UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended March 31, 2015

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)

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

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

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

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if 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 May 4, 2015, the registrant had 188,291,848 common units and 18,332,195 Class A Preferred Units outstanding.

CRESTWOOD MIDSTREAM PARTNERS LP

INDEX TO FORM 10-Q

	Page
Part I – Financial Information
Item 1. Financial Statements of Crestwood Midstream Partners LP (Unaudited):
Consolidated Balance Sheets	3
Consolidated Statements of Operations	4
Consolidated Statement of Partners’ Capital	5
Consolidated Statements of Cash Flows	6
Notes to Consolidated Financial Statements	7
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	30
Item 3. Quantitative and Qualitative Disclosures About Market Risk	40
Item 4. Controls and Procedures	40
Part II – Other Information
Item 1. Legal Proceedings	41
Item 1A. Risk Factors	41
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	42
Item 3. Defaults Upon Senior Securities	42
Item 4. Mine Safety Disclosures	42
Item 5. Other Information	42
Item 6. Exhibits	43
Signature	45

2

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements of Crestwood Midstream Partners LP

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED BALANCE SHEETS (in millions, except unit information)
	March 31, 2015		December 31, 2014
	(unaudited)
Assets
Current assets:
Cash	$	66.8	$	4.6
Accounts receivable	192.6		241.8
Inventory	9.2		8.0
Prepaid expenses and other current assets	23.6		18.7
Total current assets	292.2		273.1
Property, plant and equipment (Note 4)	3,897.0		3,883.5
Less: accumulated depreciation and depletion	391.6		365.4
Property, plant and equipment, net	3,505.4		3,518.1
Intangible assets (Note 4)	1,020.2		1,013.2
Less: accumulated amortization	155.5		137.0
Intangible assets, net	864.7		876.2
Goodwill	1,632.6		1,632.6
Investment in unconsolidated affiliates (Note 5)	316.6		295.1
Other assets	1.2		1.4
Total assets	$	6,612.7	$	6,596.5
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	128.6	$	132.4
Accrued expenses and other liabilities (Note 4)	57.0		122.0
Current portion of long-term debt (Note 6)	36.1		0.7
Total current liabilities	221.7		255.1
Long-term debt, less current portion (Note 6)	2,121.7		2,012.8
Other long-term liabilities	31.5		31.2
Commitments and contingencies (Note 10)
Partners’ capital (Note 8):
Class A preferred units (18,332,195 and 17,917,870 units issued and outstanding at March 31, 2015 and December 31, 2014)	456.9		447.7
Partners’ capital (188,304,921 and 187,965,105 limited partner units issued and outstanding at March 31, 2015 and December 31, 2014)	3,603.6		3,678.0
Total Crestwood Midstream Partners LP partners’ capital	4,060.5		4,125.7
Interest of non-controlling partners in subsidiary	177.3		171.7
Total partners’ capital	4,237.8		4,297.4
Total liabilities and partners’ capital	$	6,612.7	$	6,596.5

See accompanying notes.

3

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, except unit and per unit data) (unaudited)
	Three Months Ended
	March 31,
	2015			2014
Revenues:
Gathering and processing	$	77.3		$	78.6
Storage and transportation	45.7			44.3
NGL and crude services	327.5			409.9
Related party (Note 11)	4.6			4.2
	455.1			537.0
Costs of product/services sold:
Gathering and processing	4.4			7.7
Storage and transportation	3.3			3.2
NGL and crude services	270.6			376.2
Related party (Note 11)	8.3			11.0
	286.6			398.1
Expenses:
Operations and maintenance	35.1			28.0
General and administrative	24.2			24.1
Depreciation, amortization and accretion	59.9			50.8
	119.2			102.9
Other operating income (expense):
Gain (loss) on long-lived assets, net	(0.8		)	0.5
Loss on contingent consideration	—			(2.1		)
Operating income	48.5			34.4
Earnings (loss) from unconsolidated affiliates, net	3.4			(0.1		)
Interest and debt expense, net	(29.9		)	(28.1		)
Income before income taxes	22.0			6.2
Provision for income taxes	0.3			0.7
Net income	21.7			5.5
Net income attributable to non-controlling partners	(5.6		)	(3.1		)
Net income attributable to Crestwood Midstream Partners LP	16.1			2.4
Net income attributable to Class A preferred units	(9.2		)	—
Net income attributable to partners	$	6.9		$	2.4
General partner's interest in net income	$	7.5		$	7.5
Limited partners’ interest in net income (loss)	$	(0.6	)	$	(5.1	)
Net income (loss) per limited partner unit:
Basic	$	—		$	(0.03	)
Diluted	$	—		$	(0.03	)
Weighted-average limited partners’ units outstanding (in thousands):
Basic	188,290			187,840
Diluted	188,290			187,840

See accompanying notes.

4

CRESTWOOD MIDSTREAM PARTNERS LP 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, 2014	$	447.7	$	3,678.0		$	171.7	$	4,297.4
Distributions to general partner	—		(10.5		)	—		(10.5		)
Distributions to limited partners	—		(74.3		)	—		(74.3		)
Unit-based compensation charges	—		5.2			—		5.2
Taxes paid for unit-based compensation vesting	—		(1.7		)	—		(1.7		)
Net income	9.2		6.9			5.6		21.7
Balance at March 31, 2015	$	456.9	$	3,603.6		$	177.3	$	4,237.8

See accompanying notes.

5

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) (unaudited)
	Three Months Ended
	March 31,
	2015			2014
Operating activities
Net income	$	21.7		$	5.5
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion	59.9			50.8
Amortization of debt-related deferred costs and premiums	1.9			1.8
Unit-based compensation charges	5.2			4.6
(Gain) loss on long-lived assets	0.8			(0.5		)
Loss on contingent consideration	—			2.1
(Earnings) loss from unconsolidated affiliates, net	(3.4		)	0.1
Deferred income taxes	0.1			0.5
Other	—			0.2
Changes in operating assets and liabilities, net of effects from acquisitions	(9.2		)	2.6
Net cash provided by operating activities	77.0			67.7
Investing activities
Acquisitions, net of cash acquired (Note 3)	—			(12.1		)
Purchases of property, plant and equipment	(43.3		)	(77.3		)
Investment in unconsolidated affiliates	(17.9		)	(19.8		)
Proceeds from sale of assets	0.3			—
Net cash used in investing activities	(60.9		)	(109.2		)
Financing activities
Proceeds from the issuance of long-term debt	1,114.6			306.0
Principal payments on long-term debt	(970.0		)	(188.8		)
Payments on capital leases	(0.7		)	(1.1		)
Payments for debt-related deferred costs	(11.1		)	—
Distributions to limited partners	(74.3		)	(74.1		)
Distributions to general partner	(10.5		)	(10.5		)
Net proceeds from issuance of preferred equity of subsidiary	—			12.3
Taxes paid for unit-based compensation vesting	(1.7		)	—
Other	(0.2		)	—
Net cash provided by financing activities	46.1			43.8
Net change in cash	62.2			2.3
Cash at beginning of period	4.6			2.7
Cash at end of period	$	66.8		$	5.0
Supplemental schedule of non-cash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(9.1	)	$	(3.4	)

See accompanying notes.

6

CRESTWOOD MIDSTREAM PARTNERS LP

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, the marketing of NGLs, and the gathering, storage and transportation of crude oil.

Crestwood Equity Partners LP (CEQP) indirectly owns a non-economic general partnership interest in us 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. As of March 31, 2015, CEQP directly owns approximately 4% of our common limited partnership units. CEQP is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), which owns approximately 11% of our common units as of March 31, 2015. Crestwood Holdings is substantially owned and controlled by First Reserve Management, L.P. (First Reserve).

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

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

• Storage and Transportation: our storage and transportation operations provide regulated natural gas storage and transportation services to producers, utilities and other customers. This segment primarily includes our natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake) and 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 solution-mining and salt production company (US Salt) and Bath storage facility in New York.

On May 5, 2015, CEQP, CMLP and certain of its affiliates entered into a definitive agreement under which CMLP has agreed to merge with a wholly-owned subsidiary of CEQP, with CMLP surviving as a wholly-owned subsidiary of CEQP.  As part of the merger consideration, CMLP’s unitholders will become unitholders of CEQP in a tax free exchange, with CMLP’s common unitholders receiving 2.75 common units of CEQP for each common unit of CMLP held upon completion of the merger.  CMLP’s IDRs will also be eliminated upon completion of the merger and CMLP’s common units will cease to be listed on the NYSE.  CMLP expects to complete the merger in the third quarter of 2015, subject to the approval of Crestwood Midstream's unitholders and customary closing conditions.

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.

7

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

Basis of Presentation

The financial information as of March 31, 2015, and for the three months endedMarch 31, 2015 and 2014, is unaudited. The consolidated balance sheet as of December 31, 2014, was derived from the audited balance sheet filed in our 2014 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).

Our consolidated financial statements for the prior period include reclassifications that were made to conform to the current period presentation. Cash inflows of $9.6 million related to reimbursements of capital expenditures from producers have been reclassified from investing activities to changes in operating assets and liabilities, net of effects from acquisitions under operating activities in our consolidated statements of cash flows for the three months endedMarch 31, 2014 to conform with the current period presentation. The reclassification was not significant to our previously reported consolidated financial statements.

The accompanying consolidated financial statements should be read in conjunction with our 2014 Annual Report on Form 10-K filed with the SEC on February 27, 2015.

Significant Accounting Policies

There were no material changes in our significant accounting policies from those described in our 2014 Annual Report on Form 10-K.

New Accounting Pronouncements Issued But Not Yet Adopted

As of March 31, 2015, the following accounting standards had not yet been adopted by us.

In May 2014, the Financial Accounting Standards Board (FASB) 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 expect to adopt the provisions of this standard effective January 1, 2017 and are currently evaluating the impact that this standard will have on our consolidated financial statements. In April 2015, the FASB proposed deferring the effective date of this standard by one year.

In February 2015, the FASB issued Accounting Standards Update 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which provides additional guidance on the consolidation of limited partnerships and on the evaluation of variable interest entities. We expect to adopt the provisions of this standard effective January 1, 2016 and are currently evaluating the impact, if any, that this standard may have on our consolidated financial statements.

In April 2015, the FASB issued Accounting Standards Update 2015-03, Interest - Imputation of Interest (Subtopic 835-30), which requires deferred debt issuance costs to be classified as a reduction of the debt liability rather than as an asset in the balance sheet. We expect to adopt the provisions of this standard effective January 1, 2016, and do not currently anticipate it will have a significant impact on our consolidated financial statements.

8

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 3 – Acquisition

2014 Acquisition

Crude Transportation Acquisition (Bakken)

Red Rock. On March 21, 2014, we purchased substantially all of the trucking operations of Red Rock Transportation Inc. (Red Rock) for approximately $13.8 million, comprised of $12.1 million paid at closing plus deferred payments of $1.8 million. These operations are located in Watford City, North Dakota and provide 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.

This acquisition was not material to our NGL and crude services segment's results of operations for the three months endedMarch 31, 2014. In addition, transaction costs related to this acquisition was not material for the three months endedMarch 31, 2014.

Note 4 – Certain Balance Sheet Information

Property, Plant and Equipment

Property, plant and equipment consisted of the following at March 31, 2015 and December 31, 2014 (in millions):

	March 31, 2015		December 31, 2014
Gathering systems and pipelines	1,281.2		1,276.6
Facilities and equipment	1,458.0		1,468.8
Buildings, land, rights-of-way, storage contracts and easements	808.1		806.4
Vehicles	14.1		13.6
Construction in process	171.2		153.7
Base gas	37.5		37.5
Salt deposits	120.5		120.5
Office furniture and fixtures	6.4		6.4
	3,897.0		3,883.5
Less: accumulated depreciation and depletion	391.6		365.4
Total property, plant and equipment, net	$	3,505.4	$	3,518.1

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 $2.6 million and $2.8 million included in property, plant and equipment, net at March 31, 2015 and December 31, 2014.

9

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Intangible Assets

Intangible assets consisted of the following at March 31, 2015 and December 31, 2014 (in millions):

	March 31, 2015		December 31, 2014
Customer accounts	$	483.2	$	483.2
Covenants not to compete	5.6		5.6
Gas gathering, compression and processing contracts	427.3		431.4
Acquired storage contracts	29.0		29.0
Trademarks	9.7		9.7
Deferred financing costs	65.4		54.3
	1,020.2		1,013.2
Less: accumulated amortization	155.5		137.0
Total intangible assets, net	$	864.7	$	876.2

Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at March 31, 2015 and December 31, 2014 (in millions):

	March 31, 2015		December 31, 2014
Accrued expenses	$	17.9	$	23.7
Accrued property taxes	3.9		2.1
Accrued product purchases payable	0.4		0.7
Tax payable	—		0.4
Interest payable	13.5		22.0
Accrued additions to property, plant and equipment	9.1		20.0
Commitments and contingent liabilities (Note 10)	—		40.0
Capital leases	0.9		1.3
Deferred revenue	11.3		11.6
Other	—		0.2
Total accrued expenses and other liabilities	$	57.0	$	122.0

10

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 5 - Investments in Unconsolidated Affiliates

Net Investment and Earnings (Loss)

Our net investments in and earnings (loss) from our unconsolidated affiliates are as follows (in millions, unless otherwise stated):

	Ownership Percentage			Investment				Earnings (Loss) from Unconsolidated Affiliates
	March 31,			March 31,		December 31,		Three Months Ended March 31,
	2015			2015		2014		2015		2014
Jackalope Gas Gathering Services, L.L.C.(1)	50.00	%	(4)	$	244.2	$	232.9	$	2.5	$	0.3
Tres Palacios Holdings LLC(2)	50.01	%		42.8		36.0		0.9		—
Powder River Basin Industrial Complex, LLC(3)	50.01	%		29.6		26.2		—		(0.4		)
Total				$	316.6	$	295.1	$	3.4	$	(0.1	)

(1) As of March 31, 2015, our investment balance exceeded our equity in the underlying net assets of Jackalope Gas Gathering Services, L.L.C. (Jackalope)by approximately $52.9 million. We amortize and generally assess the recoverability of this amount over 20 years, which represents the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation and RKI Exploration and Production, LLC, and reflect the amortization as a reduction of our earnings from unconsolidated affiliates. For the three months ended March 31, 2015 and 2014, we recorded amortization of approximately $0.8 million. Our Jackalope investment is included in our gathering and processing segment.

(2) In December 2014, one of our consolidated subsidiaries and an affiliate of Brookfield Infrastructure Group (Brookfield) formed the Tres Palacios Holdings LLC (Tres Holdings) joint venture. For more information on our joint venture, see our 2014 Annual Report on Form 10-K filed with the SEC. As of March 31, 2015, our equity in the underlying net assets exceeded our investment balance in Tres Holdings by approximately $30.0 million. We amortize and generally assess the recoverability of this amount over the life of the Tres Palacios Gas Storage LLC (Tres Palacios) sublease agreement, and reflect the amortization as an increase of our earnings from unconsolidated affiliates. For the three months ended March 31, 2015, we recorded amortization of approximately $0.3 million. Our Tres Holdings investment is included in our storage and transportation segment.

(3) As of March 31, 2015, our investment balance approximated our equity in the underlying net assets of Powder River Basin Industrial Complex, LLC (PRBIC). Our PRBIC investment is included in our NGL and crude services segment.

(4) Excludes non-controlling interests related to our investment in Jackalope. See Note 8 for a further discussion of our non-controlling interest related to our investment in Jackalope.

Distributions and Contributions

Jackalope.Jackalope is required, within 30 days following the end of each quarter, to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the three months endedMarch 31, 2015 and 2014, Jackalope did not make any distributions to its members. In April 2015, we received a cash distribution of approximately $4.5 million from Jackalope. During the three months endedMarch 31, 2015 and 2014, we contributed approximately $8.8 million and $17.3 million to Jackalope.

Tres Holdings. Tres Holdings is required, within 30 days following the end of each quarter, to make quarterly distributions of its available cash (as defined in its limited liability company agreement) to its members based on their respective ownership percentage. In April 2015, we received a cash distribution of approximately $2.1 million from Tres Holdings. During the three months endedMarch 31, 2015, we contributed approximately $5.7 million to Tres Holdings.

PRBIC. PRBIC is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the three months endedMarch 31, 2015, we received a cash distribution of approximately $0.3 million from PRBIC as a return of capital. During the three months endedMarch 31, 2014, PRBIC did not make any distributions to its members. In addition, during the three months endedMarch 31, 2015 and 2014, we contributed approximately $3.7 million and $2.5 million to PRBIC.

11

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 6 - 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 March 31, 2015 and December 31, 2014, 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.

We enter 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 March 31, 2015, our outstanding positions and the related impact to our consolidated statement of operations associated with our risk management activities were not material. As of March 31, 2014, we did not have any risk management activities.

As of March 31, 2015 and December 31, 2014, the carrying amounts of cash, 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 March 31, 2015 and December 31, 2014 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):

	March 31, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2019 Senior Notes	$	350.9	$	363.6	$	351.0	$	360.5
2020 Senior Notes	$	503.8	$	500.3	$	504.0	$	481.6
2022 Senior Notes	$	600.0	$	607.5	$	600.0	$	568.5
2023 Senior Notes	$	700.0	$	710.5	$	—	$	—

12

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Debt

Long-term debt consisted of the following at March 31, 2015 and December 31, 2014 (in millions):

	March 31, 2015		December 31, 2014
Credit Facility	$	—	$	555.0
2019 Senior Notes	350.0		350.0
Premium on 2019 Senior Notes	0.9		1.0
2020 Senior Notes	500.0		500.0
Fair value adjustment of 2020 Senior Notes	3.8		4.0
2022 Senior Notes	600.0		600.0
2023 Senior Notes	700.0		—
Other	3.1		3.5
Total debt	2,157.8		2,013.5
Less: current portion	36.1		0.7
Total long-term debt	$	2,121.7	$	2,012.8

Credit Facility

We have a five-year $1.0 billion senior secured revolving credit facility (the Credit Facility), which expires in October 2018 and 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 subsidiaries except for Crestwood Niobrara LLC (Crestwood Niobrara), PRBIC and Tres Holdings and their respective subsidiaries.

At March 31, 2015, we had $429.1 million of available capacity under the Credit Facility considering the most restrictive debt covenants in our credit agreement. In March 2015, we utilized proceeds from our 2023 Senior Notes offerings to pay down the outstanding balance on our Credit Facility as discussed below. At March 31, 2015 and December 31, 2014, our outstanding standby letters of credit were $5.6 million and $15.1 million. Borrowings under our Credit Facility accrue interest at prime or LIBOR-based rates plus applicable spreads, which resulted in interest rates between 2.66% and 4.75% at December 31, 2014. The weighted-average interest rate as of December 31, 2014 was 2.86%.

We are required under our credit agreement to maintain a net debt to consolidated EBITDA ratio (as defined in our credit agreement) of not more than 5.00 to 1.0 (or, if applicable, 5.50 to 1.0 during certain periods immediately following a material acquisition by us) and a consolidated EBITDA to consolidated interest expense ratio (as defined in our credit agreement) of not less than 2.50 to 1.0. As a result of our election to increase the permitted net debt to consolidated EBITDA ratio in conjunction with our 50.01% acquisition of Tres Palacios, the net debt to consolidated EBITDA ratio required by our credit agreement is 5.50 for a 270-day period commencing December 3, 2014. At March 31, 2015, our net debt to consolidated EBITDA was approximately 4.58 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 4.15 to 1.0.

Senior Notes

As of March 31, 2015, we had four 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), (iii) $600 million in aggregate principal amount of 6.125% Senior Notes due 2022 (the 2022 Senior Notes), and (iv) $700 million in aggregate principal amount of 6.25% Senior Notes due 2023 (the 2023 Senior Notes and together with the 2019 Senior Notes, the 2020 Senior Notes and the 2022 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.

13

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

In March 2015, we issued $700 million of 6.25% unsecured Senior Notes due 2023 in a private offering. The 2023 Senior Notes will mature on April 1, 2023, and interest is payable semiannually in arrears on April 1 and October 1 of each year, beginning October 1, 2015. The net proceeds from this offering of approximately $688.9 million were used to pay down borrowings under our Credit Facility and for our general partnership purposes.

On April 8, 2015, we redeemed the 2019 Senior Notes for approximately $364.1 million, including accrued interest of $0.5 million and a call premium of $13.6 million. We utilized approximately $315 million of our Credit Facility to redeem all of the outstanding 2019 Senior Notes.

At March 31, 2015, 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 2014 Annual Report on Form 10-K filed with the SEC.

Other

For a description of our non-interest bearing obligations due under noncompetition agreements, see our 2014 Annual Report on Form 10-K filed with the SEC.

Note 7 - Earnings Per Limited Partner Unit

CEQP, through its wholly-owned subsidiaries, 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 months endedMarch 31, 2015 and 2014 (in millions):

Allocation of Net Income Attributable to CMLP
	Three Months Ended
	March 31,
	2015			2014
Net income attributable to CMLP	$	16.1		$	2.4
Class A preferred units’ interest in net income attributable to CMLP	(9.2		)	—
General partner’s incentive distributions	(7.5		)	(7.5		)
Limited partners’ interest in net income (loss) attributable to CMLP after incentive distributions	$	(0.6	)	$	(5.1	)

14

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Earnings Per Limited Partner Unit
	Three Months Ended
	March 31,
	2015			2014
Limited partners’ interest in net income (loss)	$	(0.6	)	$	(5.1	)
Weighted-average limited partner units - basic	188.3			187.8
Effect of diluted units	—			—
Weighted-average limited partner units - diluted	188.3			187.8
Basic earnings per unit:
Net income (loss) per limited partner	$	—		$	(0.03	)
Diluted earnings per unit:
Net income (loss) per limited partner	$	—		$	(0.03	)

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 months endedMarch 31, 2015, we also excluded a weighted-average of 18,332,193 common units, representing Class A preferred units if converted to common units, from our diluted earnings per unit. During the three months endedMarch 31, 2015 and 2014, we excluded a weighted-average of 12,325,740 and 4,922,372 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.

Note 8 - Partners’ Capital

Class A Preferred Units

On June 17, 2014, we entered into definitive agreements with a group of investors, including Magnetar Financial, 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. During the three months ended March 31, 2015 and through the date of this filing, we did not sell any Preferred Units to the Class A Purchasers under these agreements. For additional information on our Class A Preferred Units, see our 2014 Annual Report on Form 10-K filed with the SEC.

Equity Distribution Agreement

We entered into an equity distribution program with certain financial institutions (each, a Manager) under which we are allowed to 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. We will pay the Managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under this at-the-market program. We did not issue any common units under this equity distribution program as of March 31, 2015 and through the date of this filing.

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 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

During the three months endedMarch 31, 2015 and 2014, we paid cash distributions to our general partner (representing IDRs and distributions related to common units held by the general partner) of approximately $10.5 million.

15

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Distributions to Class A Preferred Unit Holders

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

On April 23, 2015, the board of directors of our general partner authorized the issuance of 423,903 Class A Preferred Units to our preferred unitholders for the quarter ended March 31, 2015 in lieu of paying a cash distribution. On February 13, 2015, we issued 414,325 Class A Preferred Units to our preferred unitholders for the quarter ended December 31, 2014 in lieu of paying a cash distribution.

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 three months endedMarch 31, 2015 and 2014:

Record Date	Payment Date	Per Unit Rate		Cash Distribution (in millions)
2015
February 6, 2015	February 13, 2015	$	0.41	$	74.3
2014
February 7, 2014	February 14, 2014	$	0.41	$	74.1

On April 23, 2015, we declared a distribution of $0.41 per limited partner unit to be paid on May 15, 2015, to unitholders of record on May 8, 2015 with respect to the first quarter of 2015.

Non-Controlling Partners

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, which is reflected as non-controlling interest in our consolidated financial statements. During the three months endedMarch 31, 2014, GE made capital contributions of $12.3 million to Crestwood Niobrara in exchange for an equivalent number of preferred units. During the three months endedMarch 31, 2015 and 2014, Crestwood Niobrara issued 3,680,570 and 2,210,294 preferred units to GE in lieu of paying a cash distribution. Beginning in the first quarter of 2015, Crestwood Niobrara no longer had the option to pay distributions to GE by issuing additional preferred units in lieu of paying a cash distribution. On April 30, 2015, Crestwood Niobrara paid a distribution of $3.8 million to GE for the quarter ended March 31, 2015.

16

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 9 - Equity Plans

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

Crestwood LTIP

The following table summarizes information regarding restricted unit activity during the three months endedMarch 31, 2015:

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2015	834,796		$	23.18
Vested - restricted units	(424,653	)	$	23.11
Granted - restricted units	512,404		$	16.01
Granted - phantom units	161,039		$	16.02
Forfeited(1)	(37,997	)	$	20.93
Unvested - March 31, 2015	1,045,589		$	18.68

(1) We implemented a company-wide initiative to reduce operating costs in 2015 and beyond, which included a reduction in work force. As a result, 21,583 restricted units were forfeited during the three months endedMarch 31, 2015.

As of March 31, 2015 and December 31, 2014, we had total unamortized compensation expense of approximately $15.7 million and $9.5 million related to restricted and phantom 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 $3.0 million and $2.9 million during the three months endedMarch 31, 2015 and 2014, which is included in general and administrative expenses on our consolidated statements of operations. An additional $2.2 million and $1.7 million of net compensation expense was allocated from CEQP to us during the three months endedMarch 31, 2015 and 2014 (see Note 11). We granted restricted and phantom units with a grant date fair value of approximately $8.2 million and $2.6 million during the three months endedMarch 31, 2015.  As of March 31, 2015, we had 17,199,153 units available for issuance under the Crestwood LTIP.

Restricted Units.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 endedMarch 31, 2015 and 2014, we withheld 134,591 and 7,456 common units to satisfy employee tax withholding obligations.

Phantom Units.The Crestwood LTIP currently permits, and our general partner has made, grants of phantom units. Each phantom unit entitles the holder thereof to receive upon vesting one common unit of CMLP granted pursuant to the Crestwood LTIP and a phantom unit award agreement (the Phantom Unit Agreement). The Phantom Unit Agreement provides for vesting to occur at the end of three years following the grant date or, if earlier, upon the named executive officer's termination without cause or due to death or disability or the named executive officer's resignation for employee cause (each, as defined in the Phantom Unit Agreement). In addition, the Phantom Unit Agreement provides for distribution equivalent rights with respect to each phantom unit which are paid in additional phantom units and settled in common units upon vesting of the underlying phantom units.

17

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Employee Unit Purchase Plan

We have an employee unit purchase plan under which employees of the general partner may purchase our common units through payroll deductions up to a maximum of 10% of the employees' eligible compensation. Under the plan, we may purchase our common units on the open market for the benefit of participating employees based on their payroll deductions.  In addition, we may contribute an additional 10% of participating employees' payroll deductions to purchase additional Crestwood common 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. During the three months ended March 31, 2015, there were 2,011 common units purchased through the employee unit purchase plan related to the fourth quarter of 2014. In April 2015, there were 3,841 common units purchased related to the first quarter of 2015.

Note 10 - Commitments and Contingencies

Legal Proceedings

Canadian Class Action Lawsuit. Prior to the completion of our acquisition of Arrow 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 (the Class Action Suit).

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 in the first half of 2015.

There are three other lawsuits related to the Class Action Suit. Montreal Main & Atlantic Railway filed bankruptcy actions in both the U.S. Bankruptcy Court for the District of Maine and in the Canadian Bankruptcy Court. In addition, a lawsuit was filed in Cook County, Illinois on behalf of the deceased claimants, which is currently stayed due to the bankruptcy proceeding. We are not currently named as a defendant in these additional lawsuits; however, we have been notified by the bankruptcy trustees of a proposal to contribute to a settlement in exchange for a release from all claims related to the Class Action Suit. We have evaluated this proposal and made a confidential contingent offer to the Bankruptcy Trustee.

We will vigorously defend ourselves and, to the extent these actions proceed, we believe we have meritorious defenses to the claims.  Because these related actions are in the early stages of the proceeding, we are unable to estimate a reasonably possible loss or range of loss in this matter.  We also believe these claims are insurable under our insurance policy and we have notified our insurance company of them.

18

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

When we were served with the Class Action Suit, we notified the former owners of the Arrow system that the claims alleged in the Class Action Suit would, if true, result in breaches of certain representations and warranties made by the former sellers in the agreement under which we acquired Arrow. As part of the acquisition, we deposited 3,309,797 of our common units into an escrow account to cover potential indemnification claims made by us on or before December 31, 2014. Subject to indemnification claims paid out with escrowed units and any outstanding claims outstanding at year end, all common units remaining in the escrow account on January 1, 2015 were to be released to the former owners. In December 2014, we notified the escrow agent of our indemnification notices delivered to the former owners and instructed the escrow agent not to release any escrowed units to the former owners. On February 19, 2015, we received a summons for an action filed against us in the Supreme Court of the State of New York (County of New York), under which the former owners have asserted our indemnification notices regarding the Class Action Suit and our notice to the escrow agent breach the terms of the merger and escrow agreements and the implied covenant of good faith and fair dealing.  The former owners have requested declaratory and injunctive relief, as well as monetary damages. Although our insurance policies would not cover this action, we believe we have meritorious defenses to this lawsuit and will aggressively defend ourselves. We are unable to estimate a reasonably possible loss or range of loss in this matter due to the recent filing of this lawsuit.

General. 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 March 31, 2015 and December 31, 2014, 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 2014, we experienced three 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. We will continue our remediation efforts to ensure the impacted lands are restored to their prior state. We believe these releases are insurable events under our policies, and we have notified our carriers of these events. We have not recorded an insurance receivable as of March 31, 2015. In May 2015, we experienced a release of up to 8,000 barrels of produced water on our Arrow water gathering system, and immediately notified numerous regulatory authorities and other third parties.  We are currently evaluating the extent of the release and its impact on the related lands, and because this matter is in the early stages of investigation, we are unable to estimate a reasonably possible loss or range of loss.

We may potentially be subject to fines and penalties as a result of the water releases.  We received data requests from the Environmental Protection Agency (EPA) related to the releases in October 2014, responded to the EPA’s original request for information in January 2015, and are working to respond to supplemental requests received from the EPA in the first quarter of 2015.  On April 16, 2015, the EPA issued a Notice of Potential Violation relating to the water releases, and we anticipate responding to the Notice of Potential Violation in May 2015. On March 3, 2015, we received a grand jury subpoena from the United States Attorney’s Office in Bismarck, North Dakota, seeking documents and information relating to the largest of the

19

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

three releases, and we are in the process of providing the requested information. We cannot predict what the outcome of these investigations will be, and we had no amounts accrued for fines or penalties as of March 31, 2015.

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 March 31, 2015 and December 31, 2014, our accrual of approximately $0.3 million and $1.1 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 $0.3 million to $0.8 million.

Contingent Consideration - Antero

In connection with the acquisition of Antero Resources Appalachian Corporation (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. In February 2015, we paid Antero $40.0 million to settle the liability under the earn-out provision. This amount is reflected in changes in operating assets and liabilities, net of effects from acquisitions under operating activities in our consolidated statements of cash flows.

Note 11 - Related Party Transactions

We do not have any employees. We share common management, general 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. 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 months endedMarch 31, 2015 and 2014 (in millions):

	Three Months Ended
	March 31,
	2015		2014
Gathering and processing revenues	$	1.2	$	0.9
NGL and crude services revenues	$	3.4	$	3.3
Gathering and processing costs of product/services sold (1)	$	8.3	$	11.0
General and administrative expenses (2)	$	17.4	$	19.6
Reimbursement of operations and maintenance expenses	$	0.9	$	—

(1) Represents natural gas purchases from Sabine Oil and Gas LLC.

(2) Included in general and administrative expenses is approximately $2.2 million and $1.7 million of net unit-based compensation charges allocated to us from CEQP for the three months endedMarch 31, 2015 and 2014.

The following table shows accounts receivable and accounts payable from our affiliates as of March 31, 2015 and December 31, 2014 (in millions):

	March 31, 2015		December 31, 2014
Accounts receivable	$	1.1	$	0.3
Accounts payable	$	5.5	$	6.3

20

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

For additional information regarding our related party transactions, see our 2014 Annual Report on Form 10-K filed with the SEC.

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.

Below is a reconciliation of net income to EBITDA (in millions):

	Three Months Ended
	March 31,
	2015		2014
Net income	$	21.7	$	5.5
Add:
Interest and debt expense, net	29.9		28.1
Provision for income taxes	0.3		0.7
Depreciation, amortization and accretion	59.9		50.8
EBITDA	$	111.8	$	85.1

21

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

The following tables summarize the reportable segment data for the three months endedMarch 31, 2015 and 2014 (in millions).

	Three Months Ended March 31, 2015
	Gathering and Processing			Storage and Transportation			NGL and Crude Services		Corporate			Total
Revenues	$	78.5		$	45.7		$	330.9	$	—		$	455.1
Costs of product/services sold	12.7			3.3			270.6		—			286.6
Operations and maintenance expense	14.9			4.3			15.9		—			35.1
General and administrative expense	—			—			—		24.2			24.2
Loss on long-lived assets	(0.3		)	(0.5		)	—		—			(0.8		)
Earnings from unconsolidated affiliates, net	2.5			0.9			—		—			3.4
EBITDA	$	53.1		$	38.5		$	44.4	$	(24.2	)	$	111.8
Goodwill	$	81.1		$	726.3		$	825.2	$	—		$	1,632.6
Total assets	$	1,969.6		$	1,976.1		$	2,514.0	$	153.0		$	6,612.7
Purchases of property, plant and equipment	$	11.4		$	2.7		$	29.1	$	0.1		$	43.3

	Three Months Ended March 31, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	79.5		$	44.3	$	413.2		$	—		$	537.0
Costs of product/services sold	18.7			3.2		376.2			—			398.1
Operations and maintenance expense	13.4			4.3		10.3			—			28.0
General and administrative expense	—			—		—			24.1			24.1
Gain on long-lived assets	0.5			—		—			—			0.5
Loss on contingent consideration	(2.1		)	—		—			—			(2.1		)
Earnings (loss) from unconsolidated affiliates, net	0.3			—		(0.4		)	—			(0.1		)
EBITDA	$	46.1		$	36.8	$	26.3		$	(24.1	)	$	85.1
Goodwill	$	99.6		$	728.6	$	861.1		$	—		$	1,689.3
Total assets	$	1,881.6		$	1,975.5	$	2,478.0		$	156.3		$	6,491.4
Purchases of property, plant and equipment	$	46.3		$	1.2	$	28.9		$	0.9		$	77.3

Note 13 – Condensed Consolidating Financial Information

Crestwood is a holding company and owns no operating assets and has no significant operations independent of our subsidiaries. Obligations under our Senior Notes and our Credit Facility are jointly and severally guaranteed by substantially all of our subsidiaries, except for Crestwood Niobrara, PRBIC and Tres Holdings and their respective 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.

As summarized in the table below, the condensed consolidating financial statements for the three months endedMarch 31, 2014 have been corrected for certain errors in presentation. There was no impact to our consolidated statement of operations or our consolidated statement of cash flows for the three months endedMarch 31, 2014.

22

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

	Parent						Guarantor Subsidiaries				Eliminations
	As Adjusted			As Previously Reported			As Adjusted		As Previously Reported		As Adjusted			As Previously Reported
	(in millions)
General and administrative expense	$	17.0		$	(2.1	)	$	7.1	$	26.2	$	—		$	—
Operating income (loss)	(17.2		)	1.9			51.6		32.5		—			—
Equity in net income (loss) of subsidiary	50.8			31.7			—		—		(50.8		)	(31.7		)
Income (loss) before income taxes	5.5			5.5			51.6		32.5		(50.8		)	(31.7		)
Net income (loss)	5.5			5.5			50.9		31.8		(50.8		)	(31.7		)
Net income (loss) attributable to Crestwood Midstream Partners LP	5.5			5.5			50.9		31.8		(50.8		)	(31.7		)

	Parent						Guarantor Subsidiaries						Non-Guarantor Subsidiaries						Eliminations
	As Adjusted			As Previously Reported			As Adjusted			As Previously Reported			As Adjusted			As Previously Reported			As Adjusted			As Previously Reported
	(in millions)
Cash flows from operating activities:	$	(39.6	)	$	5.8		$	107.3		$	52.3		$	—		$	—		$	—		$	—
Cash flows from investing activities:
Investment in unconsolidated affiliates, net	—			—			—			(2.5		)	(19.8		)	(17.3		)	—			—
Capital contributions from consolidated affiliates	(6.5		)	(4.0		)	—			—			—			—			6.5			4.0
Other	—			(2.4		)	—			—			—			—			—			2.4
Net cash provided by (used in) investing activities	(7.4		)	(7.3		)	(88.5		)	(81.4		)	(19.8		)	(17.3		)	6.5			6.4
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	306.0			2.5			—			303.5			—			—			—			—
Principal payments on long-term debt	(188.8		)	—			—			(188.8		)	—			—			—			—
Distributions paid	(84.6		)	—			—			(84.6		)	—			—			—			—
Contributions from parent	—			—			—			—			6.5			4.0			(6.5		)	(4.0		)
Change in intercompany balances	15.4			—			(15.4		)	2.4			—			—			—			(2.4		)
Net cash provided by (used in) financing activities	47.7			2.2			(16.2		)	31.7			18.8			16.3			(6.5		)	(6.4		)

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 March 31, 2015 and December 31, 2014, and for the three months endedMarch 31, 2015 and 2014.  The financial information may not necessarily be indicative of the results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

23

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Balance Sheet
March 31, 2015
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	—	$	66.8	$	—	$	—		$	66.8
Accounts receivable	0.9		190.6		—		—			191.5
Accounts receivable - related party	—		—		1.1		—			1.1
Total accounts receivable	0.9		190.6		1.1		—			192.6
Inventories	—		9.2		—		—			9.2
Other current assets	—		23.6		—		—			23.6
Total current assets	0.9		290.2		1.1		—			292.2
Property, plant and equipment, net	7.3		3,498.1		—		—			3,505.4
Goodwill and intangible assets, net	47.0		2,450.3		—		—			2,497.3
Investment in consolidated affiliates	6,359.5		—		—		(6,359.5		)	—
Investment in unconsolidated affiliates	—		—		316.6		—			316.6
Other assets	—		1.2		—		—			1.2
Total assets	$	6,414.7	$	6,239.8	$	317.7	$	(6,359.5	)	$	6,612.7
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	1.3	$	121.8	$	—	$	—		$	123.1
Accounts payable - related party	3.2		1.3		1.0		—			5.5
Total accounts payable	4.5		123.1		1.0		—			128.6
Other current liabilities	49.5		43.6		—		—			93.1
Total current liabilities	54.0		166.7		1.0		—			221.7
Long-term liabilities:
Long-term debt, less current portion	2,121.7		—		—		—			2,121.7
Other long-term liabilities	1.2		30.3		—		—			31.5
Partners' capital	4,060.5		6,042.8		139.4		(6,182.2		)	4,060.5
Interest of non-controlling partners in subsidiaries	177.3		—		177.3		(177.3		)	177.3
Total partners' capital	4,237.8		6,042.8		316.7		(6,359.5		)	4,237.8
Total liabilities and partners' capital	$	6,414.7	$	6,239.8	$	317.7	$	(6,359.5	)	$	6,612.7

24

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Balance Sheet
December 31, 2014
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	—	$	4.6	$	—	$	—		$	4.6
Accounts receivable	1.2		240.3		—		—			241.5
Accounts receivable - related party	—		—		0.3		—			0.3
Total accounts receivable	1.2		240.3		0.3		—			241.8
Inventories	—		8.0		—		—			8.0
Other current assets	—		18.7		—		—			18.7
Total current assets	1.2		271.6		0.3		—			273.1
Property, plant and equipment, net	7.9		3,510.2		—		—			3,518.1
Goodwill and intangible assets, net	38.0		2,470.8		—		—			2,508.8
Investment in consolidated affiliates	6,296.7		—		—		(6,296.7		)	—
Investment in unconsolidated affiliates	—		—		295.1		—			295.1
Other assets	—		1.4		—		—			1.4
Total assets	$	6,343.8	$	6,254.0	$	295.4	$	(6,296.7	)	$	6,596.5
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	4.8	$	121.3	$	—	$	—		$	126.1
Accounts payable - related party	4.2		1.9		0.2		—			6.3
Total accounts payable	9.0		123.2		0.2		—			132.4
Other current liabilities	23.0		99.7		—		—			122.7
Total current liabilities	32.0		222.9		0.2		—			255.1
Long-term liabilities:
Long-term debt, less current portion	2,012.8		—		—		—			2,012.8
Other long-term liabilities	1.6		29.6		—		—			31.2
Partners' capital	4,125.7		6,001.5		123.5		(6,125.0		)	4,125.7
Interest of non-controlling partners in subsidiaries	171.7		—		171.7		(171.7		)	171.7
Total partners' capital	4,297.4		6,001.5		295.2		(6,296.7		)	4,297.4
Total liabilities and partners' capital	$	6,343.8	$	6,254.0	$	295.4	$	(6,296.7	)	$	6,596.5

25

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Three Months Ended March 31, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	455.1		$	—		$	—		$	455.1
Costs of product/services sold	—			286.6			—			—			286.6
Expenses:
Operations and maintenance	—			35.1			—			—			35.1
General and administrative	13.4			10.8			—			—			24.2
Depreciation, amortization and accretion	0.2			59.7			—			—			59.9
	13.6			105.6			—			—			119.2
Other operating income (expense):
Loss on long-lived assets, net	—			(0.8		)	—			—			(0.8		)
Operating income	(13.6		)	62.1			—			—			48.5
Earnings from unconsolidated affiliates, net	—			—			3.4			—			3.4
Interest and debt expense, net	(29.9		)	—			—			—			(29.9		)
Equity in net income (loss) of subsidiary	65.2			—			—			(65.2		)	—
Income (loss) before income taxes	21.7			62.1			3.4			(65.2		)	22.0
Provision for income taxes	—			0.3			—			—			0.3
Net income (loss)	21.7			61.8			3.4			(65.2		)	21.7
Net income attributable to non-controlling partners	—			—			(5.6		)	—			(5.6		)
Net income (loss) attributable to Crestwood Midstream Partners LP	21.7			61.8			(2.2		)	(65.2		)	16.1
Net income attributable to Class A preferred units	(9.2		)	—			—			—			(9.2		)
Net income (loss) attributable to partners	$	12.5		$	61.8		$	(2.2	)	$	(65.2	)	$	6.9

26

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Three Months Ended March 31, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	537.0		$	—		$	—		$	537.0
Costs of product/services sold	—			398.1			—			—			398.1
Expenses:
Operations and maintenance	—			28.0			—			—			28.0
General and administrative	17.0			7.1			—			—			24.1
Depreciation, amortization and accretion	0.2			50.6			—			—			50.8
	17.2			85.7			—			—			102.9
Other operating income (expense):
Gain on long-lived assets, net	—			0.5			—			—			0.5
Loss on contingent consideration	—			(2.1		)	—			—			(2.1		)
Operating income (loss)	(17.2		)	51.6			—			—			34.4
Loss from unconsolidated affiliates, net	—			—			(0.1		)	—			(0.1		)
Interest and debt expense, net	(28.1		)	—			—			—			(28.1		)
Equity in net income (loss) of subsidiary	50.8			—			—			(50.8		)	—
Income (loss) before income taxes	5.5			51.6			(0.1		)	(50.8		)	6.2
Provision for income taxes	—			0.7			—			—			0.7
Net income (loss)	5.5			50.9			(0.1		)	(50.8		)	5.5
Net income attributable to non-controlling partners	—			—			(3.1		)	—			(3.1		)
Net income (loss) attributable to Crestwood Midstream Partners LP	$	5.5		$	50.9		$	(3.2	)	$	(50.8	)	$	2.4

27

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Cash Flows
Three Months Ended March 31, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(54.8	)	$	131.8		$	—		$	—		$	77.0
Cash flows from investing activities:
Purchases of property, plant and equipment	(0.1		)	(43.2		)	—			—			(43.3		)
Investment in unconsolidated affiliates	—			—			(17.9		)	—			(17.9		)
Proceeds from sale of assets	—			0.3			—			—			0.3
Capital contribution to consolidated affiliates	(17.9		)	—			—			17.9			—
Net cash provided by (used in) investing activities	(18.0		)	(42.9		)	(17.9		)	17.9			(60.9		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	1,114.6			—			—			—			1,114.6
Principal payments on long-term debt	(970.0		)	—			—			—			(970.0		)
Payments on capital leases	(0.5		)	(0.2		)	—			—			(0.7		)
Payments for debt-related deferred costs	(11.1		)	—			—			—			(11.1		)
Distributions paid	(84.8		)	—			—			—			(84.8		)
Contributions from parent	—			—			17.9			(17.9		)	—
Taxes paid for unit-based compensation vesting	—			(1.7		)	—			—			(1.7		)
Change in intercompany balances	24.8			(24.8		)	—			—			—
Other	(0.2		)	—			—			—			(0.2		)
Net cash provided by (used in) financing activities	72.8			(26.7		)	17.9			(17.9		)	46.1
Net change in cash	—			62.2			—			—			62.2
Cash at beginning of period	—			4.6			—			—			4.6
Cash at end of period	$	—		$	66.8		$	—		$	—		$	66.8

28

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Cash Flows
Three Months Ended March 31, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(39.6	)	$	107.3		$	—		$	—		$	67.7
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(12.1		)	—			—			(12.1		)
Purchases of property, plant and equipment	(0.9		)	(76.4		)	—			—			(77.3		)
Investment in unconsolidated affiliates	—			—			(19.8		)	—			(19.8		)
Capital contribution to consolidated affiliates	(6.5		)	—			—			6.5			—
Net cash provided by (used in) investing activities	(7.4		)	(88.5		)	(19.8		)	6.5			(109.2		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	306.0			—			—			—			306.0
Principal payments on long-term debt	(188.8		)	—			—			—			(188.8		)
Payments on capital leases	(0.3		)	(0.8		)	—			—			(1.1		)
Distributions paid	(84.6		)	—			—			—			(84.6		)
Contributions from parent	—			—			6.5			(6.5		)	—
Net proceeds from issuance of preferred equity of subsidiary	—			—			12.3			—			12.3
Change in intercompany balances	15.4			(15.4		)	—			—			—
Net cash provided by (used in) financing activities	47.7			(16.2		)	18.8			(6.5		)	43.8
Net change in cash	0.7			2.6			(1.0		)	—			2.3
Cash at beginning of period	0.1			1.6			1.0			—			2.7
Cash at end of period	$	0.8		$	4.2		$	—		$	—		$	5.0

29

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 2014 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:

• 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;

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

• governmental legislation and regulations;

• 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 2014 Annual Report on Form 10-K.

Our Company

We are a growth-oriented MLP that manages, owns and operates 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 facilities and fleet, NGL storage facility and salt production business. Below is a discussion of events that highlight our core business and financing activities.

30

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. We believe that our strategy of focusing on liquids-rich plays without abandoning prolific lean gas plays positions us well to (i) generate greater returns in the near term while natural gas prices remain depressed, (ii) capture greater upside economics when natural gas prices normalize, and (iii) in general, manage through commodity price cycles and production changes associated therewith.

• Powder River Basin (PRB) Niobrara. In January 2015, the construction of the 120 MMcf/d Bucking Horse processing plant was completed and the plant was placed into service. The completion of the Bucking Horse processing plant adds a substantial component to our portfolio of fee-based contracts and provides additional opportunities for long-term infrastructure development as production from the emerging PRB Niobrara continues to increase. In addition, the gathering system continues to expand with the most recent compression facility placed into service in January 2015. We are actively working with area producers to develop additional gathering and processing facilities beyond our Jackalope acreage in the region.

• Barnett Shale. Our gathering and processing systems are integral to Quicksilver Resources, Inc.'s (Quicksilver) Barnett Shale operations, as a substantial amount of Quicksilver's revenues are derived from the sale of natural gas and natural gas liquids produced from acreage dedicated to us. In March 2015, Quicksilver filed for protection under Chapter 11 of the U.S. Bankruptcy Code and shut in production of certain non-economic wells in conjunction with that filing. We continue to provide services to Quicksilver and we are closely monitoring its restructuring process, which could have a significant impact on our G&P segment's results.

Storage and Transportation

Our storage and transportation segment consists of our interconnected natural gas storage and transportation assets. We have four natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake) and three transportation pipelines (North-South Facilities, MARC I and the East Pipeline) located in the Northeast in or near the Marcellus Shale.

• North/South Pipeline (NS-1 Expansion). The first phase of our NS-1 Expansion was placed into service in December 2014, and the second phase was completed in the first quarter of 2015. This expansion provides approximately 200 MMcf/d of incremental delivery capacity into Millennium Pipeline on the north end of the system. We are actively pursuing incremental projects on the North/South Pipeline that would provide additional delivery capability and increased market access, including providing access to new sources of supply.

• MARC I. In the first quarter of 2015, we secured an anchor shipper and successfully completed an open season for an expansion of the MARC I Pipeline.  This expansion will provide for the installation of the new Wilmot supply interconnect with Appalachian Midstream Services and approximately 250 MMcf/d of increased capacity at the interconnect between MARC I and Transcontinental Gas Pipe Line Corporation (Transco). The expansion project is expected to be completed in the fourth quarter of 2015.

• MARC II. We continue to make progress on the MARC II Pipeline Project, which is currently designed to provide up to 1.0 Bcf/d of delivery alternatives for northeast customers accessing the proposed Penn East and Transco pipelines. Market feedback on the project remain positive. The MARC II Pipeline project could be placed in service as early as the fourth quarter of 2017 pending sufficient shipper commitments.

NGL and Crude Services

Our NGL and crude services segment consists of our crude oil gathering systems and rail terminals, 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 to provide gathering, storage and terminal services to our

anchor customers, and we utilize our crude oil and NGL assets on a portfolio basis to provide integrated supply and logistics solutions to producers, refiners and other customers.

• Bakken Shale - Arrow. We are continuing to build out the Arrow gathering system to its total design capacity of 125,000 Bbls/d of crude oil gathering, 100 MMcf/d of gas gathering, and 40,000 Bbls/d of produced water gathering.

31

We are constructing a 200,000 barrel crude oil storage tank at the Arrow central delivery point, which we expect to complete and place into service by the end of second quarter of 2015. The new storage tank is commercially supported by a take-or-pay storage agreement for 50% of the tank's working storage capacity.

On May 5, 2015, CEQP, CMLP and certain of its affiliates entered into a definitive agreement under which CMLP has agreed to merge with a wholly-owned subsidiary of CEQP, with CMLP surviving as a wholly-owned subsidiary of CEQP.  As part of the merger consideration, CMLP’s unitholders will become unitholders of CEQP in a tax free exchange, with CMLP’s common unitholders receiving 2.75 common units of CEQP for each common unit of CMLP held upon completion of the merger.  CMLP’s IDRs will also be eliminated upon completion of the merger and CMLP’s common units will cease to be listed on the NYSE.  CMLP expects to complete the merger in the third quarter of 2015, subject to the approval of Crestwood Midstream's unitholders and customary closing conditions.

Outlook and Trends

Our long-term distribution growth is influenced by our ability to execute our growth strategy, including maximizing throughput on our assets and the successful completion of both organic expansion projects and strategic acquisitions. With a goal to increase cash available for distributions from our assets, our operating strategies include the expansion of customer services, from which we can generate higher revenues, and the prudent control of operating and administrative costs, resulting in increased operating margins and cash flows from operations. The continued integration of our gathering, processing, marketing, storage and transportation assets and services along the midstream value chain will be instrumental to our ability to produce commercial synergies which drive higher revenues. Our ability to monitor and manage the operating costs associated with increased customer services and volume throughput will be an important driver of increased operating margins and higher cash flows.

Despite the sharp decline in commodity prices since mid-2014, we believe that we are well positioned to deliver consistently improving financial results in 2015 due to a number of factors. First, we completed a significant number of capital expansion projects in 2014 that we believe will provide period to period volume increases in 2015. Second, many of our assets are located on long term, core acreage dedications in highly economic shale plays (driven by a combination of favorable netback pricing, low drilling, completion and operating costs, and high estimated ultimate reserves and initial production rates in each of those shale plays) which allows many of our producers to continue to develop their properties even at current prices. Third, a substantial portion of the midstream services we provide to customers in the high-growth shale plays such as the Marcellus, Bakken and PRB Niobrara are based on fixed fee, take-or-pay or cost-of-service agreements that ensure a minimum level of cash flow regardless of actual commodity prices or volumetric throughput.

Another critical factor to improvement in our financial results in 2015 is reduced operating and administrative costs. During the three months ended March 31, 2015, our expenses related to operations, maintenance and general and administrative matters totaled $59 million, compared to $52 million during the same period in 2014. The increase was primarily due to the expansion of our operating platform as a result of approximately $400 million in capital expansion projects and bolt-on acquisitions completed in 2014. To align our operating costs further with current market conditions, in the first quarter of 2015, we implemented a company-wide cost-savings initiative to achieve annual run-rate cost savings of $25 million to $30 million by streamlining the organization to increase efficiency and improve effectiveness. Approximately $15 million of the overall cost savings is expected to impact our 2015 results through operational and support function consolidations and a reduction in work force. We incurred approximately $4 million of upfront costs during the first quarter of 2015 related to this cost savings initiative.

Historically, during periods of low commodity prices and deferred producer activity, the midstream industry typically experiences a slow-down in organic project growth opportunities and an increase in strategic acquisition opportunities. Our ability to compete for acquisitions and large scale, standalone organic development projects is largely impacted by our weighted average cost of capital (WACC) compared to our competitors. Our WACC is a function of our cost of debt and cost of equity, which includes the current yield on our common units and the embedded capital costs of our IDRs. Since mid-2014, our cost of equity, including the net effect of our existing IDR burden, has increasingly limited our ability to compete effectively for potential acquisitions and growth projects.  We are exploring alternatives designed to lower our capital costs and position us to better compete for acquisitions and development projects necessary to execute our growth strategy.

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Regulatory Matters

Many activities within the energy midstream sector have experienced increased regulatory oversight over the past few years, and we expect the trend of regulatory oversight to continue for the foreseeable future. We anticipate greater regulatory oversight related to activities that have attracted significant negative attention in the public domain (e.g., the transportation of crude oil by rail). We also anticipate greater regulatory oversight in states like North Dakota and tribal sovereignties like the Mandan, Hidatsa & Arikara Nation (MHA Nation), where regulation in certain areas is now starting to align with the tremendous production growth experienced in those jurisdictions in a short period of time.

We are developing an NGL storage facility in Schuyler County, New York. We have requested from the New York State Department of Environmental Conservation (NYSDEC) the permits necessary to store up to 2.1 million barrels of propane and butane in underground caverns created by US Salt’s solution-mining process. The NYSDEC staff issued a draft underground storage permit in November 2014. An issues conference was held in February 2015 to determine whether any significant and substantive issues concerning our project require further adjudication. Initial post-conference briefs were submitted to the presiding Administrative Law Judge (ALJ) in April 2015, and the ALJ is expected to issue an opinion late in the second quarter of 2015.  The NYSDEC staff has defended the draft permit and argued there are no significant and substantive issues requiring an adjudicatory hearing.  We continue to believe the NYSDEC will issue the permit required for us to construct, own and operate the proposed storage facility, but we can provide no assurances if and when the permit will be issued. We have recorded approximately $38 million of costs in property, plant and equipment and $66 million of goodwill related to this NGL storage facility as of March 31, 2015.

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 unit-based compensation charges, gains and impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to potential

and completed acquisitions, certain environmental remediation costs, certain costs related to our 2015 cost savings initiatives, 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.

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Results of Operations

The following table summarizes our results of operations for the three months ended March 31, 2015 and 2014 (in millions):

	Three Months Ended
	March 31,
	2015			2014
Revenues	$	455.1		$	537.0
Costs of product/services sold	286.6			398.1
Operations and maintenance expense	35.1			28.0
General and administrative expense	24.2			24.1
Depreciation, amortization and accretion	59.9			50.8
Gain (loss) on long-lived assets, net	(0.8		)	0.5
Loss on contingent consideration	—			(2.1		)
Operating income	48.5			34.4
Earnings (loss) from unconsolidated affiliates, net	3.4			(0.1		)
Interest and debt expense, net	(29.9		)	(28.1		)
Provision for income taxes	(0.3		)	(0.7		)
Net income	$	21.7		$	5.5
Add:
Interest and debt expense, net	29.9			28.1
Provision for income taxes	0.3			0.7
Depreciation, amortization and accretion	59.9			50.8
EBITDA	$	111.8		$	85.1
Unit-based compensation charges	5.2			4.6
(Gain) loss on long-lived assets, net	0.8			(0.5		)
Loss on contingent consideration	—			2.1
(Earnings) loss from unconsolidated affiliates, net	(3.4		)	0.1
Adjusted EBITDA from unconsolidated affiliates, net	6.5			1.7
Significant transaction and environmental related costs and other items	3.8			5.8
Adjusted EBITDA	$	124.7		$	98.9

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	Three Months Ended
	March 31,
	2015			2014
EBITDA:
Net cash provided by operating activities	$	77.0		$	67.7
Net changes in operating assets and liabilities	9.2			(2.6		)
Amortization of debt-related deferred costs and premiums	(1.9		)	(1.8		)
Interest and debt expense, net	29.9			28.1
Unit-based compensation charges	(5.2		)	(4.6		)
Gain (loss) on long-lived assets, net	(0.8		)	0.5
Loss on contingent consideration	—			(2.1		)
Earnings (loss) from unconsolidated affiliates, net	3.4			(0.1		)
Deferred income taxes	(0.1		)	(0.5		)
Provision for income taxes	0.3			0.7
Other non-cash income	—			(0.2		)
EBITDA	$	111.8		$	85.1
Unit-based compensation charges	5.2			4.6
(Gain) loss on long-lived assets, net	0.8			(0.5		)
Loss on contingent consideration	—			2.1
(Earnings) loss from unconsolidated affiliates, net	(3.4		)	0.1
Adjusted EBITDA from unconsolidated affiliates, net	6.5			1.7
Significant transaction and environmental related costs and other items	3.8			5.8
Adjusted EBITDA	$	124.7		$	98.9

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

	Three Months Ended								Three Months Ended
	March 31, 2015								March 31, 2014
	Gathering and Processing			Storage and Transportation			NGL and Crude Services		Gathering and Processing			Storage and Transportation		NGL and Crude Services
Revenues	$	78.5		$	45.7		$	330.9	$	79.5		$	44.3	$	413.2
Costs of product/services sold	12.7			3.3			270.6		18.7			3.2		376.2
Operations and maintenance expense	14.9			4.3			15.9		13.4			4.3		10.3
Gain (loss) on long-lived assets	(0.3		)	(0.5		)	—		0.5			—		—
Loss on contingent consideration	—			—			—		(2.1		)	—		—
Earnings (loss) from unconsolidated affiliates	2.5			0.9			—		0.3			—		(0.4		)
EBITDA	$	53.1		$	38.5		$	44.4	$	46.1		$	36.8	$	26.3

Segment Results

Below is a discussion of the factors that impacted EBITDA by segment for the three months endedMarch 31, 2015 compared to the same period in 2014.

Gathering and Processing

EBITDA for our G&P segment increased by approximately $7.0 million for the three months endedMarch 31, 2015 compared to the same period in 2014, primarily due to lower costs of product/services sold of approximately $6.0 million, partially offset by lower revenues and higher operations and maintenance expense. The decrease in our G&P segment's costs of product/services sold was primarily driven by lower NGL and natural gas prices experienced under our percent-of-proceeds contracts related to our assets located in Granite Wash.

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Our G&P segment’s revenues decreased by approximately $1.0 million during the three months ended March 31, 2015 compared to the same period in 2014, although we experienced an increase in our gathering and compression volumes. The decrease in our G&P revenues was primarily driven by lower NGL and natural gas prices related to our assets located in Granite Wash as discussed above, partially offset by higher gathering and compression revenues from Antero, our primary customer in the Marcellus Shale. We gathered approximately 1.2 Bcf/d of natural gas on our G&P systems during the three months ended March 31, 2015 compared to 1.1 Bcf/d during the same period in 2014. Our compression volumes increased from 0.4 Bcf/d for the three months ended March 31, 2014 to 0.7 Bcf/d during the same period in 2015. The increases in our G&P gathering and compression volumes were primarily due to several new compressor stations placed in service during 2014 in the Marcellus Shale and new wells connected to our systems during 2014.

Partially offsetting the decrease in our costs of product/services sold were higher operations and maintenance expense of approximately $1.5 million during the three months ended March 31, 2015 compared to the same period in 2014 due to compressor stations in the Marcellus Shale that were placed in service during the last half of 2014.

Our G&P segment's EBITDA was impacted by a $2.1 million loss on contingent consideration recorded in the first quarter of 2014. The loss on contingent consideration was an accrual that reflected the fair value of an earn-out premium associated with the original acquisition of our Marcellus G&P assets from Antero Resources Appalachian Corporation (Antero) in 2012. The earn-out provision allowed Antero to receive an additional $40.0 million payment when gathering volumes exceeded a certain threshold as defined in the acquisition agreements, which was settled in February 2015.

In addition, we recorded a $2.2 million increase in equity earnings from Jackalope Gas Gathering Services, L.L.C. (Jackalope) for the three months endedMarch 31, 2015 compared to the same period in 2014. The increase was primarily attributable to the Bucking Horse processing plant which was placed in service on the Jackalope system in January 2015.

In March 2015, one of our customers in the Barnett Shale, Quicksilver, began shutting in certain of its wells in conjunction with Quicksilver's filing for protection under Chapter 11 of the U.S. Bankruptcy Code. The shut in wells decreased our revenues generated by our Barnett Shale operations by approximately $0.7 million during the month of March, and we continue to evaluate the impact that these and potential future shut-ins may have on our G&P operations in the Barnett Shale.

Storage and Transportation

Our storage and transportation segment's EBITDA increased by approximately $1.7 million during the three months ended March 31, 2015 compared to the same period in 2014. The increase in our storage and transportation segment's EBITDA was primarily due to higher revenues from additional firm storage and transportation services resulting from organic growth projects placed in service during 2014 and 2015, primarily the NS-1 Expansion project, which increased volumes delivered into Millennium Pipeline. During the three months ended March 31, 2015, total firm throughput from our Northeast storage and transportation services averaged approximately 1.6 Bcf/d compared to 1.4 Bcf/d during the same period in 2014.

Our storage and transportation segment's costs of product/services sold and operations and maintenance expenses were relatively flat during the three months ended March 31, 2015 compared to the same period in 2014.

In December 2014, we formed the Tres Palacios Holdings LLC (Tres Holdings) joint venture with an affiliate of Brookfield Infrastructure Group (Brookfield) to acquire 100% of the membership interest in Tres Palacios Gas Storage LLC (Tres Palacios). For the three months ended March 31, 2015, we recorded earnings from our unconsolidated affiliate of approximately $0.9 million, which primarily related to our proportionate share of Tres Holdings’ net income. For a further discussion of our investment in Tres Holdings, see Item 1, Financial Statements, Note 5.

NGL and Crude Services

Our NGL and crude services segment's EBITDA increased by approximately $18.1 million during the three months ended March 31, 2015 compared to the same period in 2014, primarily due to lower costs of products/services sold, partially offset by lower revenues.

Our NGL and crude services segment's costs of product/services sold decreased by approximately $105.6 million primarily due to the net decline in costs of product/services sold related to our Arrow and crude marketing operations. Average crude oil prices on crude oil sales decreased by over 50% during the three months ended March 31, 2015 compared to the same period in 2014. Partially offsetting this net decline in costs of product/services sold were higher costs of products/services sold related to our crude oil transportation operations which we acquired in 2014.

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Our NGL and crude services segment's revenues decreased by $82.3 million during the three months ended March 31, 2015 compared to the same period in 2014, due primarily to a $96.4 million net decrease in the revenues related to our Arrow and crude marketing operations resulting from lower prices on crude oil sales. Our revenues did not decrease as much as our costs of product/services sold because crude oil, natural gas and water volumes increased by 50%, 121% and 102% during the three months ended March 31, 2015 compared to the same period in 2014, as new wells were connected to our system. Partially offsetting this decline in revenues was a $6.8 million increase in revenues resulting from higher volumes on our COLT Hub as a result of our expansion of the facility (including placing our release and departure tracks in service in December 2014) and increased utilization of non-firm capacity on the system. During the three months ended March 31, 2015 and 2014, we loaded approximately 123,000 MBbls/d and 98,000 MBbls/d of crude on rail cars entering the facility. We also experienced an increase in revenues of $6.7 million during the three months ended March 31, 2015 related to our crude oil transportation operations acquired in 2014.

During the three months ended March 31, 2015, we experienced higher operations and maintenance expense primarily due to the acquisition of our crude oil transportation fleet in 2014.

For the three months ended March 31, 2015, and 2014, we recorded a loss from our unconsolidated affiliate, PRBIC, of less than $0.1 million and approximately $0.4 million, which primarily related to our proportionate share of PRBIC’s net loss.

Other Results

Our consolidated EBITDA for the three months endedMarch 31, 2015 was $111.8 million, an increase of $26.7 million compared to the same period in 2014. Our consolidated Adjusted EBITDA for the three months endedMarch 31, 2015 was $124.7 million, an increase of $25.8 million compared to the same period in 2014. The increase in our EBITDA and Adjusted EBITDA was primarily driven by our segment results described above. Partially offsetting those results were the general and administrative expenses of our Corporate operations which were relatively flat during the three months ended March 31, 2015 compared to the same period in 2014. During the first quarter of 2015, we incurred $3.6 million of costs related to our 2015 cost savings initiatives, compared to $5.8 million of costs during the first quarter of 2014, primarily related to the Arrow acquisition and the Crestwood merger.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense - During the three months endedMarch 31, 2015, our depreciation, amortization and accretion expense increased compared to the same period in 2014, primarily due to the acquisition of our crude oil transportation assets during 2014 and the expansion of our gathering and processing assets in the Marcellus Shale.

Interest and Debt Expense - Interest and debt expense increased by approximately $1.8 million during the three months endedMarch 31, 2015 compared to the same period in 2014. The following table provides a summary of interest and debt expense (in millions):

	Three Months Ended
	March 31,
	2015		2014
Credit facilities	$	4.3	$	4.1
Senior notes	24.4		23.5
Other debt-related costs	1.9		1.8
Gross interest and debt expense	30.6		29.4
Less: capitalized interest	0.7		1.3
Interest and debt expense, net	$	29.9	$	28.1

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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, our Credit Facility, debt issuances, and sales of our common and Class A preferred units.  Our operating subsidiaries use cash from their respective operations to fund their operating activities and maintenance capital expenditures.  We believe our current liquidity sources and operating cash flows will be sufficient to fund our future operating and capital requirements.

• Credit Facility. As of March 31, 2015, we had $429.1 million of available capacity under the Credit Facility considering the most restrictive debt covenants in our credit agreement. On April 8, 2015, we utilized approximately $315 million of our Credit Facility to redeem all of our outstanding 2019 Senior Notes. See Item 1, Financial Statements, Note 6 for a more detailed description of our Credit Facility.

• Preferred Units. During the three months ended March 31, 2015, we did not sell any Preferred Units to the Class A Purchasers. We expect to issue $60.0 million of Preferred Units to the Class A Purchasers before September 30, 2015, and to use the net proceeds from such issuances to fund expansion and development projects, to reduce borrowings under our Credit Facility, and for other general partnership purposes. See Item 1, Financial Statements, Note 8 for a more detailed description of the Preferred Units.

• Equity Distribution Agreement. We entered into an equity distribution program with certain financial institutions (each, a Manager) under which we are allowed to 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. We will pay the Managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under this at-the-market program. We did not issue any common units under this equity distribution program as of March 31, 2015 and through the date of this filing.

• Senior Notes. In March 2015, we issued $700 million of 6.25% unsecured Senior Notes due 2023 in a private offering. The net proceeds from this offering of approximately $688.9 million were used to pay down borrowings under our Credit Facility and for general partnership purposes. On April 8, 2015, we utilized approximately $315 million of our Credit Facility to redeem all of our outstanding 2019 Senior Notes as discussed above.

As of March 31, 2015, we were in compliance with all our debt covenants related to our Credit Facility and our Senior Notes. See Item 1, Financial Statements, Note 6 for a more detailed description of our Credit Facility and Senior Notes.

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

	Three Months Ended
	March 31,
	2015			2014
Net cash provided by operating activities	$	77.0		$	67.7
Net cash used in investing activities	(60.9		)	(109.2		)
Net cash provided by financing activities	46.1			43.8

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Operating Activities

Our operating cash flows increased approximately $9.3 million during the three months ended March 31, 2015 compared to the same period in 2014, primarily due to lower costs of product/services sold of approximately $111.5 million primarily due to lower prices in our G&P and NGL and crude services operations described above, partially offset by (i) lower operating revenues of $81.9 million primarily from our Arrow operations described above; (ii) higher operations and maintenance expenses of approximately $7.1 million primarily due to the acquisition of our crude oil transportation assets in mid-2014; and (iii) a $11.8 million net change in working capital resulting primarily from the payment of the Antero contingent consideration offset by reimbursements of property, plant and equipment during the first quarter of 2015.

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.

The following table summarizes our capital expenditures for the three months ended March 31, 2015 (in millions). 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 flows and earnings.

Growth capital	$	33.6
Maintenance capital	2.7
Other (1)	7.0
Purchases of property, plant and equipment	43.3
Reimbursements of property, plant and equipment	22.9
Net purchases of property, plant and equipment	$	20.4

(1) Represents gross purchases of property, plant and equipment that are reimbursable by third parties.

In addition to our capital expenditures discussed above, our cash flows from investing activities were also impacted by the following significant items during the three months ended March 31, 2015 and 2014:

Acquisitions. During the three months ended March 31, 2014, we acquired substantially all of the operating assets of Red Rock for approximately $12.1 million. For a further discussion of this acquisition, see Item 1, Financial Statements, Note 3.

Investments in Unconsolidated Affiliates. During the three months ended March 31, 2015 and 2014, we made capital contributions of approximately $17.9 million and $19.8 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.

Financing Activities

Significant items impacting our financing activities during the three months endedMarch 31, 2015 and 2014, included the following:

Equity Transactions

• $12.3 million in proceeds from the issuance of non-controlling interests during the three months endedMarch 31, 2014

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Debt Transactions

• $688.9 million net proceeds from the issuance of the 2023 Senior Notes during the three months endedMarch 31, 2015; and

• $672.6 million increase in net repayments under our Credit Facility during the three months endedMarch 31, 2015 compared to the same period in 2014

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Our interest rate risk and commodity price, market and credit risks are discussed in our 2014 Annual Report on Form 10-K and there have been no material changes in those exposures from December 31, 2014 to March 31, 2015 other than as follows.

Credit Risk

On March 17, 2015, Quicksilver, a significant customer in our gathering and processing operations in the Barnett Shale, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Although Quicksilver is current on all amounts we invoiced them through April 2015, we are closely monitoring our exposure to Quicksilver to ensure they continue to promptly pay invoices, including those billed to them in May 2015.

Item 4. Controls and Procedures

Disclosure Controls and Procedures

As of March 31, 2015, 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 March 31, 2015.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the three months endedMarch 31, 2015 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

Our Risk Factors are consistent with those disclosed in Part I, Item 1A. Risk Factors of our 2014 Annual Report on Form 10-K. Below is an update to our Risk Factors.

Declines in natural gas, NGL or crude prices could adversely affect our business.

Low commodity prices impact natural gas and oil exploration and production activity levels and can result in a decline in the production of hydrocarbons over time, resulting in reduced throughput on our systems and terminals. Declines in natural gas, NGL or crude oil prices can also affect our customers’ ability to continue their operations at existing levels or at all. For example, many of our customers have indicated a lower level of development activity in 2015 based on an expectation that the recent decline in commodity prices will continue for an extended period of time. As a result of these customer expectations, we have taken steps to immediately streamline our organization, increase efficiencies and improve effectiveness. We forecast $25 million to $30 million of annual cost savings, approximately $15 million of which we expect to realize in 2015 through headcount reductions and the elimination or consolidation of support functions. Commodity prices are entirely outside of our control, and we cannot provide any assurances that we will be able to achieve any cost saving objectives prompted by lower commodity prices.

Any sustained period of low commodity prices, or our failure to achieve cost-control or restructuring objectives designed to help us perform better during sustained periods of low commodity prices, could have a material adverse effect on our business, results of operations, and financial condition.

Our operations are subject to compliance with environmental and operational safety laws and regulations that may expose us to significant costs and liabilities. Our operations are subject to stringent federal, regional, state and local laws and regulations governing health and safety aspects of our operations, the discharge of materials into the environment or otherwise relating to environmental protection. Such environmental laws and regulations impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable legal requirements, the application of specific health and safety criteria addressing worker protections and the imposition of restrictions on the generation, handling, treatment, storage, disposal and transportation of materials and wastes. Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and the issuance of injunctions restricting or prohibiting some or all of our activities.

For example, our Arrow water gathering system experienced three releases during 2014 on the Fort Berthold Indian Reservation in North Dakota. In each instance, we notified the applicable authorities, contained and cleaned up the releases, and placed the impacted segments of these water lines back into service. Although we will continue our remediation efforts to ensure the impacted lands are restored to their prior state, we may be subject to fines and penalties. We received data requests from the Environmental Protection Agency (EPA) related to the releases in October 2014, responded to the EPA’s original request for information in January 2015, and are working to respond to supplemental requests received from the EPA in the first quarter of 2015. On April 16, 2015, the EPA issued a Notice of Potential Violation relating to the water releases, and we anticipate responding to the Notice of Potential Violation in May 2015. On March 3, 2015, we received a grand jury subpoena from the United States Attorney’s Office in Bismarck, North Dakota, seeking documents and information relating to the largest of the three releases, and we are in the process of providing the requested information. We cannot predict what the outcome of these investigations will be.

Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where materials or wastes have been disposed or otherwise released. In the course of our operations, generated materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for recycling or disposal.

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It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us as well as the industry in general or otherwise adversely affect demand for our services and salt products. For example, in January 2015, the Obama Administration announced plans for the EPA to issue final standards in 2016 that would reduce methane emissions from new and modified oil and natural gas production and natural gas processing and transmission facilities by up to 45 percent from 2012 levels by 2025, and, in December 2014, the EPA published a proposed rulemaking that it expects to finalize by October 1, 2015 that would seek to reduce the National Ambient Air Quality Standard for ozone to between 65 and 70 parts per billion for both the 8-hour primary and secondary standards.

We depend on a limited number of customers for a substantial portion of our revenues.

We generate a substantial portion of our gathering revenues from a limited number of oil and gas producers. Within our G&P segment, the top two producers (Antero in the Marcellus Shale and Quicksilver in the Barnett Shale) each accounted for approximately 4%, respectively, of our total consolidated revenues in 2014. Within our NGL and crude services segment, five producers primarily on our Arrow system in the Bakken Shale accounted for approximately 49% of our total consolidated revenues in 2014. Given the current commodity price environment and its anticipated impact on shale production, we expect our gathering revenues to remain leveraged to a limited number of producers in 2015 as we continue to build out our gathering systems, particularly in the Marcellus, Bakken and PRB Niobrara. Because we depend on a limited number of customers, a loss of a significant customer or failure to perform by a significant customer could cause a significant decline in our revenues. In particular, on March 17, 2015, Quicksilver filed for protection under Chapter 11 of the U.S. Bankruptcy Code and shut in production of certain non-economic wells in conjunction with that filing.

Although we have obtained acreage dedications from many producer customers, most of our gathering contracts do not contain minimum volume requirements that would protect us against volumetric risks associated with lower-than-forecast volumes flowing through our systems. Our producer customers do not have contractual obligations to develop their properties in the areas covered by our acreage dedications, and they may determine that it is more attractive to direct their capital spending and resources to other areas. A decrease in producer capital spending and reserves in the areas covered by our acreage dedications with our significant gathering customers could result in reduced volumes serviced by us and a material decline in our revenues and cash flows.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

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Item 6. Exhibits

Exhibit Number	Description
3.1	Certificate of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.4 to Inergy Midstream, L.P.'s Form S-1/A filed on November 21, 2011)
3.1A	Amendment to the Certificate of Limited Partnership of Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.2 to the Partnership’s Form 8-K filed on October 10, 2013)
3.3	First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P., dated December 21, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)
3.3A	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy Midstream, L.P.’s Form 8-K filed on October 1, 2013)
3.3B	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.1 to the Partnership’s Form 8-K filed on October 10, 2013)
3.3C	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP (incorporated herein by reference to Exhibit 3.1 to the Partnership's Form 8-K filed on June 19, 2014)
3.4	Certificate of Formation of NRGM GP, LLC (incorporated herein by reference to Exhibit 3.7 to Inergy Midstream, L.P.'s Form S-1/A filed on November 21, 2011)
3.4A	Certificate of Amendment of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.37 to the Partnership’s Form S-4 filed on October 28, 2013)
3.5	Amended and Restated Limited Liability Company Agreement of NRGM GP, LLC, dated December 21, 2011 (incorporated herein by reference to Exhibit 3.2 to Inergy Midstream, L.P.'s Form 8-K filed on December 22, 2011)
3.5A	Amendment No. 1 to the Amended and Restated Limited Liability Company Agreement of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.39 to the Partnership’s Form S-4 filed on October 28, 2013)
*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

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*

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.

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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:	May 7, 2015	By:	/s/ ROBERT T. HALPIN
			Robert T. Halpin
			Senior Vice President and Chief Financial Officer
			(Duly Authorized Officer and Principal Financial Officer)

45