep. 30, 2014

Business Combinations [Abstract]

Acquisitions

Acquisitions and Divestitures

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 nine months endedSeptember 30, 2014. In addition, transaction costs related to these acquisitions were not material for the three and nine months endedSeptember 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. 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 Crestwood and Legacy Inergy.  During the period from June 19, 2013 to September 30, 2013, we recognized $78.0 million of revenues and $7.1 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. 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 three and nine months endedSeptember 30, 2014, we also recognized approximately $0.2 million and $5.4 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 Arrow Acquisition had been included in our consolidated results for the full three and nine months endedSeptember 30, 2013, and as if the results for Legacy Inergy reverse acquisition had been included for the entire nine months endedSeptember 30, 2013 (in millions, except per unit information):

	Three Months Ended		Nine Months Ended
	September 30, 2013		September 30, 2013
Revenues	$	601.2	$	1,526.8
Net income	$	9.6	$	27.2
Net income per limited partner unit(1):
Basic	$	0.02	$	0.07
Diluted	$	0.02	$	0.07

(1) Basic and diluted net income per limited partner unit for the three and nine months endedSeptember 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.

Divestitures

On July 25, 2013, we sold a cryogenic plant and associated equipment for approximately $11.0 million (net of fees) and recognized a gain of approximately $4.4 million during the three months ended September 30, 2013.

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Long-Term Incentive Plan (Tables)

9 Months Ended

Sep. 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 nine months endedSeptember 30, 2014:

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	250,557		$	22.13
Vested - restricted units	(190,818	)	$	22.16
Granted - restricted units	838,036		$	23.31
Forfeited	(57,208	)	$	23.49
Unvested - September 30, 2014	840,567		$	23.21

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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		9 Months Ended
	Sep. 30, 2014	Sep. 30, 2013	Sep. 30, 2014	Sep. 30, 2013
Earnings Per Share [Abstract]
Net income attributable to CMLP	$ 16.8	$ 9.7	$ 27.2	$ 25.3
Class A preferred units interest in net income attributable to CMLP	(9.1)	0	(10.2)	0
General partner’s incentive distributions	(7.5)	(6.2)	(22.5)	(18.9)
General partner’s interest in net income attributable to CMLP	0	(0.1)	0	(0.4)
Limited partners’ interest in net income (loss) attributable to CMLP	$ 0.2	$ 3.4	$ (5.5)	$ 6.0

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

9 Months Ended

Sep. 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.