Crestwood Equity Partners (CEQP+) 10-Q 2015 Q2 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the quarterly period ended June 30, 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 August 3, 2015, the registrant had 188,309,552 common units and 18,756,098 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	35
Item 3. Quantitative and Qualitative Disclosures About Market Risk	48
Item 4. Controls and Procedures	49
Part II – Other Information
Item 1. Legal Proceedings	50
Item 1A. Risk Factors	50
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	51
Item 3. Defaults Upon Senior Securities	51
Item 4. Mine Safety Disclosures	51
Item 5. Other Information	51
Item 6. Exhibits	52
Signature	53

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)
	June 30, 2015		December 31, 2014
	(unaudited)
Assets
Current assets:
Cash	$	0.2	$	4.6
Accounts receivable	227.4		241.8
Inventory	12.8		8.0
Prepaid expenses and other current assets	17.5		18.7
Total current assets	257.9		273.1
Property, plant and equipment (Note 4)	3,918.2		3,883.5
Less: accumulated depreciation and depletion	431.1		365.4
Property, plant and equipment, net	3,487.1		3,518.1
Intangible assets (Note 4)	1,012.4		1,013.2
Less: accumulated amortization	174.1		137.0
Intangible assets, net	838.3		876.2
Goodwill	1,592.4		1,632.6
Investment in unconsolidated affiliates (Note 5)	324.2		295.1
Other assets	1.3		1.4
Total assets	$	6,501.2	$	6,596.5
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	109.8	$	132.4
Accrued expenses and other liabilities (Note 4)	82.9		122.0
Current portion of long-term debt (Note 6)	6.0		0.7
Total current liabilities	198.7		255.1
Long-term debt, less current portion (Note 6)	2,159.5		2,012.8
Other long-term liabilities	30.9		31.2
Commitments and contingencies (Note 10)
Partners’ capital (Note 8):
Class A preferred units (18,756,098 and 17,917,870 units issued and outstanding at June 30, 2015 and December 31, 2014)	464.4		447.7
Partners’ capital (188,301,322 and 187,965,105 limited partner units issued and outstanding at June 30, 2015 and December 31, 2014)	3,468.5		3,678.0
Total Crestwood Midstream Partners LP partners’ capital	3,932.9		4,125.7
Interest of non-controlling partners in subsidiary	179.2		171.7
Total partners’ capital	4,112.1		4,297.4
Total liabilities and partners’ capital	$	6,501.2	$	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						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Revenues:
Gathering and processing	$	73.3		$	82.7		$	150.6		$	161.3
Storage and transportation	44.0			45.4			89.7			89.7
NGL and crude services	356.1			543.5			683.6			953.4
Related party (Note 11)	5.0			4.1			9.6			8.3
	478.4			675.7			933.5			1,212.7
Costs of product/services sold:
Gathering and processing	5.6			7.8			10.0			15.5
Storage and transportation	3.4			3.8			6.7			7.0
NGL and crude services	299.4			497.7			570.0			873.9
Related party (Note 11)	7.7			9.8			16.0			20.8
	316.1			519.1			602.7			917.2
Expenses:
Operations and maintenance	32.1			32.7			67.2			60.7
General and administrative	26.2			21.3			50.4			45.4
Depreciation, amortization and accretion	60.6			54.9			120.5			105.7
	118.9			108.9			238.1			211.8
Other operating income (expense):
Gain (loss) on long-lived assets, net	(0.6		)	1.1			(1.4		)	1.6
Goodwill impairment	(40.2		)	—			(40.2		)	—
Loss on contingent consideration	—			(6.5		)	—			(8.6		)
Operating income	2.6			42.3			51.1			76.7
Earnings (loss) from unconsolidated affiliates, net	5.0			(1.5		)	8.4			(1.6		)
Interest and debt expense, net	(32.6		)	(29.0		)	(62.5		)	(57.1		)
Loss on modification/extinguishment of debt	(17.1		)	—			(17.1		)	—
Income (loss) before income taxes	(42.1		)	11.8			(20.1		)	18.0
Provision for income taxes	0.1			0.1			0.4			0.8
Net income (loss)	(42.2		)	11.7			(20.5		)	17.2
Net income attributable to non-controlling partners	(5.7		)	(3.7		)	(11.3		)	(6.8		)
Net income (loss) attributable to Crestwood Midstream Partners LP	(47.9		)	8.0			(31.8		)	10.4
Net income attributable to Class A preferred units	(7.5		)	(1.1		)	(16.7		)	(1.1		)
Net income (loss) attributable to partners	$	(55.4	)	$	6.9		$	(48.5	)	$	9.3
General partner's interest in net income (loss)	$	7.5		$	7.5		$	15.0		$	15.0
Limited partners’ interest in net income (loss)	$	(62.9	)	$	(0.6	)	$	(63.5	)	$	(5.7	)
Net income (loss) per limited partner unit:
Basic	$	(0.33	)	$	—		$	(0.34	)	$	(0.03	)
Diluted	$	(0.33	)	$	—		$	(0.34	)	$	(0.03	)
Weighted-average limited partners’ units outstanding (in thousands):
Basic	188,292			187,998			188,291			187,920
Diluted	188,292			187,998			188,291			187,920

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	—		(20.9		)	—			(20.9		)
Distributions to limited partners	—		(148.6		)	—			(148.6		)
Distributions to Crestwood Niobrara Preferred Unitholders	—		—			(3.8		)	(3.8		)
Unit-based compensation charges	—		10.5			—			10.5
Taxes paid for unit-based compensation vesting	—		(2.1		)	—			(2.1		)
Other	—		0.1			—			0.1
Net income (loss)	16.7		(48.5		)	11.3			(20.5		)
Balance at June 30, 2015	$	464.4	$	3,468.5		$	179.2		$	4,112.1

See accompanying notes.

5

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) (unaudited)
	Six Months Ended
	June 30,
	2015			2014
Operating activities
Net income (loss)	$	(20.5	)	$	17.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion	120.5			105.7
Amortization of debt-related deferred costs and premiums	3.9			3.6
Unit-based compensation charges	10.5			9.8
Goodwill impairment	40.2			—
(Gain) loss on long-lived assets	1.4			(1.6		)
Loss on contingent consideration	—			8.6
Loss on modification/extinguishment of debt	17.1			—
(Earnings) loss from unconsolidated affiliates, net, adjusted for cash distributions	(2.1		)	1.6
Deferred income taxes	0.3			0.5
Other	0.2			—
Changes in operating assets and liabilities, net of effects from acquisitions	(23.6		)	(34.3		)
Net cash provided by operating activities	147.9			111.1
Investing activities
Acquisitions, net of cash acquired (Note 3)	—			(19.5		)
Purchases of property, plant and equipment	(77.7		)	(180.4		)
Investment in unconsolidated affiliates	(27.8		)	(48.6		)
Capital distributions from unconsolidated affiliates	1.0			—
Proceeds from sale of assets	1.7			—
Net cash used in investing activities	(102.8		)	(248.5		)
Financing activities
Proceeds from the issuance of long-term debt	1,865.1			860.6
Principal payments on long-term debt	(1,712.5		)	(863.2		)
Payments on capital leases	(1.2		)	(1.9		)
Payments for debt-related deferred costs	(11.7		)	—
Financing fees paid for early debt redemption	(13.6		)	—
Distributions to limited partners	(148.6		)	(148.3		)
Distributions to general partner	(20.9		)	(20.9		)
Distributions paid to non-controlling partners	(3.8		)	—
Net proceeds from issuance of preferred equity of subsidiary	—			33.6
Net proceeds from the issuance of Class A preferred units	—			293.7
Taxes paid for unit-based compensation vesting	(2.1		)	(1.5		)
Other	(0.2		)	(0.1		)
Net cash provided by (used in) financing activities	(49.5		)	152.0
Net change in cash	(4.4		)	14.6
Cash at beginning of period	4.6			2.7
Cash at end of period	$	0.2		$	17.3
Supplemental schedule of non-cash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(11.3	)	$	14.7

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

Crestwood Equity Partners LP (CEQP), a publicly traded Delaware limited partnership, 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 June 30, 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 June 30, 2015. Crestwood Holdings is substantially owned and controlled by First Reserve Management, L.P. (First Reserve).

On May 5, 2015, CEQP, the Company and certain of its affiliates entered into a definitive agreement under which we have agreed to merge with a wholly-owned subsidiary of CEQP, with the Company surviving as a wholly-owned subsidiary of CEQP (the Simplification Merger).  As part of the merger consideration, our common unitholders will become unitholders of CEQP in a tax free exchange, with our common unitholders receiving 2.75 common units of CEQP for each common unit of the Company held upon completion of the merger.  Upon completion of the Simplification Merger, our IDRs will be eliminated and our common units will cease to be listed on the New York Stock Exchange (NYSE).  We expect to complete the Simplification Merger in the third quarter of 2015, subject to the approval by our unitholders and the satisfaction of customary closing conditions. For additional information about the Simplification Merger, see Note 14.

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.

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 June 30, 2015, and for the three and six months ended June 30, 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 $15.7 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 six months ended June 30, 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 and related notes 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. Below is an update of our estimates related to goodwill.

Goodwill

Our goodwill represents the excess of the amount we paid for a business over the fair value of the net identifiable assets acquired. We evaluate goodwill for impairment annually on December 31, and whenever events indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount. This evaluation requires us to compare the fair value of each of our reporting units to its carrying value (including goodwill). If the fair value exceeds the carrying amount, goodwill of the reporting unit is not considered impaired.

We estimate the fair value of our reporting units based on a number of factors, including discount rates, projected cash flows, enterprise value and the potential value we would receive if we sold the reporting unit. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our reporting units (which includes assumptions, among others, about estimating future operating margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our customers, such as their future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. If the growth assumptions embodied in the projections prove inaccurate, we could incur a future impairment charge.

Due to the significant, sustained decrease in the market price of our common units from January 1, 2015 to June 30, 2015, we evaluated our reporting units and determined it was more likely than not that the goodwill associated with our Fayetteville (G&P segment) and our Watkins Glen (NGL and Crude Services segment) reporting units was impaired as of June 30, 2015.  As a result of further analysis of the fair value of goodwill at these reporting units, we recorded goodwill impairments of $8.3 million and $31.9 million related to our Fayetteville and Watkins Glen reporting units, respectively, during the three ended June 30, 2015. The impairment of our Fayetteville goodwill primarily resulted from increasing the discount rate utilized in determining the fair value of the reporting unit from 9% to 10%, considering the continued decrease in commodity prices and its impact on the midstream industry and our customers in the Fayetteville Shale.  The impairment of our Watkins Glen goodwill primarily resulted from increasing the discount rate utilized in determining the fair value of the reporting unit from 10.5% to 13.3% and continued delays and uncertainties in the permitting of our proposed NGL storage facility.  We have

8

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

approximately $64.2 million and $34.3 million of goodwill remaining on the balance sheet as of June 30, 2015 related to our Fayetteville and Watkins Glen reporting units, respectively, which represents the fair value of the goodwill related to those reporting units at June 30, 2015, which is a Level 3 fair value measurement. We continue to monitor these goodwill amounts and the $1,493.9 million of goodwill associated with our other reporting units as of June 30, 2015, and continued increases in discount rates and/or declines in the projected future operating performance of our reporting units or sustained decreases in the market price of our common units could result in future goodwill impairments.

New Accounting Pronouncements Issued But Not Yet Adopted

As of June 30, 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, 2018 and are currently evaluating the impact that this standard will have on our consolidated financial statements.

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.

Note 3 – Acquisitions

Crude Transportation Acquisitions (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.

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

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

9

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 4 – Certain Balance Sheet Information

Property, Plant and Equipment

Property, plant and equipment consisted of the following at June 30, 2015 and December 31, 2014 (in millions):

	June 30, 2015		December 31, 2014
Gathering systems and pipelines	1,282.8		1,276.6
Facilities and equipment	1,491.0		1,468.8
Buildings, land, rights-of-way, storage contracts and easements	810.1		806.4
Vehicles	13.6		13.6
Construction in process	156.0		153.7
Base gas	37.5		37.5
Salt deposits	120.5		120.5
Office furniture and fixtures	6.7		6.4
	3,918.2		3,883.5
Less: accumulated depreciation and depletion	431.1		365.4
Total property, plant and equipment, net	$	3,487.1	$	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 $2.3 million and $2.8 million included in property, plant and equipment, net at June 30, 2015 and December 31, 2014.

Intangible Assets

Intangible assets consisted of the following at June 30, 2015 and December 31, 2014 (in millions):

	June 30, 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	9.6		9.7
Deferred financing costs	57.7		54.3
	1,012.4		1,013.2
Less: accumulated amortization	174.1		137.0
Total intangible assets, net	$	838.3	$	876.2

10

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at June 30, 2015 and December 31, 2014 (in millions):

	June 30, 2015		December 31, 2014
Accrued expenses	$	20.5	$	23.7
Accrued property taxes	6.2		2.1
Accrued product purchases payable	1.0		0.7
Tax payable	—		0.4
Interest payable	26.8		22.0
Accrued additions to property, plant and equipment	11.9		20.0
Commitments and contingent liabilities (Note 10)	—		40.0
Capital leases	0.9		1.3
Deferred revenue	15.6		11.6
Other	—		0.2
Total accrued expenses and other liabilities	$	82.9	$	122.0

Note 5 - Investments in Unconsolidated Affiliates

Net Investments 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
	June 30,			June 30,		December 31,		Three Months Ended June 30,					Six Months Ended June 30,
	2015			2015		2014		2015		2014			2015		2014
Jackalope Gas Gathering Services, L.L.C.(1)	50.00	%	(4)	$	249.9	$	232.9	$	1.1	$	(0.6	)	$	3.6	$	(0.3	)
Tres Palacios Holdings LLC(2)	50.01	%		41.3		36.0		0.6		—			1.5		—
Powder River Basin Industrial Complex, LLC(3)	50.01	%		33.0		26.2		3.3		(0.9		)	3.3		(1.3		)
Total				$	324.2	$	295.1	$	5.0	$	(1.5	)	$	8.4	$	(1.6	)

(1) As of June 30, 2015, our investment balance exceeded our equity in the underlying net assets of Jackalope Gas Gathering Services, L.L.C. (Jackalope) by approximately $52.2 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 we reflect the amortization as a reduction of our earnings from unconsolidated affiliates. We recorded amortization of approximately 0.7 million for the three months ended June 30, 2015 and 2014, and 1.5 million for the six months ended June 30, 2015 and 2014. 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. As of June 30, 2015, our equity in the underlying net assets exceeded our investment balance in Tres Holdings by approximately $29.7 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 we reflect the amortization as an increase in our earnings from unconsolidated affiliates. We recorded amortization of approximately $0.3 million and $0.6 million for the three and six months ended June 30, 2015. Our Tres Holdings investment is included in our storage and transportation segment.

(3) As of June 30, 2015, our investment balance approximated our equity in the underlying net assets of Powder River Basin Industrial Complex, LLC (PRBIC). During the three and six months ended June 30, 2015, we recorded additional equity earnings of approximately $3.2 million related to a gain associated with the adjustment of our member's capital account by our equity investee. 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.

11

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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 six months ended June 30, 2015, we received a cash distribution of approximately $4.5 million from Jackalope. During the six months ended June 30, 2014, Jackalope did not make any distributions to its members. In July 2015, we received a cash distribution of approximately $4.2 million from Jackalope. During the six months ended June 30, 2015 and 2014, we contributed approximately $17.9 million and $45.8 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. During the six months ended June 30, 2015, we received a cash distribution of approximately $2.1 million from Tres Holdings. In July 2015, we received a cash distribution of approximately $1.9 million from Tres Holdings. During the six months ended June 30, 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 six months ended June 30, 2015, we received a cash distribution of approximately $0.7 million from PRBIC. During the six months ended June 30, 2014, PRBIC did not make any distributions to its members. In July 2015, we received a cash distribution of approximately $0.6 million from PRBIC. During the six months ended June 30, 2015 and 2014, we contributed approximately $4.2 million and $2.8 million to PRBIC.

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 June 30, 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 June 30, 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 June 30, 2014, we did not have any risk management activities.

As of June 30, 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 June 30, 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):

	June 30, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2019 Senior Notes	$	—	$	—	$	351.0	$	360.5
2020 Senior Notes	$	503.7	$	517.5	$	504.0	$	481.6
2022 Senior Notes	$	600.0	$	615.6	$	600.0	$	568.5
2023 Senior Notes	$	700.0	$	729.8	$	—	$	—

12

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Debt

Long-term debt consisted of the following at June 30, 2015 and December 31, 2014 (in millions):

	June 30, 2015		December 31, 2014
Credit Facility	$	358.3	$	555.0
2019 Senior Notes	—		350.0
Premium on 2019 Senior Notes	—		1.0
2020 Senior Notes	500.0		500.0
Fair value adjustment of 2020 Senior Notes	3.7		4.0
2022 Senior Notes	600.0		600.0
2023 Senior Notes	700.0		—
Other	3.5		3.5
Total debt	2,165.5		2,013.5
Less: current portion	6.0		0.7
Total long-term debt	$	2,159.5	$	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 June 30, 2015, we had $489.6 million of available capacity under the Credit Facility considering the most restrictive debt covenants in our credit agreement. At June 30, 2015 and December 31, 2014, the balance outstanding under our Credit Facility was $358.3 million and $555.0 million and our outstanding standby letters of credit were $5.5 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 2.94% and 5.00% at June 30, 2015 and 2.66% and 4.75% at December 31, 2014. The weighted-average interest rate as of June 30, 2015 and December 31, 2014 was 2.97% and 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 Holdings, 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 June 30, 2015, our net debt to consolidated EBITDA was approximately 4.48 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 4.17 to 1.0.

In conjunction with the Simplification Merger, we intend to enter into an amended and restated senior secured revolving credit facility under which up to $1.5 billion in aggregate principle amount of cash borrowings and letters of credit will be made available to us by a syndicate of lenders (see Note 14 for additional information).

Senior Notes

In March 2015, we issued $700.0 million of 6.25% unsecured Senior Notes due 2023 (the 2023 Senior Notes) 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 $688.3 million were used to pay down borrowings under our Credit Facility and for our general partnership purposes.

13

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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. In conjunction with the redemption of our 2019 Senior Notes, we recorded approximately $17.1 million of loss on extinguishment of debt during the second quarter of 2015.

Our senior notes are guaranteed on a senior unsecured basis by all of our domestic restricted subsidiaries, subject to certain exceptions.

At June 30, 2015, we were in compliance with all of our debt covenants applicable to our Credit Facility and our senior notes.

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 tables below show the (i) allocation of net income attributable to CMLP and the (ii) net income attributable to CMLP per limited partner unit based on the number of basic and diluted limited partner units outstanding for the three and six months ended June 30, 2015 and 2014 (in millions):

Allocation of Net Income Attributable to CMLP
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Net income (loss) attributable to CMLP	$	(47.9	)	$	8.0		$	(31.8	)	$	10.4
Class A preferred units’ interest in net income attributable to CMLP	(7.5		)	(1.1		)	(16.7		)	(1.1		)
General partner’s incentive distributions	(7.5		)	(7.5		)	(15.0		)	(15.0		)
Limited partners’ interest in net loss attributable to CMLP	$	(62.9	)	$	(0.6	)	$	(63.5	)	$	(5.7	)

Earnings Per Limited Partner Unit
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Limited partners’ interest in net loss	$	(62.9	)	$	(0.6	)	$	(63.5	)	$	(5.7	)
Weighted-average limited partner units - basic	188.3			188.0			188.3			187.9
Effect of diluted units	—			—			—			—
Weighted-average limited partner units - diluted	188.3			188.0			188.3			187.9
Basic earnings per unit:
Net income (loss) per limited partner	$	(0.33	)	$	—		$	(0.34	)	$	(0.03	)
Diluted earnings per unit:
Net income (loss) per limited partner	$	(0.33	)	$	—		$	(0.34	)	$	(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 and six months ended June 30, 2015, we excluded a weighted-average of 18,756,096 and 18,332,193 common units, representing Class A preferred units, and a weighted-average of 14,795,156 common units in both periods, representing Crestwood Niobrara's preferred units, from our diluted earnings per unit. During the three and six months ended June 30, 2014,

14

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

we excluded a weighted-average of 1,838,799 and 924,479 common units, representing Class A preferred units, and a weighted-average of 6,070,354 and 5,549,570 common units, representing Crestwood Niobrara's preferred units, from our diluted earnings per unit. See Note 8 for additional information regarding the potential conversion of these 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. Through December 31, 2014, the Class A Purchasers purchased 17,529,879 Preferred Units for a cash purchase price of $25.10 per unit resulting in gross proceeds to us of approximately $440.0 million (net proceeds of approximately $430.5 million after deducting transaction fees and offering expenses). During the three and six months ended June 30, 2015 and through the date of this filing, we did not sell any Preferred Units to the Class A Purchasers under these agreements.

In conjunction with the Simplification Merger, (i) we will issue the remaining $60 million of Preferred Units available for purchase by the Class A Purchasers under their $500 million equity commitment; and (ii) the Preferred Units will, upon completion of the merger, be exchanged for new preferred units of CEQP with substantially similar terms and conditions to those of the Preferred Units (see Note 14 for additional information).

Equity Distribution Agreement

Effective May 8, 2015, we suspended the equity distribution program with certain financial institutions under which we were allowed to offer and sell, from time to time through one or more of these financial institutions, common units having an aggregate offering price of up to $300.0 million. Prior to our suspension of this program, we did not issue any common units through these financial institutions.

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 six months ended June 30, 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 $20.9 million in each period.

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

15

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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.

During the six months ended June 30, 2015, we issued 838,228 Class A Preferred Units to our preferred unitholders in lieu of paying a cash distribution. On July 23, 2015, the board of directors of our general partner authorized the issuance of 433,707 Class A Preferred Units to our preferred unitholders for the quarter ended June 30, 2015 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 six months endedJune 30, 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
May 8, 2015	May 15, 2015	$	0.41	74.3
				$	148.6
2014
February 7, 2014	February 14, 2014	$	0.41	$	74.1
May 8, 2014	May 15, 2014	$	0.41	74.2
				$	148.3

On July 23, 2015, we declared a distribution of $0.41 per limited partner unit to be paid on August 14, 2015 to unitholders of record on August 7, 2015 with respect to the second 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 six months ended June 30, 2014, GE made capital contributions of $33.6 million to Crestwood Niobrara in exchange for an equivalent number of preferred units. GE did not make capital contributions to Crestwood Niobrara during the six months ended June 30, 2015.

In January 2015, Crestwood Niobrara issued 3,680,570 preferred units to GE in lieu of paying a cash distribution for the quarter ended December 31, 2014. 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. During the six months ended June 30, 2015, Crestwood Niobrara paid a cash distribution of $3.8 million to GE. During the three and six months ended June 30, 2014, Crestwood Niobrara issued 2,536,010 and 4,746,304 preferred units to GE in lieu of paying a cash distributions. On July 30, 2015, Crestwood Niobrara paid a cash distribution of $3.8 million to GE for the quarter ended June 30, 2015.

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. Under the terms of the Simplification Merger, the restricted and phantom common units granted under the Crestwood LTIP will be converted into 2.75 restricted units of CEQP.

16

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Crestwood LTIP

The following table summarizes information regarding restricted and phantom unit activity during the six months endedJune 30, 2015:

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2015	834,796		$	23.18
Vested - restricted units	(449,667	)	$	22.93
Vested - phantom units	(21,578	)	$	16.05
Granted - restricted units	522,328		$	16.01
Granted - phantom units	165,501		$	15.99
Forfeited(1)	(70,522	)	$	20.03
Unvested - June 30, 2015	980,858		$	18.65

(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, 39,172 restricted units were forfeited during the six months ended June 30, 2015.

As of June 30, 2015 and December 31, 2014, we had total unamortized compensation expense of approximately $12.4 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 $3.1 million and $3.3 million during the three months ended June 30, 2015 and 2014 and $6.1 million and $6.2 million during the six months ended June 30, 2015 and 2014, which is included in general and administrative expenses on our consolidated statements of operations.  An additional $2.2 million and $4.4 million of net compensation expense was allocated from CEQP to us during the three and six months ended June 30, 2015 and an additional $1.9 million and $3.6 million of net compensation expense was allocated from CEQP to us during the three and six months ended June 30, 2014 (see Note 11). We granted restricted and phantom units with a grant date fair value of approximately $8.4 million and $2.6 million during the six months ended June 30, 2015.  As of June 30, 2015, we had 17,219,872 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 ended June 30, 2015 and 2014, we withheld 2,574 and 61,076 common units to satisfy employee tax withholding obligations and during the six months ended June 30, 2015 and 2014, we withheld 137,165 and 68,532 common units.

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.

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

17

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

number of units that may be purchased under the plan is 200,000. During the three and six months ended June 30, 2015, there were 3,841 and 5,852 common units purchased through the employee unit purchase plan. Effective May 7, 2015, we suspended the employee unit purchase plan.

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.  In June 2015, the Superior Court determined that the Class Action Suit proceeding should be allowed to proceed against certain respondents that have not contributed to the global settlement described below. Because Arrow is a contributing party to the global settlement, the Class Action Suit against Arrow has been stayed pending approval of the global settlement plan in the United States and Canadian bankruptcy proceedings described below.

One of the defendants in the lawsuit, Montreal Main & Atlantic Railway (MM&A), filed bankruptcy actions in the U.S. Bankruptcy Court for the District of Maine and in the Canadian Bankruptcy Court. The bankruptcy trustees in the proceedings approached the respondents in the Class Action Suit (including Arrow) to contribute monetary damages to a global settlement for all claims, including any potential environmental damages, related to the Lac Megantic derailment. During the first quarter of 2015, we agreed to contribute to the global settlement in exchange for a release from all claims related to the derailment, including the Class Action Suit. In June 2015, the creditors in the Canadian bankruptcy proceeding voted unanimously in favor of the global settlement. The Canadian bankruptcy court approved the bankruptcy plan (including the global settlement) on July 13, 2015, which is under appeal, and the United States bankruptcy court may approve the bankruptcy plan (including the global settlement) in 2016. Our contribution to the global settlement, in addition to associated legal fees, is fully covered by insurance, and assuming the global settlement is approved by both bankruptcy courts as anticipated, Arrow should not be exposed to additional damages relating to the derailment.

Additional lawsuits related to the derailment have been filed in United States courts, all of which have been or are expected to be stayed as a result of the automatic stay arising from MM&A's United States bankruptcy proceeding. Arrow has been named as a defendant in two of these additional lawsuits, including (i) Annick Roy, as special administrator of the Estate of Jean-Guy Veilleaux, deceased, vs. Rail World, Inc., et. al. filed in the United States District Court for the District of Maine, and (ii) Samuel Audet, et. al. vs. Devlar Energy Marketing, LLC, et. al. filed in the District Court of Dallas County, Texas; however, we do not expect to be served due to the automatic stay arising from MM&A's United States bankruptcy proceeding.

We will vigorously defend ourselves and, to the extent these actions proceed, we believe we have meritorious defenses to the claims.  Moreover, based on the Company’s contribution to the global settlement and our expectation that the global settlement will be approved by both bankruptcy courts, we do not anticipate any material loss in this matter after considering insurance. Absent approval of the global settlement, we are not able to estimate our exposure to loss on this matter although we believe we have insurance to cover any reasonably possible exposure.

18

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Arrow Indemnification Action. When Arrow was 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.

In March 2015, the parties entered into a standstill agreement to facilitate settlement discussions. On June 30, 2015, the parties entered into a settlement agreement under which (i) we agreed to purchase an additional $25 million of insurance coverage underwritten specifically for claims associated with the Lac Megantic derailment; (ii) each party agreed to release the other party from all claims related to the Class Action Suit; (iii) we agreed to instruct the escrow agent to release all escrowed units to the former owners; and (iv) the former owners agreed to dismiss the lawsuit with prejudice. On July 1, 2015, we and the former owners gave irrevocable notice to the escrow agent for the release of all escrowed units, and the lawsuit was dismissed with prejudice on July 7, 2015. We did not incur material costs and expenses related to this lawsuit and settlement.

Simplification Merger Lawsuits. On May 20, 2015, Lawrence G. Farber, a purported unitholder of the Company, filed a complaint in the Southern District of the United States, Houston Division, as a putative class action on behalf of our unitholders, entitled Lawrence G. Farber, individually and on behalf of all others similarly situated vs. Crestwood Midstream Partners LP, Crestwood Midstream GP LLC, Robert G. Phillips, Alvin Bledsoe, Michael G. France, Philip D. Gettig, Warren H. Gfeller, David Lumpkins, John J. Sherman, David Wood, Crestwood Equity Partners LP, Crestwood Equity GP LLC, CEQP ST Sub LLC, MGP GP, LLC, Crestwood Midstream Holdings LP, and Crestwood Gas Services GP LLC. This complaint alleges, among other things, that our general partner breached its fiduciary duties, certain individual defendants have breached their fiduciary duties of loyalty and due care, and that other defendants have aided and abetted such breaches. The plaintiff seeks to enjoin the Simplification Merger unless and until such alleged breaches have been cured.

On July 21, 2015, Isaac Aron, another purported unitholder of the Company, filed a complaint in the Southern District of the United States, Houston Division, as a putative class action on behalf of our unitholders, entitled Isaac Aron, individually and on behalf of all others similarly situated vs. Robert G. Phillps, Alvin Bledsoe, Michael G. France, Philip D. Getting, Warren H. Gfeller, David Lumpkins, John J. Sherman, David Wood, Crestwood Midstream Partners, LP Crestwood Midstream Holdings LP, Crestwood Midstream GP LLC, Crestwood Gas Services GP, LLC, Crestwood Equity Partners LP, Crestwood Equity GP LLC, CEQP ST Sub LLC and MGP GP, LLC. The complaint alleges, among other things, that our general partner and certain individual defendants violated Sections 14(a) and 20(a) of the Securities Exchange Act of 1934 and Rule 14a-9 by filing an alleged incomplete and misleading Form S-4 Registration Statement with the Securities and Exchange Commission. The plaintiffs seek to enjoin the merger unless and until certain information is disclosed to our unitholders.

While CEQP and the Company cannot predict the outcome of these lawsuits or any other lawsuits that may be filed subsequent to the filing of this Form 10-Q, nor can CEQP and the Company predict the amount of time and expense that will be required to resolve these lawsuits or any other lawsuits, CEQP, the Company and the other defendants named in this lawsuit intend to vigorously defend against this and any other actions.

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 June 30, 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.

19

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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. In May 2015, we experienced a release of approximately 5,200 barrels of produced water on our Arrow water gathering system, immediately notified numerous regulatory authorities and other third parties, and thereafter contained and cleaned up the releases. 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 June 30, 2015.  

We may potentially be subject to fines and penalties as a result of the water releases.  In October 2014, we received data requests from the Environmental Protection Agency (EPA) related to the 2014 water releases, and we responded to the requests during the first half of 2015. In April 2015, the EPA issued a Notice of Potential Violation (NOPV) under the Clean Water Act relating to the 2014 water releases. We responded to the NOPV in May 2015, and have commenced settlement discussion with the EPA concerning the NOPV. 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 2014 water releases, and we provided the requested information during the second quarter of 2015. We cannot predict what the outcome of these investigations will be, and we had no amounts accrued for fines or penalties as of June 30, 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 June 30, 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 $1.7 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.

20

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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 and six months ended June 30, 2015 and 2014 (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014
Gathering and processing revenues	$	1.7	$	0.7	$	2.9	$	1.6
NGL and crude services revenues	$	3.3	$	3.4	$	6.7	$	6.7
Gathering and processing costs of product/services sold (1)	$	7.7	$	9.8	$	16.0	$	20.8
General and administrative expenses (2)	$	14.4	$	17.4	$	31.8	$	37.0
Reimbursement of operations and maintenance expenses	$	0.7	$	—	$	1.6	$	—

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

(2) Included in general and administrative expenses is approximately $2.2 million and $4.4 million of net unit-based compensation charges allocated to us from CEQP for the three and six months ended June 30, 2015 and $1.9 million and $3.6 million of net unit-based compensation charges allocated to us from CEQP for the three and six months ended June 30, 2014.

The following table shows accounts receivable and accounts payable from our affiliates as of June 30, 2015 and December 31, 2014 (in millions):

	June 30, 2015		December 31, 2014
Accounts receivable	$	1.2	$	0.3
Accounts payable	$	2.6	$	6.3

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 is defined as income before income taxes, plus debt-related costs (net interest and debt expense and loss on modification/extinguishment of debt) and depreciation, amortization and accretion expense.

21

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2015			2014		2015			2014
Net income (loss)	$	(42.2	)	$	11.7	$	(20.5	)	$	17.2
Add:
Interest and debt expense, net	32.6			29.0		62.5			57.1
Loss on modification/extinguishment of debt	17.1			—		17.1			—
Provision for income taxes	0.1			0.1		0.4			0.8
Depreciation, amortization and accretion	60.6			54.9		120.5			105.7
EBITDA	$	68.2		$	95.7	$	180.0		$	180.8

The following tables summarize the reportable segment data for the three and six months ended June 30, 2015 and 2014 (in millions).

	Three Months Ended June 30, 2015
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	75.0		$	44.0	$	359.4		$	—		$	478.4
Costs of product/services sold	13.3			3.4		299.4			—			316.1
Operations and maintenance expense	14.3			4.1		13.7			—			32.1
General and administrative expense	—			—		—			26.2			26.2
Loss on long-lived assets	—			—		(0.6		)	—			(0.6		)
Goodwill impairment	(8.3		)	—		(31.9		)	—			(40.2		)
Earnings from unconsolidated affiliates, net	1.1			0.6		3.3			—			5.0
EBITDA	$	40.2		$	37.1	$	17.1		$	(26.2	)	$	68.2
Goodwill	$	72.7		$	726.3	$	793.4		$	—		$	1,592.4
Total assets	$	1,963.1		$	1,961.0	$	2,430.3		$	146.8		$	6,501.2
Purchases of property, plant and equipment	$	7.9		$	3.0	$	23.2		$	0.3		$	34.4

	Three Months Ended June 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	83.4		$	45.4	$	546.9		$	—		$	675.7
Costs of product/services sold	17.6			3.8		497.7			—			519.1
Operations and maintenance expense	14.7			4.4		13.6			—			32.7
General and administrative expense	—			—		—			21.3			21.3
Gain on long-lived assets	0.5			0.6		—			—			1.1
Loss on contingent consideration	(6.5		)	—		—			—			(6.5		)
Loss from unconsolidated affiliates, net	(0.6		)	—		(0.9		)	—			(1.5		)
EBITDA	$	44.5		$	37.8	$	34.7		$	(21.3	)	$	95.7
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	1,980.2		$	1,960.6	$	2,536.7		$	158.1		$	6,635.6
Purchases of property, plant and equipment	$	79.6		$	1.3	$	19.5		$	2.7		$	103.1

22

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

	Six Months Ended June 30, 2015
	Gathering and Processing			Storage and Transportation			NGL and Crude Services			Corporate			Total
Revenues	$	153.5		$	89.7		$	690.3		$	—		$	933.5
Costs of product/services sold	26.0			6.7			570.0			—			602.7
Operations and maintenance expense	29.2			8.4			29.6			—			67.2
General and administrative expense	—			—			—			50.4			50.4
Loss on long-lived assets	(0.3		)	(0.5		)	(0.6		)	—			(1.4		)
Goodwill impairment	(8.3		)	—			(31.9		)	—			(40.2		)
Earnings from unconsolidated affiliates, net	3.6			1.5			3.3			—			8.4
EBITDA	$	93.3		$	75.6		$	61.5		$	(50.4	)	$	180.0
Goodwill	$	72.7		$	726.3		$	793.4		$	—		$	1,592.4
Total assets	$	1,963.1		$	1,961.0		$	2,430.3		$	146.8		$	6,501.2
Purchases of property, plant and equipment	$	19.3		$	5.7		$	52.3		$	0.4		$	77.7

	Six Months Ended June 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	162.9		$	89.7	$	960.1		$	—		$	1,212.7
Costs of product/services sold	36.3			7.0		873.9			—			917.2
Operations and maintenance expense	28.1			8.7		23.9			—			60.7
General and administrative expense	—			—		—			45.4			45.4
Gain on long-lived assets	1.0			0.6		—			—			1.6
Loss on contingent consideration	(8.6		)	—		—			—			(8.6		)
Loss from unconsolidated affiliates, net	(0.3		)	—		(1.3		)	—			(1.6		)
EBITDA	$	90.6		$	74.6	$	61.0		$	(45.4	)	$	180.8
Goodwill	$	99.6		$	726.3	$	855.5		$	—		$	1,681.4
Total assets	$	1,980.2		$	1,960.6	$	2,536.7		$	158.1		$	6,635.6
Purchases of property, plant and equipment	$	125.9		$	2.5	$	48.4		$	3.6		$	180.4

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 and six months ended June 30, 2014 have been corrected for certain errors in presentation between the parent and guarantor subsidiaries. There was no impact to our consolidated statement of operations for the three and six months ended June 30, 2014 or our consolidated statement of cash flows for the six months ended June 30, 2014.

23

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2014
(in millions)
	Parent						Guarantor Subsidiaries				Eliminations
	As Adjusted			As Previously Reported			As Adjusted		As Previously Reported		As Adjusted			As Previously Reported
General and administrative expense	$	9.9		$	(0.9	)	$	11.4	$	22.2	$	—		$	—
Operating income (loss)	(10.1		)	0.7			52.4		41.6		—			—
Interest and debt expense, net	(29.0		)	(29.2		)	—		0.2		—			—
Equity in net income (loss) of subsidiary	50.8			40.2			—		—		(50.8		)	(40.2		)
Income (loss) before income taxes	11.7			11.7			52.4		41.8		(50.8		)	(40.2		)
Net income (loss)	11.7			11.7			52.3		41.7		(50.8		)	(40.2		)
Net income (loss) attributable to Crestwood Midstream Partners LP	11.7			11.7			52.3		41.7		(50.8		)	(40.2		)
Net income (loss) attributable to partners	10.6			10.6			52.3		41.7		(50.8		)	(40.2		)

Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2014
(in millions)
	Parent						Guarantor Subsidiaries				Eliminations
	As Adjusted			As Previously Reported			As Adjusted		As Previously Reported		As Adjusted			As Previously Reported
General and administrative expense	$	26.9		$	(3.0	)	$	18.5	$	48.4	$	—		$	—
Operating income (loss)	(27.3		)	2.6			104.0		74.1		—			—
Interest and debt expense, net	(57.1		)	(57.3		)	—		0.2		—			—
Equity in net income (loss) of subsidiary	101.6			71.9			—		—		(101.6		)	(71.9		)
Income (loss) before income taxes	17.2			17.2			104.0		74.3		(101.6		)	(71.9		)
Net income (loss)	17.2			17.2			103.2		73.5		(101.6		)	(71.9		)
Net income (loss) attributable to Crestwood Midstream Partners LP	17.2			17.2			103.2		73.5		(101.6		)	(71.9		)
Net income (loss) attributable to partners	16.1			16.1			103.2		73.5		(101.6		)	(71.9		)

24

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2014
(in millions)
	Parent						Guarantor Subsidiaries						Non-Guarantor Subsidiaries						Eliminations
	As Adjusted			As Previously Reported			As Adjusted			As Previously Reported			As Adjusted			As Previously Reported			As Adjusted			As Previously Reported
Cash flows from operating activities:	$	(80.4	)	$	(16.7	)	$	191.5		$	112.1		$	—		$	—		$	—		$	—
Cash flows from investing activities:
Investment in unconsolidated affiliates, net	—			—			—			(2.8		)	(48.6		)	(45.8		)	—			—
Capital contributions from consolidated affiliates	(14.0		)	(11.2		)	—			(2.8		)	—			—			14.0			14.0
Other	—			(265.5		)	—			—			—			—			—			265.5
Net cash provided by (used in) investing activities	(16.3		)	(279.0		)	(197.6		)	(187.5		)	(48.6		)	(45.8		)	14.0			279.5
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	860.6			2.5			—			858.1			—			—			—			—
Principal payments on long-term debt	(863.2		)	—			—			(863.2		)	—			—			—			—
Distributions paid	(169.2		)	—			—			(169.2		)	—			—			—			—
Contributions from parent	—			—			—			2.8			14.0			11.2			(14.0		)	(14.0		)
Change in intercompany balances	(24.7		)	—			24.7			265.5			—			—			—			(265.5		)
Net cash provided by (used in) financing activities	96.7			295.7			21.7			91.0			47.6			44.8			(14.0		)	(279.5		)

The tables below present condensed consolidating financial statements for us (parent) on a stand-alone, unconsolidated basis, and our combined guarantor and combined non-guarantor subsidiaries as of June 30, 2015 and December 31, 2014, and for the three and six months ended June 30, 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.

25

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Balance Sheet
June 30, 2015
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	—	$	0.2	$	—	$	—		$	0.2
Accounts receivable	0.7		225.5		—		—			226.2
Accounts receivable - related party	—		0.4		0.8		—			1.2
Total accounts receivable	0.7		225.9		0.8		—			227.4
Inventory	—		12.8		—		—			12.8
Other current assets	—		17.5		—		—			17.5
Total current assets	0.7		256.4		0.8		—			257.9
Property, plant and equipment, net	7.3		3,479.8		—		—			3,487.1
Goodwill and intangible assets, net	42.8		2,387.9		—		—			2,430.7
Investment in consolidated affiliates	6,257.7		—		—		(6,257.7		)	—
Investment in unconsolidated affiliates	—		—		324.2		—			324.2
Other assets	—		1.3		—		—			1.3
Total assets	$	6,308.5	$	6,125.4	$	325.0	$	(6,257.7	)	$	6,501.2
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	1.7	$	105.5	$	—	$	—		$	107.2
Accounts payable - related party	1.6		0.4		0.6		—			2.6
Total accounts payable	3.3		105.9		0.6		—			109.8
Other current liabilities	32.8		56.1		—		—			88.9
Total current liabilities	36.1		162.0		0.6		—			198.7
Long-term liabilities:
Long-term debt, less current portion	2,159.5		—		—		—			2,159.5
Other long-term liabilities	0.8		30.1		—		—			30.9
Partners' capital	3,932.9		5,933.3		145.2		(6,078.5		)	3,932.9
Interest of non-controlling partners in subsidiaries	179.2		—		179.2		(179.2		)	179.2
Total partners' capital	4,112.1		5,933.3		324.4		(6,257.7		)	4,112.1
Total liabilities and partners' capital	$	6,308.5	$	6,125.4	$	325.0	$	(6,257.7	)	$	6,501.2

26

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
Inventory	—		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

27

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	478.4		$	—		$	—		$	478.4
Costs of product/services sold	—			316.1			—			—			316.1
Expenses:
Operations and maintenance	—			32.1			—			—			32.1
General and administrative	16.4			9.8			—			—			26.2
Depreciation, amortization and accretion	0.9			59.7			—			—			60.6
	17.3			101.6			—			—			118.9
Other operating expense:
Loss on long-lived assets, net	—			(0.6		)	—			—			(0.6		)
Goodwill impairment	—			(40.2		)	—			—			(40.2		)
Operating income (loss)	(17.3		)	19.9			—			—			2.6
Earnings from unconsolidated affiliates, net	—			—			5.0			—			5.0
Interest and debt expense, net	(32.6		)	—			—			—			(32.6		)
Loss on modification/extinguishment of debt	(17.1		)	—			—			—			(17.1		)
Equity in net income (loss) of subsidiary	24.8			—			—			(24.8		)	—
Income (loss) before income taxes	(42.2		)	19.9			5.0			(24.8		)	(42.1		)
Provision for income taxes	—			0.1			—			—			0.1
Net income (loss)	(42.2		)	19.8			5.0			(24.8		)	(42.2		)
Net income attributable to non-controlling partners	—			—			(5.7		)	—			(5.7		)
Net income (loss) attributable to Crestwood Midstream Partners LP	(42.2		)	19.8			(0.7		)	(24.8		)	(47.9		)
Net income attributable to Class A preferred units	(7.5		)	—			—			—			(7.5		)
Net income (loss) attributable to partners	$	(49.7	)	$	19.8		$	(0.7	)	$	(24.8	)	$	(55.4	)

28

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Three Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	675.7		$	—		$	—		$	675.7
Costs of product/services sold	—			519.1			—			—			519.1
Expenses:
Operations and maintenance	—			32.7			—			—			32.7
General and administrative	9.9			11.4			—			—			21.3
Depreciation, amortization and accretion	0.2			54.7			—			—			54.9
	10.1			98.8			—			—			108.9
Other operating income (expense):
Gain on long-lived assets, net	—			1.1			—			—			1.1
Loss on contingent consideration	—			(6.5		)	—			—			(6.5		)
Operating income (loss)	(10.1		)	52.4			—			—			42.3
Loss from unconsolidated affiliates, net	—			—			(1.5		)	—			(1.5		)
Interest and debt expense, net	(29.0		)	—			—			—			(29.0		)
Equity in net income (loss) of subsidiary	50.8			—			—			(50.8		)	—
Income (loss) before income taxes	11.7			52.4			(1.5		)	(50.8		)	11.8
Provision for income taxes	—			0.1			—			—			0.1
Net income (loss)	11.7			52.3			(1.5		)	(50.8		)	11.7
Net income attributable to non-controlling partners	—			—			(3.7		)	—			(3.7		)
Net income (loss) attributable to Crestwood Midstream Partners LP	11.7			52.3			(5.2		)	(50.8		)	8.0
Net income attributable to Class A preferred units	(1.1		)	—			—			—			(1.1		)
Net income (loss) attributable to partners	$	10.6		$	52.3		$	(5.2	)	$	(50.8	)	$	6.9

29

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	933.5		$	—		$	—		$	933.5
Costs of product/services sold	—			602.7			—			—			602.7
Expenses:
Operations and maintenance	—			67.2			—			—			67.2
General and administrative	29.8			20.6			—			—			50.4
Depreciation, amortization and accretion	1.1			119.4			—			—			120.5
	30.9			207.2			—			—			238.1
Other operating expense:
Loss on long-lived assets, net	—			(1.4		)	—			—			(1.4		)
Goodwill impairment	—			(40.2		)	—			—			(40.2		)
Operating income (loss)	(30.9		)	82.0			—			—			51.1
Earnings from unconsolidated affiliates, net	—			—			8.4			—			8.4
Interest and debt expense, net	(62.5		)	—			—			—			(62.5		)
Loss on modification/extinguishment of debt	(17.1		)	—			—			—			(17.1		)
Equity in net income (loss) of subsidiary	90.0			—			—			(90.0		)	—
Income (loss) before income taxes	(20.5		)	82.0			8.4			(90.0		)	(20.1		)
Provision for income taxes	—			0.4			—			—			0.4
Net income (loss)	(20.5		)	81.6			8.4			(90.0		)	(20.5		)
Net income attributable to non-controlling partners	—			—			(11.3		)	—			(11.3		)
Net income (loss) attributable to Crestwood Midstream Partners LP	(20.5		)	81.6			(2.9		)	(90.0		)	(31.8		)
Net income attributable to Class A preferred units	(16.7		)	—			—			—			(16.7		)
Net income (loss) attributable to partners	$	(37.2	)	$	81.6		$	(2.9	)	$	(90.0	)	$	(48.5	)

30

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Operations
Six Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	1,212.7		$	—		$	—		$	1,212.7
Costs of product/services sold	—			917.2			—			—			917.2
Expenses:
Operations and maintenance	—			60.7			—			—			60.7
General and administrative	26.9			18.5			—			—			45.4
Depreciation, amortization and accretion	0.4			105.3			—			—			105.7
	27.3			184.5			—			—			211.8
Other operating income (expense):
Gain on long-lived assets, net	—			1.6			—			—			1.6
Loss on contingent consideration	—			(8.6		)	—			—			(8.6		)
Operating income (loss)	(27.3		)	104.0			—			—			76.7
Loss from unconsolidated affiliates, net	—			—			(1.6		)	—			(1.6		)
Interest and debt expense, net	(57.1		)	—			—			—			(57.1		)
Equity in net income (loss) of subsidiary	101.6			—			—			(101.6		)	—
Income (loss) before income taxes	17.2			104.0			(1.6		)	(101.6		)	18.0
Provision for income taxes	—			0.8			—			—			0.8
Net income (loss)	17.2			103.2			(1.6		)	(101.6		)	17.2
Net income attributable to non-controlling partners	—			—			(6.8		)	—			(6.8		)
Net income (loss) attributable to Crestwood Midstream Partners LP	17.2			103.2			(8.4		)	(101.6		)	10.4
Net income attributable to Class A preferred units	(1.1		)	—			—			—			(1.1		)
Net income (loss) attributable to partners	$	16.1		$	103.2		$	(8.4	)	$	(101.6	)	$	9.3

31

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(89.1	)	$	231.0		$	6.0		$	—		$	147.9
Cash flows from investing activities:
Purchases of property, plant and equipment	(0.4		)	(77.3		)	—			—			(77.7		)
Investment in unconsolidated affiliates	—			—			(27.8		)	—			(27.8		)
Capital distributions from unconsolidated affiliates	—			—			1.0			—			1.0
Proceeds from sale of assets	—			1.7			—			—			1.7
Capital contribution to consolidated affiliates	(24.6		)	—			—			24.6			—
Net cash provided by (used in) investing activities	(25.0		)	(75.6		)	(26.8		)	24.6			(102.8		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	1,865.1			—			—			—			1,865.1
Principal payments on long-term debt	(1,712.5		)	—			—			—			(1,712.5		)
Payments on capital leases	(0.9		)	(0.3		)	—			—			(1.2		)
Payments for debt-related deferred costs	(11.7		)	—			—			—			(11.7		)
Financing fees paid for early debt redemption	(13.6		)	—			—			—			(13.6		)
Distributions paid	(169.5		)	—			(3.8		)	—			(173.3		)
Contributions from parent	—			—			24.6			(24.6		)	—
Taxes paid for unit-based compensation vesting	—			(2.1		)	—			—			(2.1		)
Change in intercompany balances	157.4			(157.4		)	—			—			—
Other	(0.2		)	—			—			—			(0.2		)
Net cash provided by (used in) financing activities	114.1			(159.8		)	20.8			(24.6		)	(49.5		)
Net change in cash	—			(4.4		)	—			—			(4.4		)
Cash at beginning of period	—			4.6			—			—			4.6
Cash at end of period	$	—		$	0.2		$	—		$	—		$	0.2

32

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Condensed Consolidating Statements of Cash Flows
Six Months Ended June 30, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(80.4	)	$	191.5		$	—		$	—		$	111.1
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(19.5		)	—			—			(19.5		)
Purchases of property, plant and equipment	(2.3		)	(178.1		)	—			—			(180.4		)
Investment in unconsolidated affiliates	—			—			(48.6		)	—			(48.6		)
Capital contribution to consolidated affiliates	(14.0		)	—			—			14.0			—
Net cash provided by (used in) investing activities	(16.3		)	(197.6		)	(48.6		)	14.0			(248.5		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	860.6			—			—			—			860.6
Principal payments on long-term debt	(863.2		)	—			—			—			(863.2		)
Payments on capital leases	(0.5		)	(1.4		)	—			—			(1.9		)
Distributions paid	(169.2		)	—			—			—			(169.2		)
Contributions from parent	—			—			14.0			(14.0		)	—
Net proceeds from issuance of preferred equity of subsidiary	—			—			33.6			—			33.6
Net proceeds from issuance of Class A preferred units	293.7			—			—			—			293.7
Taxes paid for unit-based compensation vesting	—			(1.5		)	—			—			(1.5		)
Change in intercompany balances	(24.7		)	24.7			—			—			—
Other	—			(0.1		)	—			—			(0.1		)
Net cash provided by (used in) financing activities	96.7			21.7			47.6			(14.0		)	152.0
Net change in cash	—			15.6			(1.0		)	—			14.6
Cash at beginning of period	0.1			1.6			1.0			—			2.7
Cash at end of period	$	0.1		$	17.2		$	—		$	—		$	17.3

33

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 14 – Simplification Merger

On May 5, 2015, CEQP, the Company and certain of its affiliates entered into a definitive agreement under which we have agreed to merge with a wholly-owned subsidiary of CEQP, with the Company surviving as a wholly-owned subsidiary of CEQP.  As part of the merger consideration, our common unitholders will become unitholders of CEQP in a tax free exchange, with our common unitholders receiving 2.75 common units of CEQP for each common unit of the Company held upon completion of the merger.  Upon completion of the Simplification Merger, our IDRs will be eliminated and our common units will cease to be listed on the NYSE.  We expect to complete the merger in the third quarter of 2015, subject to the approval by our unitholders and the satisfaction of customary closing conditions. The Simplification Merger was unanimously approved by the boards of directors of the Company and CEQP, based on the unanimous approval and recommendation of their respective conflicts committees, which consisted entirely of independent directors.

Under the merger agreement, (i) we are required to call, prior to the closing of the Simplification Merger, the remaining $60 million of equity commitment made available by the Class A Purchasers; and (ii) we will, contemporaneously with or immediately following the closing of the Simplification Merger, acquire CEQP's proprietary NGL business. Also, in conjunction with the Simplification Merger:

• CEQP and Crestwood Holdings each entered into a support agreement with the Company under which CEQP and Crestwood Holdings have agreed to vote their respective CMLP common units in favor of the Simplification Merger at the unitholder meeting required by the merger; and

• the Class A Holders entered into letter agreements with the Company under which they have agreed, subject to the closing of the merger, to exchange their Preferred Units into new preferred units of CEQP upon completion of the Simplification Merger.

Although not required by the merger agreement, we anticipate contemporaneously with the closing of the merger that we will repay and retire all borrowings under our existing Credit Facility. This indebtedness will effectively be retired with a combination of proceeds received by the Company from the sale of Preferred Units to the Class A Purchasers prior to the closing of the Simplification Merger and borrowings under our amended and restated credit facility (described below).

To refinance the existing Credit Facility in conjunction with the Simplification Merger, we intend to enter into an amended and restated senior secured revolving credit facility under which up to $1.5 billion in aggregate principle amount of cash borrowings and letters of credit will be made available to us by a syndicate of lenders. In July 2015, we received final lender commitments for the $1.5 billion revolving credit facility and, subject to customary closing conditions (including the closing of the merger and our acquisition of CEQP's NGL assets concurrently with or immediately following the closing of the amended and restated credit facility), we expect to close the amended and restated credit agreement contemporaneously with the closing of the Simplification Merger. Pursuant to the final commitments from the syndicate of lenders, we anticipate that the terms of the amended and restated credit agreement will be substantially similar to the terms and conditions of our existing $1.0 billion credit facility, and that the proprietary NGL business acquired from CEQP will be part of the lenders’ collateral package.

Following the acquisition of CEQP's proprietary NGL business and refinancing described above, we will own all of the operating assets within the Crestwood partnerships and will issue all of the debt (including bank loans and senior notes) required to operate those businesses. CEQP, as our publicly-traded parent company following the merger, will issue common units when equity capital is required by our businesses.

34

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; (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 (iv) our expectation that the Simplification Merger will close in the third quarter; 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 an master limited partnership 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.

35

On May 5, 2015, CEQP, the Company and certain of its affiliates entered into a definitive agreement under which we have agreed to merger with a wholly-owned subsidiary of CEQP, with the Company surviving as a wholly-owned subsidiary of CEQP.  As part of the merger consideration, our common unitholders will become unitholders of CEQP in a tax free exchange, our IDRs will also be eliminated and our common units will cease to be listed on the NYSE.  Contemporaneously with or immediately following the closing of the Simplification Merger, the Company will acquire CEQP’s proprietary NGL business. As discussed in more detail below, we believe this strategic simplification of the Crestwood structure will improve our capital structure and better position us to compete for acquisitions and growth opportunities during a period of increased competition and low commodity prices. A more detailed explanation of the merger agreement and our obligations thereunder is available in the Current Report on Form 8-K filed by the Company with the SEC on May 6, 2015. Additional information regarding our reasons for pursuing the Simplification Merger, as well as certain other items relating to the merger and our post-merger operations, is available in Amendment No. 1 to the Registration Statement on Form S-4 filed by CEQP with SEC on July 24, 2015.

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.

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 wells in conjunction with that filing. Quicksilver’s creditors were required to submit claims by July 31, 2015, and Quicksilver has the exclusive right to submit its restructuring plan to the bankruptcy court by mid-October. 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.

36

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). We have completed the NS-1 Expansion project which 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. We completed an open season for an expansion of the MARC I Pipeline in the first quarter of 2015 and have entered into firm service contracts with multiple customers for the expansion capacity.  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). We expect to complete the expansion project 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. In June 2015, we completed the construction of a 200,000 barrel crude oil storage tank at the Arrow central delivery point and placed it into service.

Outlook and Trends

Our long-term growth potential 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.

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Another critical factor to improvement in our financial results in 2015 is reduced operating and administrative costs. 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 $8 million and $12 million of upfront costs during the three and six months ended June 30, 2015 related to this cost savings initiative and the Simplification Merger. Absent these upfront costs, our expenses related to operations, maintenance and general and administrative matters decreased by $4 million and $1.0 million during the three and six months ended June 30, 2015 compared to the same periods in 2014.

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.

In May 2015, we announced the Simplification Merger. We believe combining the Crestwood partnerships will lower our capital costs (primarily by eliminating our existing IDR burden and multiple public company costs) and position us to better compete for expansion opportunities necessary to execute our growth strategy. We believe greater strategic transparency and streamlined corporate structure resulting from the Simplification Merger will allow us to attract capital on economic terms more favorable than we currently experience. In addition, to the extent other strategic alternatives emerge (prior to or following the merger) that enable us to create significant unitholder value, the Simplification Merger does not preclude us from pursuing those alternatives.

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 (Watkins Glen reporting unit). 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, and an issues conference was held in February 2015 to determine whether any significant and substantive issues concerning our project require further adjudication. We expect the Administrative Law Judge (ALJ) presiding over the issues conferences to issue a decision in the third quarter of 2015.  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 $34 million of goodwill related to this NGL storage facility as of June 30, 2015.

Qualifying Income Status and Proposed Regulations

Pursuant to Internal Revenue Code Section 7704(c)(2), in order to be treated as a partnership for U.S. federal income tax purposes, more than 90 percent of the income of a partnership must be from certain specified sources, including the exploration, development, mining or production, processing, refining, marketing and transportation of minerals and natural resources. On May 5, 2015, the Treasury Department and the IRS issued the Proposed Regulations regarding qualifying income under Section 7704(d)(1)(E) of the Code. The Proposed Regulations provide rules regarding the Qualifying Income Exception. The comment period on the proposed new regulations ends on August 5, 2015. When the comment period closes, the IRS will review and analyze the comments received. During this time, they may consult with industry experts and others to fully understand the matter. However, there is no set time frame for this process and it can take months or years to finalize the proposed new regulations. Although we do not believe, based upon our current operations and language of the proposed regulations, that we will be treated as corporation for U.S. federal income tax purposes, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for purposes of the qualifying income requirement.

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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 debt-related costs (net interest and debt expense and loss on modification/extinguishment of debt) 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 and six months ended June 30, 2015 and 2014 (in millions):

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
Revenues	$	478.4		$	675.7		$	933.5		$	1,212.7
Costs of product/services sold	316.1			519.1			602.7			917.2
Operations and maintenance expense	32.1			32.7			67.2			60.7
General and administrative expense	26.2			21.3			50.4			45.4
Depreciation, amortization and accretion	60.6			54.9			120.5			105.7
Gain (loss) on long-lived assets, net	(0.6		)	1.1			(1.4		)	1.6
Goodwill impairment	(40.2		)	—			(40.2		)	—
Loss on contingent consideration	—			(6.5		)	—			(8.6		)
Operating income	2.6			42.3			51.1			76.7
Earnings (loss) from unconsolidated affiliates, net	5.0			(1.5		)	8.4			(1.6		)
Interest and debt expense, net	(32.6		)	(29.0		)	(62.5		)	(57.1		)
Loss on modification/extinguishment of debt	(17.1		)	—			(17.1		)	—
Provision for income taxes	(0.1		)	(0.1		)	(0.4		)	(0.8		)
Net income (loss)	$	(42.2	)	$	11.7		$	(20.5	)	$	17.2
Add:
Interest and debt expense, net	32.6			29.0			62.5			57.1
Loss on modification/extinguishment of debt	17.1			—			17.1			—
Provision for income taxes	0.1			0.1			0.4			0.8
Depreciation, amortization and accretion	60.6			54.9			120.5			105.7
EBITDA	$	68.2		$	95.7		$	180.0		$	180.8
Unit-based compensation charges	5.3			5.2			10.5			9.8
(Gain) loss on long-lived assets, net	0.6			(1.1		)	1.4			(1.6		)
Goodwill impairment	40.2			—			40.2			—
Loss on contingent consideration	—			6.5			—			8.6
(Earnings) loss from unconsolidated affiliates, net	(5.0		)	1.5			(8.4		)	1.6
Adjusted EBITDA from unconsolidated affiliates, net	5.7			0.4			12.2			2.1
Significant transaction and environmental related costs and other items	10.4			1.5			14.2			7.3
Adjusted EBITDA	$	125.4		$	109.7		$	250.1		$	208.6

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
EBITDA:
Net cash provided by operating activities	$	70.9		$	43.4		$	147.9		$	111.1
Net changes in operating assets and liabilities	14.4			36.9			23.6			34.3
Amortization of debt-related deferred costs and premiums	(2.0		)	(1.8		)	(3.9		)	(3.6		)
Interest and debt expense, net	32.6			29.0			62.5			57.1
Unit-based compensation charges	(5.3		)	(5.2		)	(10.5		)	(9.8		)
Gain (loss) on long-lived assets, net	(0.6		)	1.1			(1.4		)	1.6
Goodwill impairment	(40.2		)	—			(40.2		)	—
Loss on contingent consideration	—			(6.5		)	—			(8.6		)
Earnings (loss) from unconsolidated affiliates, net, adjusted for cash distributions	(1.3		)	(1.5		)	2.1			(1.6		)
Deferred income taxes	(0.2		)	—			(0.3		)	(0.5		)
Provision for income taxes	0.1			0.1			0.4			0.8
Other non-cash income	(0.2		)	0.2			(0.2		)	—
EBITDA	$	68.2		$	95.7		$	180.0		$	180.8
Unit-based compensation charges	5.3			5.2			10.5			9.8
(Gain) loss on long-lived assets, net	0.6			(1.1		)	1.4			(1.6		)
Goodwill impairment	40.2			—			40.2			—
Loss on contingent consideration	—			6.5			—			8.6
(Earnings) loss from unconsolidated affiliates, net	(5.0		)	1.5			(8.4		)	1.6
Adjusted EBITDA from unconsolidated affiliates, net	5.7			0.4			12.2			2.1
Significant transaction and environmental related costs and other items	10.4			1.5			14.2			7.3
Adjusted EBITDA	$	125.4		$	109.7		$	250.1		$	208.6

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

	Three Months Ended								Three Months Ended
	June 30, 2015								June 30, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Gathering and Processing			Storage and Transportation		NGL and Crude Services
Revenues	$	75.0		$	44.0	$	359.4		$	83.4		$	45.4	$	546.9
Costs of product/services sold	13.3			3.4		299.4			17.6			3.8		497.7
Operations and maintenance expense	14.3			4.1		13.7			14.7			4.4		13.6
Gain (loss) on long-lived assets	—			—		(0.6		)	0.5			0.6		—
Goodwill impairment	(8.3		)	—		(31.9		)	—			—		—
Loss on contingent consideration	—			—		—			(6.5		)	—		—
Earnings (loss) from unconsolidated affiliates	1.1			0.6		3.3			(0.6		)	—		(0.9		)
EBITDA	$	40.2		$	37.1	$	17.1		$	44.5		$	37.8	$	34.7

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	Six Months Ended									Six Months Ended
	June 30, 2015									June 30, 2014
	Gathering and Processing			Storage and Transportation			NGL and Crude Services			Gathering and Processing			Storage and Transportation		NGL and Crude Services
Revenues	$	153.5		$	89.7		$	690.3		$	162.9		$	89.7	$	960.1
Costs of product/services sold	26.0			6.7			570.0			36.3			7.0		873.9
Operations and maintenance expense	29.2			8.4			29.6			28.1			8.7		23.9
Gain (loss) on long-lived assets	(0.3		)	(0.5		)	(0.6		)	1.0			0.6		—
Goodwill impairment	(8.3		)	—			(31.9		)	—			—		—
Loss on contingent consideration	—			—			—			(8.6		)	—		—
Earnings (loss) from unconsolidated affiliates	3.6			1.5			3.3			(0.3		)	—		(1.3		)
EBITDA	$	93.3		$	75.6		$	61.5		$	90.6		$	74.6	$	61.0

Segment Results

Below is a discussion of the factors that impacted EBITDA by segment for the three and six months ended June 30, 2015 compared to the same periods in 2014.

Gathering and Processing

EBITDA for our G&P segment decreased by $4.3 million during the three months ended June 30, 2015 compared to the same period in 2014, while we experienced an increase in EBITDA of approximately $2.7 million during the six months ended June 30, 2015 compared to the same period in 2014. The decrease in EBITDA during the three months ended June 30, 2015 was primarily due to a $8.3 million goodwill impairment recorded during the three months ended June 30, 2015 related to our operations in the Fayetteville Shale, which is discussed in more detail below.

During the three and six months ended June 30. 2015, we recorded an increase of approximately $1.7 million and $3.9 million in equity earnings from Jackalope Gas Gathering Services, L.L.C. (Jackalope). The increase was primarily attributable to Jackalope placing its Bucking Horse processing plant in service in January 2015.

Our G&P segment's EBITDA was also impacted by a decrease in revenues which was substantially offset by lower costs of product/services sold. Our G&P segment’s revenues decreased by approximately $8.4 million and $9.4 million during the three and six months ended June 30, 2015 compared to the same periods in 2014, although we experienced an increase in our compression volumes while our gathering volumes remained relatively flat. 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 under our percent-of-proceeds contracts, and lower revenues from our Barnett Shale operations during the three and six months ended June 30, 2015 due to Quicksilver shutting in certain of its wells in conjunction with its filing for protection under Chapter 11 of the U.S. Bankruptcy Code. Partially offsetting the declines in our G&P revenues discussed above were higher gathering and compression revenues from Antero, our primary customer in the Marcellus Shale. Our compression volumes increased from 0.5 Bcf/d for both the three and six months ended June 30, 2014 to 0.6 Bcf/d during the same periods in 2015. The increases in our G&P 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. We gathered approximately 1.1 Bcf/d of natural gas on our G&P systems, excluding gathering volumes associated with our Jackalope equity investment, during both the three and six months ended June 30, 2015 compared to 1.2 Bcf/d and 1.1 Bcf/d during the same periods in 2014.

The decrease in revenues was partially offset by lower costs of product/services sold of approximately $4.3 million and $10.3 million. The decrease in our G&P segment's costs of product/services sold was primarily driven by lower NGL and natural gas prices under our percent-of-proceeds contracts related to our assets located in Granite Wash. In July 2015, one of our customers in the Granite Wash, Sabine Oil and Gas Corporation (Sabine), filed for protection under Chapter 11 of the U.S. Bankruptcy Code. We are closely monitoring our exposure to Sabine and we do not believe Sabine's bankruptcy will have a material impact to our G&P segment's results of operations.

Also impacting our G&P segment's EBITDA were higher operations and maintenance expense of approximately $1.1 million during the six months ended June 30, 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 operations and maintenance expenses were relatively flat during the three months ended June 30, 2015 compared to the same period in 2014.

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Our G&P segment's EBITDA was impacted by a $6.5 million and an $8.6 million loss on contingent consideration recorded in the three and six months ended June 30, 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.

Our G&P segment's EBITDA for the three and six months ended June 30, 2015 was also impacted by an $8.3 million impairment of the goodwill associated with our operations in the Fayetteville Shale due to an increase in the discount rate utilized to determine the fair value of this business, which primarily resulted from the continued decrease in commodity prices and its impact on the midstream industry. For a further discussion of this goodwill impairment, see Item 1. Financial Statements, Note 2.

Storage and Transportation

Our storage and transportation segment's EBITDA decreased by approximately $0.7 million for the three months ended June 30, 2015 compared to the same period in 2014, while we experienced an increase in EBITDA of approximately $1.0 million during the six months ended June 30, 2015 compared to the same period in 2014. During the three and six months ended June 30, 2015, we experienced higher revenues from additional firm storage and transportation services resulting from organic growth projects placed in service during the last half of 2014 and the first half of 2015, primarily the NS-1 Expansion project, which increased volumes delivered into Millennium Pipeline. Offsetting the favorable revenue impacts discussed above, were lower revenues from interruptible services during the three and six months ended June 30, 2015 compared to the same periods in 2014. During 2014, we experienced higher revenues from interruptible services resulting from increased producer activity and increased locational basis spreads in the Northeast. During the three months ended June 30, 2015, total firm throughput from our Northeast storage and transportation services averaged approximately 1.6 Bcf/d compared to 1.5 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 and six months ended June 30, 2015 compared to the same periods 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). During the three and six months ended June 30, 2015, we recorded earnings from our unconsolidated affiliate of approximately $0.6 million and $1.5 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

EBITDA for our NGL and Crude Services segment decreased by approximately $17.6 million for the three months ended June 30, 2015 compared to the same periods in 2014, although our EBITDA was relatively flat for the six months ended June 30, 2015 compared to the same period in 2014. During the three months ended June 30, 2015, we recorded a $31.9 million goodwill impairment recorded related to our Watkins Glen operations, which is discussed in more detail below.

Offsetting the $31.9 million goodwill impairment, our NGL and crude services segment's EBITDA increased by approximately $14.3 million and $32.4 million during the three and six months ended June 30, 2015 compared to the same periods 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 $198.3 million and $303.9 million during the three and six months ended June 30, 2015 compared to the same periods in 2014 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 approximately 50% during the three and six months ended June 30, 2015 compared to the same periods 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 March and May of 2014.

Our NGL and crude services segment's revenues decreased by $187.5 million and $269.8 million during the three and six months ended June 30, 2015 compared to the same periods in 2014, due primarily to a $194.0 million and $290.4 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 2%, 41% and 33% during the three months ended June 30, 2015 compared to the same period in 2014. We also

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experienced an increase of 23%, 74% and 60% in our crude oil, natural gas and water volumes, respectively, during the six months ended June 30, 2015 compared to the same period in 2014, as new wells were connected to our system. Partially offsetting this decline in revenues during the three and six months ended June 30, 2015 compared to the same periods in 2014, was a $6.6 million and $13.4 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 both the three and six months ended June 30, 2015, we loaded approximately 122 MBbls/d of crude on rail cars entering the facility compared to approximately 112 MBbls/d and 105 MBbls/d during the same period in 2014. We also experienced an increase in revenues of $4.8 million during the six months ended June 30, 2015 related to our crude oil transportation operations acquired in March and May of 2014.

During the six months ended June 30, 2015, we experienced higher operations and maintenance expense of $5.7 million primarily due to the acquisition of our crude oil transportation fleet in the second quarter of 2014. Our operations and maintenance expenses were relatively flat during the three months ended June 30, 2015 compared to the same period in 2014.

For both the three and six months ended June 30, 2015, our proportionate share of net earnings from our unconsolidated affiliate, PRBIC, was $3.3 million compared to a net loss of approximately $0.9 million and $1.3 million during the three and six months ended June 30, 2014. For a further discussion of our investment in PRBIC, see Item 1. Financial Statements, Note 5.

Our NGL and Crude Services segment's EBITDA for the three and six months ended June 30, 2015 was also impacted by a $31.9 million impairment of goodwill associated with our Watkins Glen operations due to an increase in the discount rate utilized to determine the fair value of this business, coupled with continued delays and uncertainties in the permitting of our proposed NGL storage facility. For a further discussion of this impairment, see Item 1, Financial Statements, Note 2.

Other Results

Our consolidated EBITDA for the three and six months ended June 30, 2015 was $68.2 million and $180.0 million, a decrease of $27.5 million and $0.8 million compared to the same periods in 2014. Our consolidated Adjusted EBITDA for the three and six months ended June 30, 2015 was $125.4 million and $250.1 million, an increase of $15.7 million and $41.5 million compared to the same periods in 2014. The change in our EBITDA and Adjusted EBITDA period over period was primarily driven by our segment results described above. Partially offsetting those results were higher general and administrative expenses of approximately $5 million from our Corporate operations during the three and six months ended June 30, 2015 compared to the same periods in 2014 due to approximately $10.4 million and $14.2 million of costs primarily related to the potential merger with CEQP and our 2015 cost savings initiatives, compared to $1.5 million and $7.3 million of costs for the same periods in 2014, primarily related to the Arrow acquisition.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense - During the three and six months ended June 30, 2015, our depreciation, amortization and accretion expense increased compared to the same periods 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 $3.6 million and $5.4 million during the three and six months ended June 30, 2015 compared to the same periods in 2014. The following table provides a summary of interest and debt expense (in millions):

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014
Credit facilities	$	3.1	$	4.9	$	7.4	$	9.0
Senior notes	28.2		23.4		52.6		46.9
Capital lease interest	—		0.1		—		0.1
Other debt-related costs	2.2		2.0		4.1		3.8
Gross interest and debt expense	33.5		30.4		64.1		59.8
Less: capitalized interest	0.9		1.4		1.6		2.7
Interest and debt expense, net	$	32.6	$	29.0	$	62.5	$	57.1

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Loss on Modification/Extinguishment of Debt - During the three and six months ended June 30, 2015, we recognized a loss on modification/extinguishment of $17.1 million related to the redemption of our 2019 Senior Notes.

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. On April 8, 2015, we utilized approximately $315 million of our Credit Facility to redeem all of our outstanding 2019 Senior Notes. As of June 30, 2015, we had $489.6 million of available capacity under the Credit Facility considering the most restrictive debt covenants in our credit agreement. See Item 1, Financial Statements, Note 6 for a more detailed description of our Credit Facility.

• 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 $688.3 million were used to pay down borrowings under our Credit Facility and for general partnership purposes.

• Preferred Units. During the six months ended June 30, 2015, we did not sell any Preferred Units to the Class A Purchasers. We will issue the remaining $60 million of Preferred Units available for purchase by the Class A Purchasers in conjunction with the Simplification Merger, and we intend 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. Effective May 8, 2015, we suspended the equity distribution program with certain financial institutions under which we were allowed to offer and sell, from time to time through one or more of these financial institutions, common units having an aggregate offering price of up to $300.0 million. Prior to our suspension of this program, we did not issue any common units through these financial institutions.

As of June 30, 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.

As described above, in May 2015, CEQP, the Company and certain of its affiliates entered into a definitive agreement under which we have agreed to merger with a wholly-owned subsidiary of CEQP, with the Company surviving as a wholly-owned subsidiary of CEQP. As further described in Item 1, Financial Statements, Note 14, immediately following the closing of the Simplification Merger, we will repay and retire all borrowings under our existing Credit Facility. This indebtedness will effectively be retired with proceeds received by the Company from the sale of Preferred Units to the Class A Purchasers prior to the closing of the Simplification Merger, borrowings under our amended and restated credit facility (described below), or a combination thereof.

To refinance the existing Credit Facility in conjunction with the Simplification Merger, we intend to enter into an amended and restated senior secured revolving credit facility under which up to $1.5 billion in aggregate principle amount of cash borrowings and letters of credit will be made available to us by a syndicate of lenders. In July 2015, we received final lender commitments for the $1.5 billion revolving credit facility and, subject to customary closing conditions, we expect to close the amended and restated credit agreement contemporaneously with the closing of the Simplification Merger.

Following the acquisition of CEQP's proprietary NGL business and refinancing described above, we will own all of the operating assets within the Crestwood partnerships and will issue all of the debt (including bank loans and senior notes) required to operate those businesses. CEQP, as our publicly-traded parent company following the merger, will issue common units when equity capital is required by our businesses.

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

	Six Months Ended
	June 30,
	2015			2014
Net cash provided by operating activities	$	147.9		$	111.1
Net cash used in investing activities	(102.8		)	(248.5		)
Net cash provided by (used in) financing activities	(49.5		)	152.0

Operating Activities

Our operating cash flows increased approximately $36.8 million during the six months ended June 30, 2015 compared to the same period in 2014, primarily due to lower costs of product/services sold of approximately $314.5 million primarily due to lower prices in our G&P and NGL and Crude Services segments' operations described above, partially offset by lower operating revenues of $279.2 million primarily from our G&P and NGL and Crude Services segments' operations described above.

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 six months ended June 30, 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	$	55.9
Maintenance capital	6.2
Other (1)	15.6
Purchases of property, plant and equipment	77.7
Reimbursements of property, plant and equipment	28.8
Net purchases of property, plant and equipment	$	48.9

(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 six months ended June 30, 2015 and 2014:

Acquisitions. During the six months ended June 30, 2014, we acquired substantially all of the operating assets of Red Rock and LT Enterprises for approximately $12.1 million and $9.0 million, respectively. For a further discussion of this acquisition, see Item 1, Financial Statements, Note 3.

Investments in Unconsolidated Affiliates. During the six months ended June 30, 2015 and 2014, we made capital contributions of approximately $27.8 million and $48.6 million to our unconsolidated affiliates to fund their capital projects. For a further discussion of investment in our unconsolidated affiliates, see Item 1, Financial Statements, Note 5.

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Financing Activities

Significant items impacting our financing activities during the six months ended June 30, 2015 and 2014, included the following:

Equity Transactions

• $3.8 million increase in distributions to non-controlling partners during the six months ended June 30, 2015 compared to the same period in 2014;

• $33.6 million proceeds from the issuance of non-controlling interests during the six months ended June 30, 2014; and

• $293.7 million net proceeds from the issuance of Class A preferred units during the six months ended June 30, 2014  

Debt Transactions

• $688.3 million net proceeds from the issuance of the 2023 Senior Notes during the six months ended June 30, 2015;

• $194.8 million increase in net repayments under our Credit Facility during the six months ended June 30, 2015 compared to the same period in 2014; and

• $363.6 million redemption of our 2019 Senior Notes during the six months ended June 30, 2015

Critical Accounting Estimates

Our critical accounting estimates are consistent with those described in our 2014 Annual Report on Form 10-K. Below is an update of our critical accounting estimates related to goodwill.

Goodwill Impairment

Our goodwill represents the excess of the amount we paid for a business over the fair value of the net identifiable assets acquired. We evaluate goodwill for impairment annually on December 31, and whenever events indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount. This evaluation requires us to compare the fair value of each of our reporting units to its carrying value (including goodwill). If the fair value exceeds the carrying amount, goodwill of the reporting unit is not considered impaired.

We estimate the fair value of our reporting units based on a number of factors, including discount rates, projected cash flows, enterprise value and the potential value we would receive if we sold the reporting unit. Estimating projected cash flows requires us to make certain assumptions as it relates to future operating performance of each of our reporting units (which include assumptions, among others, about estimating future operating margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our customers, such as their future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. If the growth assumptions embodied in the projections prove inaccurate, we could incur a future impairment charge.

As described above, during interim periods we evaluate our reporting units for events and changes that could indicate that it is more likely than not that the fair value of a reporting unit could be less than its carrying amount. Due to the significant, sustained decrease in the market price of our common units from January 1, 2015 to June 30, 2015, we evaluated our reporting units and determined it was more likely than not that the goodwill associated with our Fayetteville (G&P segment) and our Watkins Glen (NGL and Crude Services segment) reporting units was impaired as of June 30, 2015.  As a result of further analysis of the fair value of the goodwill at these reporting units, we recorded an $8.3 million impairment of our goodwill related to our Fayetteville reporting unit, and a $31.9 million impairment of our goodwill related to our Watkins Glen reporting unit during the three months ended June 30, 2015.  The impairment of our Fayetteville goodwill primarily resulted from increasing the discount rate utilized in determining the fair value of the reporting unit from 9% to 10%, considering the continued decrease in commodity prices and its impact on the midstream industry and our customers in the Fayetteville Shale.  The impairment of our Watkins Glen goodwill primarily resulted from increasing the discount rate of the reporting unit from 10.5% to 13.3%, coupled with continued delays and uncertainties in the permitting of our proposed NGL storage facility. 

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We continue to monitor the remaining $64.2 million of goodwill assigned to our Fayetteville reporting unit as of June 30, 2015, and we could experience additional impairments of the remaining goodwill in the future if we experience continued increases in discount rates, or if we receive negative information about market conditions or the intent of our customers related to those operations. We also continue to monitor the remaining $34.3 million of goodwill assigned to our Watkins Glen reporting unit, and we could experience additional impairments of the remaining goodwill in the future if we experience continued increases in discount rates, or if we receive negative information about the timing or our ability to receive the required permitting related to the proposed NGL storage facility.

We acquired a substantial majority of the reporting units in our Storage and Transportation segment and our NGL and Crude Services segment during 2013 concurrent with the Inergy merger, and finalized the purchase price allocations for these acquisitions during 2014, at which time we recorded the assets, liabilities and goodwill of those reporting units at fair value. A summary of the goodwill as of June 30, 2015 related to these reporting units (other than Watkins Glen, which is described above) is as follows (in millions):

Reporting Unit	Goodwill
Northeast Storage and Transportation	$	726.3
COLT	668.3
Bath	29.0
US Salt	12.6

Any level of decrease in the forecasted cash flows of those businesses, or further increases in the discount rates utilized to value those businesses would likely result in the fair value of the reporting unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill is impaired. Although we do not believe it is more likely than not that the fair value of these reporting units could be less than their carrying amounts as of June 30, 2015, we believe that certain of these reporting units have experienced increases in the discount rates utilized in determining their fair value ranging from 0.5% to 1.0% during the first six months of 2015 resulting primarily from the continued commodity price decline since 2014. As a result, we believe that further declines in commodity prices or sustained decreases in the market price of our common units, among other factors, could result in increases in future discount rates, and additional increases of 0.5% to 1.0% in discount rates from the rates utilized at June 30, 2015 could potentially result in a future impairment of the goodwill related to these reporting units. In addition, adverse changes related to the future operating performance of these reporting units could decrease their projected cash flows, which could potentially result in a future impairment of the goodwill related to these reporting units.

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 June 30, 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 July 2015, we are closely monitoring our exposure to Quicksilver to ensure they continue to promptly pay invoices, including those billed to them in August 2015.

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Item 4. Controls and Procedures

Disclosure Controls and Procedures

As of June 30, 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 June 30, 2015.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the six months ended June 30, 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 and our Quarterly Report on Form 10-Q for the period ended March 31, 2015. Below is an update to our Risk Factors.

Sustained decreases in our market capitalization may be an indicator of a potential future impairment of our long-lived tangible and intangible assets including goodwill which could have a material adverse effect on our financial results.

During 2015, we experienced a sustained, significant decline in our unit price which resulted in our market capitalization falling below the recorded value of our consolidated net assets. Under GAAP, we were required to record goodwill impairments of $40.2 million during the three and six months ended June 30, 2015 because changes in circumstances or events (of which one of the several indicators of impairment that was considered jointly is a significant and other than temporary decrease in the our market capitalization) indicated that the carrying values of such assets exceeded their fair value and were not recoverable. A further decline in our market capitalization could result in additional impairments, which could further materially and adversely affect our financial results.

The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including the Company, may be modified by administrative, legislative or judicial interpretation at any time. For example, the Obama administration’s budget proposal for fiscal year 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of the U.S. Congress propose and consider such substantive changes to the existing federal income tax laws that affect the tax treatment of certain publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

On May 5, 2015, the U.S. Treasury Department and the IRS released proposed regulations (the Proposed Regulations) regarding qualifying income under Section 7704(d)(1)(E) of the Code. The Proposed Regulations provide an exclusive list of industry-specific activities that generate qualifying income for the purposes of the Qualifying Income Exception, including the activities that constitute the transportation, storage, processing or marketing of a natural resource. Although the Proposed Regulations adopt a narrow interpretation of the activities that generate qualifying income, the Company does not anticipate any material impact on its ability to satisfy the qualifying income test if the Proposed Regulations were finalized as proposed. However, there can be no assurances that the Proposed Regulations, when adopted as final regulations, will not take a position that is contrary to our interpretation of Section 7704 of the Code. If the Proposed Regulations were to treat any material portion of CEQP’s income as non-Qualifying income, we anticipate being able to treat that income as qualifying income for ten years under special transition rules provided in the Proposed Regulations.

Any modification to the U.S. federal income tax laws and interpretations thereof may be applied retroactively and could make it more difficult or impossible for us to meet the qualifying income exception in order for the Company to be treated as a partnership for federal income tax purposes. We are unable to predict whether any of these changes or any other proposals will ultimately be enacted or adopted. Any such changes could negatively impact the value of an investment in our units and the amount of cash available for distribution to its unitholders.

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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

*

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:	August 6, 2015	By:	/s/ ROBERT T. HALPIN
			Robert T. Halpin
			Senior Vice President and Chief Financial Officer
			(Duly Authorized Officer and Principal Financial Officer)

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