Edgar Filing: Crestwood Equity Partners LP

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Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

CEQP - Q1 15

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q



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



¨	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: 001-34664

Crestwood Equity Partners LP

(Exact name of registrant as specified in its charter)



Delaware		43-1918951
(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.

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

As of May 4, 2015, the registrant had 186,424,580 common units outstanding.

Table of Contents

CRESTWOOD EQUITY PARTNERS LP

INDEX TO FORM 10-Q



	Page
Part I – Financial Information

Item 1. Financial Statements of Crestwood Equity Partners LP (Unaudited):

Consolidated Balance Sheets	3

Consolidated Statements of Operations	4

Consolidated Statements of Comprehensive Income	5

Consolidated Statement of Partners’ Capital	6

Consolidated Statements of Cash Flows	7

Notes to Consolidated Financial Statements	8

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations	36

Item 3. Quantitative and Qualitative Disclosures About Market Risk	47

Item 4. Controls and Procedures	47

Part II – Other Information

Item 1. Legal Proceedings	48

Item 1A. Risk Factors	48

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds	49

Item 3. Defaults Upon Senior Securities	49

Item 4. Mine Safety Disclosures	49

Item 5. Other Information	49

Item 6. Exhibits	50

Signature	51

Table of Contents

PART I - FINANCIAL INFORMATION

Item 1. Financial Statements of Crestwood Equity Partners LP

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED BALANCE SHEETS (in millions, except unit information)

	March 31, 2015		December 31, 2014
	(unaudited)
Assets
Current assets:
Cash	$	67.7	$	8.8
Accounts receivable	289.8		379.6
Inventory	23.9		46.6
Assets from price risk management activities	29.5		79.8
Prepaid expenses and other current assets	27.9		23.3
Total current assets	438.8		538.1

Property, plant and equipment (Note 4)	4,291.7		4,273.9
Less: accumulated depreciation and depletion	414.0		380.1
Property, plant and equipment, net	3,877.7		3,893.8

Intangible assets (Note 4)	1,448.9		1,441.9
Less: accumulated amortization	235.4		210.6
Intangible assets, net	1,213.5		1,231.3

Goodwill	2,491.8		2,491.8
Investment in unconsolidated affiliates (Note 5)	316.6		295.1
Other assets	9.8		11.3
Total assets	$	8,348.2	$	8,461.4

Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	218.7	$	241.2
Accrued expenses and other liabilities (Note 4)	77.8		154.6
Liabilities from price risk management activities	8.6		25.4
Current portion of long-term debt (Note 8)	36.3		3.7
Total current liabilities	341.4		424.9

Long-term debt, less current portion (Note 8)	2,442.8		2,392.8
Other long-term liabilities	48.0		47.2
Deferred income taxes	11.1		12.0
Commitments and contingencies (Note 12)

Partners’ capital (Note 10):
Crestwood Equity Partners LP partners’ capital (187,249,354 and 186,403,667 common units issued and outstanding at March 31, 2015 and December 31, 2014)	758.0		776.2
Interest of non-controlling partners in subsidiaries	4,746.9		4,808.3
Total partners’ capital	5,504.9		5,584.5
Total liabilities and partners’ capital	$	8,348.2	$	8,461.4

See accompanying notes.

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CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, except unit and per unit data) (unaudited)

	Three Months Ended
	March 31,
	2015			2014
Revenues:
Gathering and processing	$	77.3		$	78.6
Storage and transportation	45.7			51.0
NGL and crude services	607.5			841.1
Related party (Note 13)	1.0			0.9
	731.5			971.6
Costs of product/services sold:
Gathering and processing	4.4			7.7
Storage and transportation	3.3			6.8
NGL and crude services	513.7			760.5
Related party (Note 13)	8.3			11.0
	529.7			786.0
Expenses:
Operations and maintenance	50.6			44.1
General and administrative	27.5			27.9
Depreciation, amortization and accretion	74.2			66.3
	152.3			138.3
Other operating income (expense):
Gain (loss) on long-lived assets, net	(1.0		)	0.5
Loss on contingent consideration	—			(2.1		)
Operating income	48.5			45.7
Earnings (loss) from unconsolidated affiliates, net	3.4			(0.1		)
Interest and debt expense, net	(33.6		)	(31.7		)
Other income, net	0.2			0.1
Income before income taxes	18.5			14.0
Provision for income taxes	0.4			0.8
Net income	18.1			13.2
Net (income) loss attributable to non-controlling partners	(9.8		)	6.4
Net income attributable to Crestwood Equity Partners LP	$	8.3		$	19.6

Subordinated unitholders' interest in net income	$	0.2		$	0.5
Common unitholders' interest in net income	$	8.1		$	19.1

Net income per limited partner unit:
Basic	$	0.04		$	0.11
Diluted	$	0.04		$	0.11

Weighted-average limited partners’ units outstanding (in thousands):
Basic	182,801			181,885
Dilutive units	4,388			4,388
Diluted	187,189			186,273

See accompanying notes.

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CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in millions) (unaudited)

	Three Months Ended
	March 31,
	2015		2014
Net income	$	18.1	$	13.2
Change in fair value of Suburban Propane Partners, L.P. units (Note 10)	—		(0.8		)
Comprehensive income	$	18.1	$	12.4

See accompanying notes.

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CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENT OF PARTNERS’ CAPITAL (in millions) (unaudited)

	Crestwood Equity Partners			Non-Controlling Partners			Total Partners’ Capital
Balance at December 31, 2014	$	776.2		$	4,808.3		$	5,584.5
Distributions to partners	(25.8		)	(74.3		)	(100.1		)
Unit-based compensation charges	0.8			5.0			5.8
Taxes paid for unit-based compensation vesting	(1.4		)	(1.7		)	(3.1		)
Other	(0.1		)	(0.2		)	(0.3		)
Net income	8.3			9.8			18.1
Balance at March 31, 2015	$	758.0		$	4,746.9		$	5,504.9

See accompanying notes.

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CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions) (unaudited)

	Three Months Ended
	March 31,
	2015			2014
Operating activities
Net income	$	18.1		$	13.2
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion	74.2			66.3
Amortization of debt-related deferred costs, discounts and premiums	2.1			1.9
Market adjustment on interest rate swaps	(0.3		)	(0.6		)
Unit-based compensation charges	5.8			5.4
(Gain) loss on long-lived assets, net	1.0			(0.5		)
Loss on contingent consideration	—			2.1
(Earnings) loss from unconsolidated affiliates, net	(3.4		)	0.1
Deferred income taxes	(0.9		)	(3.8		)
Other	0.4			0.2
Changes in operating assets and liabilities, net of effects from acquisitions	59.6			(2.4		)
Net cash provided by operating activities	156.6			81.9

Investing activities
Acquisitions, net of cash acquired (Note 3)	—			(12.1		)
Purchases of property, plant and equipment	(47.4		)	(82.4		)
Investment in unconsolidated affiliates	(18.1		)	(19.8		)
Proceeds from sale of assets	0.5			—
Other	(0.2		)	—
Net cash used in investing activities	(65.2		)	(114.3		)

Financing activities
Proceeds from the issuance of long-term debt	1,252.7			496.4
Principal payments on long-term debt	(1,169.9		)	(372.6		)
Payments on capital leases	(0.7		)	(1.1		)
Payments for debt-related deferred costs	(11.1		)	—
Distributions to partners	(25.8		)	(25.6		)
Distributions paid to non-controlling partners	(74.3		)	(74.1		)
Net proceeds from issuance of preferred equity of subsidiary	—			12.3
Taxes paid for unit-based compensation vesting	(3.1		)	(0.4		)
Other	(0.3		)	—
Net cash provided by (used in) financing activities	(32.5		)	34.9

Net change in cash	58.9			2.5
Cash at beginning of period	8.8			5.2
Cash at end of period	$	67.7		$	7.7

Supplemental schedule of noncash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(9.1	)	$	(3.4	)

See accompanying notes.

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 1 – Business Description

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

Our general partner, Crestwood Equity GP LLC, owns our non-economic general partnership interest. Our general partner is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve). As of March 31, 2015, Crestwood Holdings also owns approximately 11% of the Crestwood Midstream Partners LP (Crestwood Midstream or CMLP) common units. As of March 31, 2015, First Reserve owns approximately 26% of our common units, and 4,387,889 of our subordinated units.

We indirectly own Crestwood Midstream GP LLC, the non-economic general partner of Crestwood Midstream and, consequently, manage and control Crestwood Midstream. As of March 31, 2015, we also own approximately 4% of Crestwood Midstream’s limited partnership interests and 100% of its incentive distribution rights (IDRs), which entitle us to receive 50% of all distributions paid by Crestwood Midstream in excess of its initial quarterly distribution of $0.37 per common unit.

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 NGL and crude oil gathering, storage, marketing and transportation services to producers, refiners, marketers and other customers. This segment primarily includes our NGL marketing, supply and logistics business (including our West Coast processing and fractionation operations, Seymour NGL storage facility, and our rail-to-truck terminals and a fleet of transportation assets) and 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.

We own and operate a proprietary NGL supply and logistics business (including our West Coast processing and fractionation facility, Seymour storage facility, terminals and transportation fleet). All of our other consolidated assets are owned by or through Crestwood Midstream.

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

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Unless otherwise indicated, references in this report to “we,” “us,” “our,” “ours,” “our company,” the “partnership,” the “Company,” “CEQP,” “Crestwood,” and similar terms refer to either Crestwood Equity Partners LP itself or Crestwood Equity Partners LP and its consolidated subsidiaries, as the context requires.

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

Basis of Presentation

The financial information as of March 31, 2015, and for the three months ended March 31, 2015 and 2014, is unaudited. The consolidated balance sheet as of December 31, 2014, was derived from the audited balance sheet filed in our 2014 Annual Report on Form 10-K. Our consolidated financial statements are prepared in accordance with accounting principles generally accepted in the United States of America (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of all intercompany accounts and transactions. In management’s opinion, all necessary adjustments to fairly present our results of operations, financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and recurring nature. Certain information and footnote disclosures normally included in annual consolidated financial statements prepared in accordance with GAAP have been omitted pursuant to the rules and regulations of the Securities and Exchange Commission (SEC).

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

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

Significant Accounting Policies

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

New Accounting Pronouncements Issued But Not Yet Adopted

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

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance. We expect to adopt the provisions of this standard effective January 1, 2017 and are currently evaluating the impact that this standard will have on our consolidated financial statements. In April 2015, the FASB proposed deferring the effective date of this standard by one year.

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

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

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 3 – Acquisitions

2014 Acquisitions

Crude Transportation Acquisition (Bakken)

Red Rock. On March 21, 2014, Crestwood Midstream purchased substantially all of the trucking operations of Red Rock Transportation Inc. (Red Rock) for approximately $13.8 million, comprised of $12.1 million paid at closing plus deferred payments of $1.8 million. These operations are located in Watford City, North Dakota and provide crude oil and produced water hauling services to the oilfields of western North Dakota and eastern Montana. The acquired assets include a fleet of approximately 56 trailer tanks, 22 double bottom body tanks and 44 tractors with 28,000 barrels per day of transportation capacity. In the first quarter of 2014, we finalized the purchase price and allocated approximately $10.6 million of the purchase price to property, plant and equipment and intangible assets and approximately $3.2 million to goodwill. Goodwill recognized relates primarily to anticipated operating synergies between the assets acquired and our existing assets. These assets are included in our NGL and crude services segment.

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

Note 4 – Certain Balance Sheet Information

Property, Plant and Equipment

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



	March 31, 2015		December 31, 2014
Gathering systems and pipelines	$	1,417.8	$	1,410.9
Facilities and equipment	1,638.0		1,648.3
Buildings, land, rights-of-way, storage contracts and easements	843.5		841.5
Vehicles	46.6		45.2
Construction in process	174.1		156.5
Base gas	37.5		37.5
Salt deposits	120.5		120.5
Office furniture and fixtures	13.7		13.5
	4,291.7		4,273.9
Less: accumulated depreciation and depletion	414.0		380.1
Total property, plant and equipment, net	$	3,877.7	$	3,893.8

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 $5.5 million and $5.3 million included in property, plant and equipment, net at March 31, 2015 and December 31, 2014.

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Intangible Assets

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



	March 31, 2015		December 31, 2014
Customer accounts	$	583.7	$	583.7
Covenants not to compete	9.6		9.6
Gas gathering, compression and processing contracts	726.1		730.2
Acquired storage contracts	29.0		29.0
Trademarks	32.2		32.2
Deferred financing costs	68.3		57.2
	1,448.9		1,441.9
Less: accumulated amortization	235.4		210.6
Total intangible assets, net	$	1,213.5	$	1,231.3

Accrued Expenses and Other Liabilities

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



	March 31, 2015		December 31, 2014
Accrued expenses	$	36.3	$	52.5
Accrued property taxes	4.5		2.2
Accrued product purchases payable	0.4		0.7
Tax payable	—		1.6
Interest payable	14.5		23.5
Accrued additions to property, plant and equipment	9.1		20.0
Commitments and contingent liabilities (Note 12)	—		40.0
Capital leases	1.7		1.9
Deferred revenue	11.3		12.2
Total accrued expenses and other liabilities	$	77.8	$	154.6

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 5 - Investments in Unconsolidated Affiliates

Net Investment and Earnings (Loss)

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



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

(1)

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

(2)

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


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


(4)	Excludes non-controlling interests related to our investment in Jackalope. See Note 10 for a further discussion of our non-controlling interest related to our investment in Jackalope.

Distributions and Contributions

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

Tres Holdings. Tres Holdings is required, within 30 days following the end of each quarter, to make quarterly distributions of its available cash (as defined in its limited liability company agreement) to its members based on their respective ownership percentage. In April 2015, we received a cash distribution of approximately $2.1 million from Tres Holdings. During the three months ended March 31, 2015, we contributed approximately $5.9 million in Tres Holdings.

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

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 6 – Risk Management

We are exposed to certain market risks related to our ongoing business operations. These risks include exposure to changing commodity prices as well as fluctuations in interest rates. We utilize derivative instruments to manage our exposure to fluctuations in commodity prices, which is discussed below. We also periodically utilize derivative instruments to manage our exposure to fluctuations in interest rates, which is discussed in Note 8. Additional information related to our derivatives is discussed in Note 7.

Commodity Derivative Instruments and Price Risk Management

Risk Management Activities

We sell NGLs to energy related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of NGLs, heating oil and crude oil. We will periodically enter into offsetting positions to economically hedge against the exposure our customer contracts create. Certain of these contracts and positions are derivative instruments. We do not designate any of our commodity-based derivatives as hedging instruments for accounting purposes. Our commodity-based derivatives are reflected at fair value in the consolidated balance sheets, and changes in the fair value of these derivatives that impact the consolidated statements of operations are reflected in costs of product/services sold. During the three months ended March 31, 2015 and 2014, the impact to the statement of operations related to our commodity-based derivatives reflected in costs of product/services sold was a loss of $2.9 million and $0.5 million. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. This balance in the contractual portfolio significantly reduces the volatility in costs of product/services sold related to these instruments.

Commodity Price and Credit Risk

Notional Amounts and Terms

The notional amounts and terms of our derivative financial instruments include the following at March 31, 2015 and December 31, 2014 (in millions):



	March 31, 2015		December 31, 2014
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	5.9	6.8	6.8	8.4
Natural gas (MMBTU’s)	—	—	0.2	0.1

Notional amounts reflect the volume of transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not reflect our monetary exposure to market or credit risks.

All contracts subject to price risk had a maturity of 36 months or less; however, 94% of the contracts expire within 12 months.

Credit Risk

Inherent in our contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing credit risk and have established control procedures, which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of March 31, 2015 and December 31, 2014 were energy marketers and propane retailers, resellers and dealers.

Certain of our derivative instruments have credit limits that require us to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as our established credit limit with the respective counterparty. If our credit rating were to change, the counterparties could require us to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as well as the requirements of the individual counterparty. The aggregate fair value of all commodity derivative instruments with

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

credit-risk-related contingent features that were in a liability position at March 31, 2015 was $6.3 million, for which we posted no collateral and at December 31, 2014 was $5.2 million for which we posted $1.8 million of collateral in the normal course of business. In addition, at March 31, 2015 and December 31, 2014, we had a New York Mercantile Exchange (NYMEX) related net derivative liability position of $21.3 million and $36.9 million, for which we posted $28.9 million and $41.9 million of cash collateral in the normal course of business. At March 31, 2015 and December 31, 2014, we also received collateral of $11.8 million and $33.6 million in the normal course of business. All collateral amounts have been netted against the asset or liability with the respective counterparty and is reflected in our consolidated balance sheets as assets and liabilities from price risk management activities.

Note 7 – Fair Value Measurements

The accounting standard for fair value measurement establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

•

Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis. Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and US government treasury securities.

•

Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models or other valuation methodologies. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace. Instruments in this category include non-exchange-traded derivatives such as over the counter (OTC) forwards, options and physical exchanges.


•	Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.

Cash and Cash Equivalents, Accounts Receivable and Accounts Payable

As of March 31, 2015 and December 31, 2014, the carrying amounts of cash, accounts receivable and accounts payable represent fair value based on the short-term nature of these instruments.

Credit Facilities

The fair value of the amounts outstanding under our credit facilities approximates their carrying amounts as of March 31, 2015 and December 31, 2014 due primarily to the variable nature of the interest rates of the instruments, which is considered a Level 2 fair value measurement.

Senior Notes

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):

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)



	March 31, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
CEQP Senior Notes	$	10.6	$	10.6	$	11.4	$	11.6
Crestwood Midstream 2019 Senior Notes	$	350.9	$	363.6	$	351.0	$	360.5
Crestwood Midstream 2020 Senior Notes	$	503.8	$	500.3	$	504.0	$	481.6
Crestwood Midstream 2022 Senior Notes	$	600.0	$	607.5	$	600.0	$	568.5
Crestwood Midstream 2023 Senior Notes	$	700.0	$	710.5	$	—	$	—

Financial Assets and Liabilities

As of March 31, 2015 and December 31, 2014, we held certain assets and liabilities that are required to be measured at fair value on a recurring basis, which include our derivative instruments related to heating oil, crude oil, NGLs and interest rates. Our derivative instruments consist of forwards, swaps, futures, physical exchanges and options.

Certain of our derivative instruments are traded on the NYMEX. These instruments have been categorized as Level 1.

Our derivative instruments also include OTC contracts, which are not traded on a public exchange. The fair values of these derivative instruments are determined based on inputs that are readily available in public markets or can be derived from information available in publicly quoted markets. These instruments have been categorized as Level 2.

Our OTC options are valued based on the Black Scholes option pricing model that considers time value and volatility of the underlying commodity. The inputs utilized in the model are based on publicly available information as well as broker quotes. These options have been categorized as Level 2.

Our financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following tables set forth by level within the fair value hierarchy, our assets and liabilities that were accounted for at fair value on a recurring basis at March 31, 2015 and December 31, 2014 (in millions):



	March 31, 2015
	Fair Value of Derivatives
	Level 1		Level 2		Level 3		Total		Netting Agreements⁽¹⁾			Total
Assets
Assets from price risk management	$	—	$	41.1	$	—	$	41.1	$	(11.6	)	$	29.5
Suburban Propane Partners, L.P. units⁽²⁾	6.1		—		—		6.1		—			6.1
Total assets at fair value	$	6.1	$	41.1	$	—	$	47.2	$	(11.6	)	$	35.6

Liabilities
Liabilities from price risk management	$	0.2	$	35.2	$	—	$	35.4	$	(26.8	)	$	8.6
Interest rate swaps⁽³⁾	—		1.3		—		1.3		—			1.3
Total liabilities at fair value	$	0.2	$	36.5	$	—	$	36.7	$	(26.8	)	$	9.9

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)



	December 31, 2014
	Fair Value of Derivatives
	Level 1		Level 2		Level 3		Total		Netting Agreements⁽¹⁾			Total
Assets
Assets from price risk management	$	0.5	$	146.7	$	—	$	147.2	$	(67.4	)	$	79.8
Suburban Propane Partners, L.P. units⁽²⁾	6.1		—		—		6.1		—			6.1
Total assets at fair value	$	6.6	$	146.7	$	—	$	153.3	$	(67.4	)	$	85.9

Liabilities
Liabilities from price risk management	$	1.6	$	99.2	$	—	$	100.8	$	(75.4	)	$	25.4
Interest rate swaps⁽³⁾	—		1.6		—		1.6		—			1.6
Total liabilities at fair value	$	1.6	$	100.8	$	—	$	102.4	$	(75.4	)	$	27.0


(1)	Amounts represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions as well as cash collateral held or placed with the same counterparties.


(2)	Our Suburban Propane Partners, L.P. units are included in prepaid expenses and other current assets on our consolidated balance sheets.


(3)	Interest rate swaps are included in other long-term liabilities on our consolidated balance sheets.

Note 8 – Long-Term Debt

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



	March 31, 2015		December 31, 2014
CEQP Credit Facility	$	308.0	$	369.0
CEQP Senior Notes	10.6		11.4
Crestwood Midstream Revolver	—		555.0
Crestwood Midstream 2019 Senior Notes	350.0		350.0
Premium on Crestwood Midstream 2019 Senior Notes	0.9		1.0
Crestwood Midstream 2020 Senior Notes	500.0		500.0
Fair value adjustment of Crestwood Midstream 2020 Senior Notes	3.8		4.0
Crestwood Midstream 2022 Senior Notes	600.0		600.0
Crestwood Midstream 2023 Senior Notes	700.0		—
Other	5.8		6.1
Total debt	2,479.1		2,396.5
Less: current portion	36.3		3.7
Total long-term debt	$	2,442.8	$	2,392.8

We and our subsidiaries do not provide credit support or guarantee any amounts outstanding under the credit facility or notes of Crestwood Midstream. Crestwood Midstream and its subsidiaries do not provide credit support or guarantee any amounts outstanding under our credit facility or senior notes.

CEQP Credit Facility

Description of Credit Facility. We utilize a secured credit facility (the CEQP Credit Facility) with an aggregate revolving loan capacity of $495 million, to fund working capital requirements, capital expenditures and acquisitions and for general partnership purposes. All borrowings under the CEQP Credit Facility, which expires in July 2016, are generally secured by substantially all of our assets and the equity interests in all of our wholly owned subsidiaries.

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(unaudited)

At March 31, 2015, we had $134.3 million of available capacity under the revolving credit facility (excluding standby letters of credit) considering our most restrictive debt covenants under the facility. At March 31, 2015 and December 31, 2014, our outstanding standby letters of credit were $52.7 million and $56.7 million. The interest rates on the CEQP Credit Facility are based on the prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 2.43% and 4.50% at March 31, 2015. The weighted-average interest rate as of March 31, 2015 and December 31, 2014 was 2.43% and 3.02%.

Restrictive Covenants. The CEQP Credit Facility contains the following financial covenants:


•	the ratio of our total funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement) was amended in September 2014 to increase the ratio to (i) 5.25 to 1.0 for the quarter ended March 31, 2015, (ii) 5.00 to 1.0 for the quarter ended June 30, 2015, and (iii) 4.75 to 1.0 for the quarter ended September 30, 2015 and all subsequent quarters.


•	the ratio of our consolidated EBITDA to consolidated interest expense (as defined in the credit agreement), for the four quarters then most recently ended, must not be less than 2.50 to 1.0.

At March 31, 2015, the total funded debt to consolidated EBITDA was approximately 3.25 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 7.91 to 1.0.

At March 31, 2015, we were in compliance with the debt covenants in the CEQP Credit Facility. For additional information regarding our debt covenants, see our 2014 Annual Report on Form 10-K as filed with the SEC.

Interest Rate Swaps. We enter into interest rate swaps to reduce our exposure to variable interest payments due under the CEQP Credit Facility. These swap agreements require us to make quarterly payments to the counterparty on an aggregate notional amount based on fixed rates. In exchange, the counterparty is required to make quarterly floating interest rate payments on the same date to us based on the three-month LIBOR applied to the same aggregate notional amount. In February 2015, five of our interest rate swaps matured, with an aggregate notional amount of $175.0 million and fixed rates ranging from 0.84% to 2.35%. As of March 31, 2015, we had one swap agreement, with a notional amount of $50 million and a fixed rate of 2.52%. This agreement matures in 2016. During the three months ended March 31, 2015, we recorded a gain of approximately $0.3 million associated with these interest rate swaps, which is reflected as a reduction of our interest and debt expense, net on our consolidated statements of operations.

CEQP Senior Notes

At March 31, 2015, we had $10.6 million in outstanding senior notes, the majority of which mature on October 1, 2018 and have a coupon rate of 7%. The outstanding senior notes do not contain any financial covenants.

Crestwood Midstream Revolver

Description of Facility. Crestwood Midstream has a five-year $1.0 billion senior secured revolving credit facility (the Crestwood Midstream Revolver), which expires in October 2018 and is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The Crestwood Midstream Revolver 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 Crestwood Midstream Revolver is secured by substantially all of the equity interests and assets of Crestwood Midstream’s subsidiaries, except for Crestwood Niobrara LLC (Crestwood Niobrara), PRBIC and Tres Holdings and their respective subsidiaries.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Restrictive Covenants. Crestwood Midstream is required under its credit agreement to maintain a net debt to consolidated EBITDA ratio (as defined in its 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 Crestwood Midstream) and a consolidated EBITDA to consolidated interest expense ratio (as defined in its credit agreement) of not less than 2.50 to 1.0. As a result of Crestwood Midstream's election to increase the permitted net debt to consolidated EBITDA ratio in conjunction with its 50.01% acquisition of Tres Palacios Gas Storage Company LLC, the net debt to consolidated EBITDA ratio required by its credit agreement is 5.50 for a 270-day period commencing December 3, 2014. At March 31, 2015, the net debt to consolidated EBITDA was approximately 4.58 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 4.15 to 1.0.

Crestwood Midstream Senior Notes

As of March 31, 2015, Crestwood Midstream had four series of senior unsecured notes outstanding, including (i) $350 million in aggregate principal amount of 7.75% Senior Notes due 2019 (the 2019 Senior Notes), (ii) $500 million in aggregate principal amount of 6.0% Senior Notes due 2020 (the 2020 Senior Notes), (iii) $600 million in aggregate principal amount of 6.125% Senior Notes due 2022 (the 2022 Senior Notes), and (iv) $700 million in aggregate principal amount of 6.25% Senior Notes due 2023 (the 2023 Senior Notes and together with the 2019 Senior Notes, 2020 Senior Notes and 2022 Senior Notes, its Senior Notes). Crestwood Midstream's Senior Notes are guaranteed on a senior unsecured basis by all of its domestic restricted subsidiaries, subject to certain exceptions.

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

On April 8, 2015, Crestwood Midstream redeemed its 2019 Senior Notes for approximately $364.1 million, including accrued interest of $0.5 million and a call premium of $13.6 million. Crestwood Midstream utilized approximately $315 million of its credit facility to redeem all of its outstanding 2019 Senior Notes.

At March 31, 2015, Crestwood Midstream was in compliance with all of its debt covenants applicable to the Crestwood Midstream Revolver and its Senior Notes. For additional information regarding the Crestwood Midstream debt covenants, see our 2014 Annual Report on Form 10-K filed with the SEC.

Other

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

Note 9 - Earnings Per Limited Partner Unit

Our net income (loss) attributable to Crestwood Equity Partners is allocated to the subordinated and limited partner unitholders based on their ownership percentage. We calculate basic net income per limited partner unit using the two-class method. Diluted net income per limited partner unit is computed by dividing net income attributable to the limited partners by the weighted-average number of units outstanding and the effect of dilutive units outstanding. There were no units excluded from our dilutive earnings per share as we did not have any anti-dilutive units for the three months ended March 31, 2015 and 2014.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 10 – Partners’ Capital

Distributions

Distributions to Partners

A summary of our limited partner quarterly cash distributions for the three months ended March 31, 2015 and 2014 is presented below:



Record Date	Payment Date	Per Unit Rate		Cash Distributions (in millions)
2015
February 6, 2015	February 13, 2015	$	0.1375	$	25.8
2014
February 7, 2014	February 14, 2014	$	0.1375	$	25.6

On April 23, 2015, we declared a distribution of $0.1375 per limited partner unit to be paid on May 15, 2015, to unitholders of record on May 8, 2015 with respect to the first quarter of 2015.

Non-Controlling Partners

Crestwood Midstream Class A Preferred Units

On June 17, 2014, Crestwood Midstream 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, Crestwood Midstream has agreed to sell to the Class A Purchasers and the Class A Purchasers have agreed to purchase from Crestwood Midstream up to $500 million of Preferred Units at a fixed price of $25.10 per unit on or before September 30, 2015. During the three months ended March 31, 2015 and through the date of this filing, we did not sell any Preferred Units to the Class A Purchasers under these agreements. For additional information on Crestwood Midstream's Class A Preferred Units, see our 2014 Annual Report on Form 10-K filed with the SEC.

Crestwood Niobrara Preferred Interest

Crestwood Niobrara issued a preferred interest to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE) in conjunction with the acquisition of its investment in Jackalope, which is reflected as non-controlling interest in our consolidated financial statements. During the three months ended March 31, 2014, GE made capital contributions of $12.3 million to Crestwood Niobrara in exchange for an equivalent number of preferred units.

Net Income (Loss) Attributable to Non-Controlling Partners

The components of net income (loss) attributable to non-controlling partners on our consolidated statements of operations for the three months ended March 31, 2015 and 2014, are as follows (in millions):



	Three Months Ended
	March 31,
	2015			2014
Crestwood Midstream limited partner interests	$	(5.0	)	$	(9.5	)
Crestwood Midstream Class A preferred units	9.2			—
Crestwood Niobrara preferred interests	5.6			3.1
Net income (loss) attributable to non-controlling partners	$	9.8		$	(6.4	)

Distributions to Non-Controlling Partners

Crestwood Midstream Limited Partners. The Crestwood Midstream partnership agreement requires them to distribute, within 45 days after the end of each quarter, all available cash (as defined in its partnership agreement) to unitholders of record on the

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(unaudited)

applicable record date. We are not entitled to distributions on our non-economic general partner interest in Crestwood Midstream. Crestwood Midstream paid cash distributions to its limited partners (excluding distributions to its general partner and distributions on the limited partner units owned by us) of $74.3 million and $74.1 million during the three months ended March 31, 2015 and 2014.

Crestwood Midstream Class A Preferred Unitholders. Crestwood Midstream's partnership agreement requires it to make quarterly distributions to its Class A Preferred Unit holders. The holders of the 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 the Preferred Units can be made in additional Preferred Units, cash, or a combination thereof, at Crestwood Midstream's election. If Crestwood Midstream elects 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. Crestwood Midstream accrues the fair value of such distribution at the end of the quarterly period and adjusts the fair value of the distribution on the date the additional Preferred Units are distributed. Distributions on the 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 Crestwood Midstream's common units and (ii) its available cash (as defined in its partnership agreement) is insufficient to make a cash distribution to its Preferred Unit holders. If Crestwood Midstream fails to pay the full amount payable to its 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) Crestwood Midstream will not be permitted to declare or make any distributions to its 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 Crestwood Midstream fails to pay in full any Class A Preferred Distribution (as defined in its partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

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

Crestwood Niobrara Preferred Unitholders. During the three months ended March 31, 2015 and 2014, Crestwood Niobrara issued 3,680,570 and 2,210,294 preferred units to GE in lieu of paying a cash distribution. Beginning in the first quarter of 2015, Crestwood Niobrara no longer had the option to pay distributions to GE by issuing additional preferred units in lieu of paying a cash distribution. On April 30, 2015, Crestwood Niobrara paid a distribution of $3.8 million to GE for the quarter ended March 31, 2015.

Other Partners’ Capital Transactions

Equity Distribution Agreement

Crestwood Midstream entered into an equity distribution program with certain financial institutions (each, a Manager) under which it is allowed to offer and sell, from time to time through one or more of the Managers, common units having an aggregate offering price of up to $300.0 million. Crestwood Midstream will pay the Managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under this at-the-market program. Crestwood Midstream did not issue any common units under this equity distribution program as of March 31, 2015 and through the date of this filing.

Other

In August 2012, Legacy Inergy contributed its retail propane operations to Suburban Propane Partners, L.P. (SPH). In connection with this contribution, Legacy Inergy retained approximately 142,000 SPH units which we record at fair value each quarter. The change in fair value is reflected in the consolidated statements of partners’ capital and the consolidated statements of comprehensive income.

Note 11 - Equity Plans

Long-term incentive awards are granted under the Crestwood Equity Partners LP Long Term Incentive Plan (Crestwood LTIP) and the Crestwood Midstream Partners LP Long Term Incentive Plan (Crestwood Midstream LTIP) in order to align the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

economic interests of key employees and directors with those of CEQP and Crestwood Midstream's common unitholders and to provide an incentive for continuous employment. Long-term incentive compensation consist of grants of restricted and phantom units which vest based upon continued service.

Crestwood LTIP

The following table summarizes information regarding restricted and phantom unit activity during the three months ended March 31, 2015:



	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2015	1,315,880		$	13.21
Vested - restricted units	(743,252	)	$	12.96
Granted - restricted units	1,157,174		$	6.80
Granted - phantom units	362,872		$	6.72
Forfeited⁽¹⁾	(69,122	)	$	10.52
Unvested - March 31, 2015	2,023,552		$	8.56

(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, 36,542 restricted units were forfeited during the three months ended March 31, 2015.

As of March 31, 2015 and December 31, 2014, we had total unamortized compensation expense of approximately $14.1 million and $8.1 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 $2.8 million and $2.5 million (including $2.2 million and $1.7 million that was allocated to Crestwood Midstream) under the Crestwood LTIP during the three months ended March 31, 2015 and 2014, which is included in general and administrative expenses on our consolidated statements of operations. We granted restricted and phantom units with a grant date fair value of approximately $7.9 million and $2.4 million during the three months ended March 31, 2015. As of March 31, 2015, we had 12,713,653 units available for issuance under the Crestwood LTIP.

Crestwood Restricted Units. Under the Crestwood LTIP, participants who have been granted restricted units may elect to have us withhold common units to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-vested common units. Any such common units withheld are returned to the 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 March 31, 2015 and 2014, we withheld 242,365 and 47,800 common units to satisfy employee tax withholding obligations.

Crestwood 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 us granted pursuant to the Crestwood LTIP and a phantom unit award agreement (the Crestwood Equity Phantom Unit Agreement). The Crestwood Equity 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 Crestwood Equity Phantom Unit Agreement). In addition, the Crestwood Equity 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.

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(unaudited)

Crestwood Midstream LTIP

The following table summarizes information regarding restricted and phantom unit activity during the three months ended March 31, 2015:



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

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

As of March 31, 2015 and December 31, 2014, we had total unamortized compensation expense of approximately $15.7 million and $9.5 million related to restricted and phantom units issued under the Crestwood Midstream LTIP, 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 the general partner of CEQP, which vest over one year. Crestwood Midstream recognized compensation expense of approximately $3.0 million and $2.9 million during the three months ended March 31, 2015 and 2014, which is included in general and administrative expenses on our consolidated statements of operations. We granted restricted and phantom units with a grant date fair value of approximately $8.2 million and $2.6 million during the three months ended March 31, 2015. As of March 31, 2015, we had 17,199,153 units available for issuance under the Crestwood Midstream LTIP.

Crestwood Midstream Restricted Units. Under the Crestwood Midstream 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 Midstream LTIP on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When such common units are withheld, Crestwood Midstream is 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 March 31, 2015 and 2014, Crestwood Midstream withheld 134,591 and 7,456 common units to satisfy employee tax withholding obligations.

Crestwood Midstream Phantom Units. The Crestwood Midstream LTIP currently permits, and Crestwood Midstream's 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 Midstream 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.

Crestwood Midstream Employee Unit Purchase Plan

Crestwood Midstream has an employee unit purchase plan under which employees of the general partner may purchase Crestwood Midstream's common units through payroll deductions up to a maximum of 10% of the employees' eligible compensation. Under the plan, Crestwood Midstream may purchase its common units on the open market for the benefit of participating employees based on their payroll deductions. In addition, Crestwood Midstream may contribute an additional 10% of participating employees' payroll deductions to purchase additional Crestwood Midstream common units for participating employees. Unless increased by the board of directors of Crestwood Midstream's general partner, the maximum number of units that may be purchased under the plan is 200,000. During the three months ended March 31, 2015, there were 2,011 common

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

units purchased through the employee unit purchase plan related to the fourth quarter of 2014. In April 2015, there were 3,841 common units purchased related to the first quarter of 2015.

Note 12 – Commitments and Contingencies

Legal Proceedings

Property Taxes. In conjunction with the sale of our interest in Tres Palacios to Tres Holdings, we retained the liability of Tres Palacios for certain tax matters, including the property taxes litigation in which we challenged the Matagorda County Appraisal District that the assessed value was over the market value for the tax years 2012 and 2013. For those years, we believe the total difference in taxes between the assessed value and the market value is approximately $12 million. These lawsuits remain pending and the outcome is not yet determined. In January 2015, we settled the lawsuit related to the 2011 tax year with the Matagorda County Appraisal District.

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

In March 2014, the plaintiffs filed their fourth amended motion to name Arrow and numerous other energy companies as additional defendants in the class action lawsuit. The plaintiffs have named at least 53 defendants purportedly involved in the events leading up to the derailment, including the producers and sellers of the crude being transported, the midstream companies that transported the crude from the well head to the rail system, the manufacturers of the rail cars used to transport the crude, the railroad companies involved, the insurers of these companies, and the Canadian Attorney General. The plaintiffs allege, among other things, that Arrow (i) was a producer of the crude oil being transported on the derailed train, (ii) was negligent in failing to properly classify the crude delivered to the trucks that hauled the crude to the rail loading terminal, and (iii) owed a duty to the petitioners to ensure the safe transportation of the crude being transported. The motion to authorize the class action and motions in opposition were heard by the Court in June 2014. We anticipate a ruling from the Judge on the Petitioners' motion to authorize the class action in the first half of 2015.

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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

General. We are periodically involved in litigation proceedings. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, then we accrue the estimated amount. The results of litigation proceedings cannot be predicted with certainty. We could incur judgments, enter into settlements or revise our expectations regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations or cash flows in the period in which the amounts are paid and/or accrued. As of March 31, 2015 and December 31, 2014, we had $1.0 million accrued for our outstanding legal matters. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures for which we can estimate will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.

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

Regulatory Compliance

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

Environmental Compliance

During 2014, we experienced three releases totaling approximately 28,000 barrels of produced water on our Arrow water gathering system located on the Fort Berthold Indian Reservation in North Dakota. We immediately notified the National Response Center, the Three Affiliated Tribes and numerous other regulatory authorities, and thereafter contained and cleaned up the releases completely and placed the impacted segments of these water lines back into service. We will continue our remediation efforts to ensure the impacted lands are restored to their prior state. We believe these releases are insurable events under our policies, and we have notified our carriers of these events. We have not recorded an insurance receivable as of March 31, 2015. In May 2015, we experienced a release of up to 8,000 barrels of produced water on our Arrow water gathering system, and immediately notified numerous regulatory authorities and other third parties. We are currently evaluating the extent of the release and its impact on the related lands, and because this matter is in the early stages of investigation, we are unable to estimate a reasonably possible loss or range of loss.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. We are subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At March 31, 2015 and December 31, 2014, our accrual of approximately $0.3 million and $1.1 million was primarily related to the Arrow water releases described above, which is based on our undiscounted estimate of amounts we will spend on compliance with environmental and other regulations. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures (including the Arrow water releases described above) could range from approximately $0.3 million to $0.8 million.

Self-Insurance

We utilize third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers' compensation claims and general, product, vehicle and environmental liability. At March 31, 2015 and December 31, 2014, our self-insurance reserves were $12.8 million and $14.6 million. We estimate that $9.7 million of this balance will be paid subsequent to December 31, 2015. As such, $9.7 million has been classified in other long-term liabilities on our consolidated balance sheets. For more information, see our 2014 Annual Report on Form 10-K filed with the SEC.

Contingent Consideration - Antero

In connection with the acquisition of Antero Resources Appalachian Corporation (Antero), we agreed to pay Antero conditional consideration in the form of potential additional cash payments of up to $40.0 million, depending on the achievement of certain defined average annual production levels achieved during 2012, 2013 and 2014. In February 2015, we paid Antero $40.0 million to settle the liability under the earn-out provision. This amount is reflected in changes in operating assets and liabilities, net of effects from acquisitions under operating activities in our consolidated statements of cash flows.

Note 13 – Related Party Transactions

We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including gas gathering and processing services under long-term contracts, product purchases and various operating agreements.

The following table shows revenues, costs of goods sold and reimbursements of general and administrative expenses from our affiliates for the three months ended March 31, 2015 and 2014 (in millions):



	Three Months Ended
	March 31,
	2015		2014
Gathering and processing revenues	$	1.0	$	0.9
Gathering and processing costs of product/services sold⁽¹⁾	$	8.3	$	11.0
Reimbursement of general and administrative expenses	$	0.1	$	0.1
Reimbursement of operations and maintenance expenses	$	0.9	$	—


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

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)



	March 31, 2015		December 31, 2014
Accounts receivable	$	1.2	$	0.6
Accounts payable	$	5.2	$	5.6

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

Note 14 – 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 transportation services to producers, utilities and other customers. Our NGL and crude services operations provide NGL processing and fractionation, NGLs and crude oil gathering, storage, marketing and transportation, supply and logistics 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 our reportable segments. We assess the performance of our operating segments based on EBITDA, which represents operating income plus depreciation, amortization and accretion expense.

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



	Three Months Ended
	March 31,
	2015		2014
Net income	$	18.1	$	13.2
Add:
Interest and debt expense, net	33.6		31.7
Provision for income taxes	0.4		0.8
Depreciation, amortization and accretion	74.2		66.3
EBITDA	$	126.3	$	112.0

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

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



	Three Months Ended March 31, 2015
	Gathering and Processing			Storage and Transportation			NGL and Crude Services		Intersegment			Corporate			Total
Revenues	$	78.5		$	45.7		$	607.5	$	(0.2	)	$	—		$	731.5
Costs of product/services sold	12.7			3.3			513.9		(0.2		)	—			529.7
Operations and maintenance expense	14.9			4.3			31.4		—			—			50.6
General and administrative expense	—			—			—		—			27.5			27.5
Loss on long-lived assets	(0.3		)	(0.7		)	—		—			—			(1.0		)
Earnings from unconsolidated affiliates, net	2.5			0.9			—		—			—			3.4
Other income, net	—			—			—					0.2			0.2
EBITDA	$	53.1		$	38.3		$	62.2	$	—		$	(27.3	)	$	126.3
Goodwill	$	338.3		$	726.3		$	1,427.2	$	—		$	—		$	2,491.8
Total assets	$	2,617.1		$	1,976.1		$	3,570.3	$	—		$	184.7		$	8,348.2
Purchases of property, plant and equipment	$	11.4		$	2.7		$	33.1	$	—		$	0.2		$	47.4



	Three Months Ended March 31, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Intersegment		Corporate			Total
Revenues	$	79.5		$	51.0	$	841.1		$	—	$	—		$	971.6
Costs of product/services sold	18.7			6.8		760.5			—		—			786.0
Operations and maintenance expense	13.4			6.2		24.5			—		—			44.1
General and administrative expense	—			—		—			—		27.9			27.9
Gain on long-lived assets	0.5			—		—			—		—			0.5
Loss on contingent consideration	(2.1		)	—		—			—		—			(2.1		)
Earnings (loss) from unconsolidated affiliates, net	0.3			—		(0.4		)	—		—			(0.1		)
Other income, net	—			—		—			—		0.1			0.1
EBITDA	$	46.1		$	38.0	$	55.7		$	—	$	(27.8	)	$	112.0
Goodwill	$	356.8		$	728.6	$	1,463.2		$	—	$	—		$	2,548.6
Total assets	$	2,547.8		$	2,162.7	$	3,582.1		$	—	$	187.9		$	8,480.5
Purchases of property, plant and equipment	$	46.3		$	1.6	$	30.9		$	—	$	3.6		$	82.4

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

Note 15 – Condensed Consolidating Financial Information

We are a holding company and own no operating assets and have no significant operations independent of our subsidiaries. Obligations under the CEQP Senior Notes and the CEQP Credit Facility are jointly and severally guaranteed by our wholly owned subsidiaries. Legacy Crestwood GP and Crestwood Midstream and its wholly owned subsidiaries (collectively, Non-Guarantor Subsidiaries) do not guarantee our obligations under CEQP Senior Notes or CEQP Credit Facility. CEQP Finance Corp., the co-issuer of the CEQP Senior Notes, is our 100% owned subsidiary and has no material assets, operations, revenues or cash flows other than those related to its service as co-issuer of our senior notes.

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



	Parent					Guarantor Subsidiaries				Eliminations
	As Adjusted			As Previously Reported		As Adjusted		As Previously Reported		As Adjusted			As Previously Reported
	(in millions)
General and administrative expense	$	2.8		$	—	$	1.0	$	3.8	$	—		$	—
Operating income (loss)	(2.8		)	—		18.9		16.1		—			—
Equity in net income (loss) of subsidiary	19.6			16.8		—		—		(19.6		)	(16.8		)
Income (loss) before income taxes	13.2			13.2		19.0		16.2		(19.6		)	(16.8		)
Net income (loss)	13.2			13.2		18.9		16.1		(19.6		)	(16.8		)
Net income (loss) attributable to partners	13.2			13.2		18.9		16.1		(19.6		)	(16.8		)



	Parent						Guarantor Subsidiaries						Eliminations
	As Adjusted			As Previously Reported			As Adjusted			As Previously Reported			As Adjusted			As Previously Reported
	(in millions)
Cash flows from operating activities:	$	(6.9	)	$	—		$	21.1		$	14.2		$	—		$	—

Cash flows from investing activities:
Purchases of property, plant and equipment	(2.7		)	—			(2.4		)	(5.1		)	—			—
Capital contributions from consolidated affiliates and other	10.5			36.1			—			10.5			(10.5		)	(46.6		)
Net cash provided by (used in) investing activities	7.8			36.1			(2.4		)	5.4			(10.5		)	(46.6		)

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	190.4			—			—			190.4			—			—
Principal payments on long-term debt	(183.8		)	—			—			(183.8		)	—			—
Distributions paid to partners	(25.6		)	(36.1		)	—			(25.6		)	10.5			46.6
Change in intercompany balances	18.1			—			(18.1		)	—			—			—
Net cash provided by (used in) financing activities	(0.9		)	(36.1		)	(18.5		)	(19.4		)	10.5			46.6

The tables below present condensed consolidating financial statements for us (parent) on a stand-alone, unconsolidated basis, and our combined guarantor and combined non-guarantor subsidiaries as of March 31, 2015 and December 31, 2014, and for the three months ended March 31, 2015 and 2014. The financial information may not necessarily be indicative of the results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)



Condensed Consolidating Balance Sheet
March 31, 2015
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	0.9	$	—	$	66.8	$	—		$	67.7

Accounts receivable	—		97.1		191.5		—			288.6
Accounts receivable - related party	—		0.1		1.1		—			1.2
Accounts receivable - intercompany	2.8		—		—		(2.8		)	—
Total accounts receivable	2.8		97.2		192.6		(2.8		)	289.8

Inventories	—		14.7		9.2		—			23.9
Other current assets	—		33.8		23.6		—			57.4
Total current assets	3.7		145.7		292.2		(2.8		)	438.8

Property, plant and equipment, net	2.9		225.3		3,649.5		—			3,877.7
Goodwill and intangible assets, net	1.4		703.2		3,000.7		—			3,705.3
Investment in consolidated affiliates	5,829.5		—		—		(5,829.5		)	—
Investment in unconsolidated affiliates	—		—		316.6		—			316.6
Other assets	—		8.6		1.2		—			9.8
Total assets	$	5,837.5	$	1,082.8	$	7,260.2	$	(5,832.3	)	$	8,348.2

Liabilities and partners' capital
Current liabilities:
Accounts payable	$	—	$	90.4	$	123.1	$	—		$	213.5
Accounts payable - related party	—		2.5		2.7		—			5.2
Accounts payable - intercompany	—		—		2.8		(2.8		)	—
Total accounts payable	—		92.9		128.6		(2.8		)	218.7

Other current liabilities	—		29.6		93.1		—			122.7
Total current liabilities	—		122.5		221.7		(2.8		)	341.4

Long-term liabilities:
Long-term debt, less current portion	321.1		—		2,121.7		—			2,442.8
Other long-term liabilities	11.5		16.1		31.5		—			59.1

Partners' capital	758.0		944.2		138.4		(1,082.6		)	758.0
Interest of non-controlling partners in subsidiaries	4,746.9		—		4,746.9		(4,746.9		)	4,746.9
Total partners' capital	5,504.9		944.2		4,885.3		(5,829.5		)	5,504.9
Total liabilities and partners' capital	$	5,837.5	$	1,082.8	$	7,260.2	$	(5,832.3	)	$	8,348.2

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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	$	3.7	$	0.5	$	4.6	$	—		$	8.8

Accounts receivable	—		137.5		241.5		—			379.0
Accounts receivable - related party	—		0.3		0.3		—			0.6
Accounts receivable - intercompany	3.2		—		—		(3.2		)	—
Total accounts receivable	3.2		137.8		241.8		(3.2		)	379.6

Inventories	—		38.6		8.0		—			46.6
Other current assets	—		84.4		18.7		—			103.1
Total current assets	6.9		261.3		273.1		(3.2		)	538.1

Property, plant and equipment, net	2.5		227.1		3,664.2		—			3,893.8
Goodwill and intangible assets, net	1.7		706.7		3,014.7		—			3,723.1
Investment in consolidated affiliates	5,971.2		—		—		(5,971.2		)	—
Investment in unconsolidated affiliates	—		—		295.1		—			295.1
Other assets	—		9.9		1.4		—			11.3
Total assets	$	5,982.3	$	1,205.0	$	7,248.5	$	(5,974.4	)	$	8,461.4

Liabilities and partners' capital
Current liabilities:
Accounts payable	$	—	$	109.5	$	126.1	$	—		$	235.6
Accounts payable - related party	—		2.5		3.1		—			5.6
Accounts payable - intercompany	—		—		3.2		(3.2		)	—
Total accounts payable	—		112.0		132.4		(3.2		)	241.2

Other current liabilities	4.9		56.1		122.7		—			183.7
Total current liabilities	4.9		168.1		255.1		(3.2		)	424.9

Long-term liabilities:
Long-term debt, less current portion	380.0		—		2,012.8		—			2,392.8
Other long-term liabilities	12.9		15.1		31.2		—			59.2

Partners' capital	776.2		1,021.8		141.1		(1,162.9		)	776.2
Interest of non-controlling partners in subsidiaries	4,808.3		—		4,808.3		(4,808.3		)	4,808.3
Total partners' capital	5,584.5		1,021.8		4,949.4		(5,971.2		)	5,584.5
Total liabilities and partners' capital	$	5,982.3	$	1,205.0	$	7,248.5	$	(5,974.4	)	$	8,461.4

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)



Condensed Consolidating Statements of Operations
Three Months Ended March 31, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	280.0		$	455.1		$	(3.6	)	$	731.5

Costs of product/services sold	—			246.7			286.6			(3.6		)	529.7
Expenses:
Operations and maintenance	—			15.5			35.1			—			50.6
General and administrative	1.9			1.4			24.2			—			27.5
Depreciation, amortization and accretion	—			9.8			64.4			—			74.2
	1.9			26.7			123.7			—			152.3
Other operating income (expense):
Loss on long-lived assets, net	—			(0.2		)	(0.8		)	—			(1.0		)
Operating income (loss)	(1.9		)	6.4			44.0			—			48.5
Earnings from unconsolidated affiliates, net	—			—			3.4			—			3.4
Interest and debt expense, net	(3.7		)	—			(29.9		)	—			(33.6		)
Other income, net	—			0.2			—			—			0.2
Equity in net income of subsidiary	23.8			—			—			(23.8		)	—
Income (loss) before income taxes	18.2			6.6			17.5			(23.8		)	18.5
Provision for income taxes	0.1			—			0.3			—			0.4
Net income (loss)	18.1			6.6			17.2			(23.8		)	18.1
Net income attributable to non-controlling partners in subsidiaries	—			—			(9.8		)	—			(9.8		)
Net income (loss) attributable to partners	$	18.1		$	6.6		$	7.4		$	(23.8	)	$	8.3

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)



Condensed Consolidating Statements of Operations
Three Months Ended March 31, 2014
(in millions)
	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	437.9	$	537.0		$	(3.3	)	$	971.6

Costs of product/services sold	—			391.2		398.1			(3.3		)	786.0
Expenses:
Operations and maintenance	—			16.1		28.0			—			44.1
General and administrative	2.8			1.0		24.1			—			27.9
Depreciation, amortization and accretion	—			10.7		55.6			—			66.3
	2.8			27.8		107.7			—			138.3
Other operating income (expense):
Gain on long-lived assets, net	—			—		0.5			—			0.5
Loss on contingent consideration	—			—		(2.1		)	—			(2.1		)
Operating income (loss)	(2.8		)	18.9		29.6			—			45.7
Loss from unconsolidated affiliates, net	—			—		(0.1		)	—			(0.1		)
Interest and debt expense, net	(3.6		)	—		(28.1		)	—			(31.7		)
Other income, net	—			0.1		—			—			0.1
Equity in net income of subsidiary	19.6			—		—			(19.6		)	—
Income (loss) before income taxes	13.2			19.0		1.4			(19.6		)	14.0
Provision for income taxes	—			0.1		0.7			—			0.8
Net income (loss)	13.2			18.9		0.7			(19.6		)	13.2
Net loss attributable to non-controlling partners in subsidiary	—			—		6.4			—			6.4
Net income (loss) attributable to partners	$	13.2		$	18.9	$	7.1		$	(19.6	)	$	19.6

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)



Condensed Consolidating Statements of Comprehensive Income
Three Months Ended March 31, 2015
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net income (loss)	$	18.1	$	6.6	$	17.2	$	(23.8	)	$	18.1
Change in fair value of Suburban Propane Partners LP units	—		—		—		—			—
Comprehensive income (loss)	$	18.1	$	6.6	$	17.2	$	(23.8	)	$	18.1



Condensed Consolidating Statements of Comprehensive Income
Three Months Ended March 31, 2014
(in millions)
	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Net income (loss)	$	13.2		$	18.9	$	0.7	$	(19.6	)	$	13.2
Change in fair value of Suburban Propane Partners LP units	(0.8		)	—		—		—			(0.8		)
Comprehensive income (loss)	$	12.4		$	18.9	$	0.7	$	(19.6	)	$	12.4

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)



Condensed Consolidating Statements of Cash Flows
Three Months Ended March 31, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(5.4	)	$	85.0		$	77.0		$	—		$	156.6

Cash flows from investing activities:
Purchases of property, plant and equipment	(0.1		)	(4.0		)	(43.3		)	—			(47.4		)
Investment in unconsolidated affiliates	(0.2		)	—			(17.9		)	—			(18.1		)
Proceeds from sale of assets	—			0.2			0.3			—			0.5
Capital contribution from consolidated affiliates, net	10.5			—			—			(10.5		)	—
Other	(0.2		)	—			—			—			(0.2		)
Net cash provided by (used in) investing activities	10.0			(3.8		)	(60.9		)	(10.5		)	(65.2		)

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	138.1			—			1,114.6			—			1,252.7
Principal payments on long-term debt	(199.9		)	—			(970.0		)	—			(1,169.9		)
Payments on capital leases	—			—			(0.7		)	—			(0.7		)
Payments for debt-related deferred costs	—			—			(11.1		)	—			(11.1		)
Distributions paid to partners	(25.8		)	—			(10.5		)	10.5			(25.8		)
Distributions paid to non-controlling partners	—			—			(74.3		)	—			(74.3		)
Taxes paid for unit-based compensation vesting	—			(1.4		)	(1.7		)	—			(3.1		)
Change in intercompany balances	80.2			(80.2		)	—			—			—
Other	—			(0.1		)	(0.2		)	—			(0.3		)
Net cash provided by (used in) financing activities	(7.4		)	(81.7		)	46.1			10.5			(32.5		)

Net change in cash	(2.8		)	(0.5		)	62.2			—			58.9
Cash at beginning of period	3.7			0.5			4.6			—			8.8
Cash at end of period	$	0.9		$	—		$	66.8		$	—		$	67.7

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)



Condensed Consolidating Statements of Cash Flows
Three Months Ended March 31, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(6.9	)	$	21.1		$	67.7		$	—		$	81.9

Cash flows from investing activities:
Acquisitions, net of cash acquired	—			—			(12.1		)	—			(12.1		)
Purchases of property, plant and equipment	(2.7		)	(2.4		)	(77.3		)	—			(82.4		)
Investment in unconsolidated affiliates	—			—			(19.8		)	—			(19.8		)
Capital contribution from consolidated affiliates	10.5			—			—			(10.5		)	—
Net cash provided by (used in) investing activities	7.8			(2.4		)	(109.2		)	(10.5		)	(114.3		)

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	190.4			—			306.0			—			496.4
Principal payments on long-term debt	(183.8		)	—			(188.8		)	—			(372.6		)
Distributions paid to partners	(25.6		)	—			(10.5		)	10.5			(25.6		)
Distributions paid to non-controlling partners	—			—			(74.1		)	—			(74.1		)
Net proceeds from issuance of preferred equity of subsidiary	—			—			12.3			—			12.3
Change in intercompany balances	18.1			(18.1		)	—			—			—
Other	—			(0.4		)	(1.1		)	—			(1.5		)
Net cash provided by (used in) financing activities	(0.9		)	(18.5		)	43.8			10.5			34.9

Net change in cash	—			0.2			2.3			—			2.5
Cash at beginning of period	0.1			2.4			2.7			—			5.2
Cash at end of period	$	0.1		$	2.6		$	5.0		$	—		$	7.7

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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 Equity Partners LP.

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

•

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


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

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


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


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


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


•	governmental legislation and regulations;


•	weather conditions;


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


•	economic conditions;


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


•	environmental claims;


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


•	interest rates; and


•	the price and availability of debt and equity financing.

For additional factors that could cause actual results to be materially different from those described in the forward-looking statements, see Part I, Item IA. Risk Factors of our 2014 Annual Report on Form 10-K.

Our Company

We are a 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, transportation and marketing operations in the most prolific shale plays across the United States.

Our three business segments include (i) gathering and processing, which includes our natural gas G&P operations; (ii) storage and transportation, which includes our natural gas storage and transportation operations; and (iii) NGL and crude services, which includes our proprietary NGL supply and logistics business, crude oil facilities and fleet, NGL processing, fractionation and storage facilities, and salt production business. Except for our proprietary NGL supply and logistics business, which includes our West Coast NGL operations, our Seymour NGL storage facility and our fleet of NGL transportation and related rail-to-truck terminal assets, all of our operations are conducted by or through Crestwood Midstream. Below is a discussion of events that highlight our core business and financing activities.

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Gathering and Processing

Our G&P operations provide gathering, compression, treating, and processing services to producers in multiple unconventional resource plays across the United States. We have established footprints in “core of the core” areas of several shale plays with delineated condensate and rich gas windows offering attractive producer economics, while maintaining operations in several prolific dry gas plays. We believe that our strategy of focusing on liquids-rich plays without abandoning prolific lean gas plays positions us well to (i) generate greater returns in the near term while natural gas prices remain depressed, (ii) capture greater upside economics when natural gas prices normalize, and (iii) in general, manage through commodity price cycles and production changes associated therewith.

•

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

•

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

Storage and Transportation

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

•

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

•

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

•

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

NGL and Crude Services

Our NGL and crude services segment consists of our proprietary NGL and crude supply and logistics business, crude oil gathering systems and rail terminals, and US Salt. We have facilities located in and around some of the most prolific crude oil shales and premium demand market in North America. 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.

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•

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

Outlook and Trends

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

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

Another critical factor to improvement in our financial results in 2015 is reduced operating and administrative costs. During the three months ended March 31, 2015, our expenses related to operations, maintenance and general and administrative matters totaled $78 million, compared to $72 million during the same period in 2014. The increase was primarily due to the expansion of our operating platform as a result of approximately $420 million in capital expansion projects and bolt-on acquisitions completed in 2014. To align our operating costs further with current market conditions, in the first quarter of 2015, we implemented a company-wide cost-savings initiative to achieve annual run-rate cost savings of $25 million to $30 million by streamlining the organization to increase efficiency and improve effectiveness. Approximately $15 million of the overall cost savings is expected to impact our 2015 results through operational and support function consolidations and a reduction in work force. We incurred approximately $4 million of upfront costs during the first quarter of 2015 related to this cost savings initiative.

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

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Regulatory Matters

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

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

How We Evaluate Our Operations

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

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

EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company's operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. EBITDA is defined as income before income taxes, plus net interest and debt expense, and depreciation, amortization and accretion expense. In addition, Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates for our proportionate share of their depreciation and interest and the impact of certain significant items, such as unit-based compensation expenses, 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, change in fair value of certain commodity derivative contracts, 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 tables summarize our results of operations for the three months ended March 31, 2015 and 2014 (in millions):



	Three Months Ended
	March 31,
	2015			2014
Revenues	$	731.5		$	971.6
Costs of product/services sold	529.7			786.0
Operations and maintenance expense	50.6			44.1
General and administrative expense	27.5			27.9
Depreciation, amortization and accretion	74.2			66.3
Gain (loss) on long-lived assets, net	(1.0		)	0.5
Loss on contingent consideration	—			(2.1		)
Operating income	48.5			45.7
Earnings (loss) from unconsolidated affiliates, net	3.4			(0.1		)
Interest and debt expense, net	(33.6		)	(31.7		)
Other income, net	0.2			0.1
Provision for income taxes	(0.4		)	(0.8		)
Net income	18.1			13.2
Add:
Interest and debt expense, net	33.6			31.7
Provision for income taxes	0.4			0.8
Depreciation, amortization and accretion	74.2			66.3
EBITDA	$	126.3		$	112.0
Unit-based compensation charges	5.8			5.4
(Gain) loss on long-lived assets, net	1.0			(0.5		)
Loss on contingent consideration	—			2.1
(Earnings) loss from unconsolidated affiliates, net	(3.4		)	0.1
Adjusted EBITDA from unconsolidated affiliates, net	6.5			1.7
Change in fair value of commodity inventory-related derivative contracts	1.1			(10.7		)
Significant transaction and environmental related costs and other items	4.6			6.5
Adjusted EBITDA	$	141.9		$	116.6

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	Three Months Ended
	March 31,
	2015			2014
EBITDA:
Net cash provided by operating activities	$	156.6		$	81.9
Net changes in operating assets and liabilities	(59.6		)	2.4
Amortization of debt-related deferred costs, discounts and premiums	(2.1		)	(1.9		)
Interest and debt expense, net	33.6			31.7
Market adjustment on interest rate swap	0.3			0.6
Unit-based compensation charges	(5.8		)	(5.4		)
Gain (loss) on long-lived assets, net	(1.0		)	0.5
Loss on contingent consideration	—			(2.1		)
Earnings (loss) from unconsolidated affiliates, net	3.4			(0.1		)
Deferred income taxes	0.9			3.8
Provision for income taxes	0.4			0.8
Other non-cash income	(0.4		)	(0.2		)
EBITDA	$	126.3		$	112.0
Unit-based compensation charges	5.8			5.4
(Gain) loss on long-lived assets, net	1.0			(0.5		)
Loss on contingent consideration	—			2.1
(Earnings) loss from unconsolidated affiliates, net	(3.4		)	0.1
Adjusted EBITDA from unconsolidated affiliates, net	6.5			1.7
Change in fair value of commodity inventory-related derivative contracts	1.1			(10.7		)
Significant transaction and environmental related costs and other items	4.6			6.5
Adjusted EBITDA	$	141.9		$	116.6

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



	Three Months Ended								Three Months Ended
	March 31, 2015								March 31, 2014
	Gathering and Processing			Storage and Transportation			NGL and Crude Services		Gathering and Processing			Storage and Transportation		NGL and Crude Services
Revenues	$	78.5		$	45.7		$	607.5	$	79.5		$	51.0	$	841.1
Costs of product/services sold	12.7			3.3			513.9		18.7			6.8		760.5
Operations and maintenance expense	14.9			4.3			31.4		13.4			6.2		24.5
Gain (loss) on long-lived assets	(0.3		)	(0.7		)	—		0.5			—		—
Loss on contingent consideration	—			—			—		(2.1		)	—		—
Earnings (loss) from unconsolidated affiliates	2.5			0.9			—		0.3			—		(0.4		)
EBITDA	$	53.1		$	38.3		$	62.2	$	46.1		$	38.0	$	55.7

Segment Results

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

Gathering and Processing

EBITDA for our G&P segment increased by approximately $7.0 million for the three months ended March 31, 2015 compared to the same period in 2014, primarily due to lower costs of product/services sold of approximately $6.0 million, partially offset by lower revenues and higher operations and maintenance expense. The decrease in our G&P segment's costs of product/

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services sold was primarily driven by lower NGL and natural gas prices experienced under our percent-of-proceeds contracts related to our assets located in Granite Wash.

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

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

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

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

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

Storage and Transportation

Our storage and transportation segment's EBITDA increased by approximately $0.3 million during the three months ended March 31, 2015 compared to the same period in 2014. This increase was due to an increase in revenues from our Northeast storage and transportation operations, partially offset by the deconsolidation of Tres Palacios' impacts on our results. In December 2014, we sold our 100% interest in Tres Palacios Gas Storage LLC (Tres Palacios) to Tres Palacios Holdings LLC (Tres Holdings), the newly formed joint venture between a subsidiary of Crestwood Midstream and an affiliate of Brookfield Infrastructure Group (Brookfield) and, as a result, we deconsolidated Tres Palacios. During the three months ended March 31, 2014, Tres Palacios contributed approximately $1.2 million of EBITDA, consisting primarily of $6.7 million of revenues, $3.6 million of costs of product/services sold and $1.9 million of operations and maintenance expense. For the three months ended March 31, 2015, we recorded earnings from our unconsolidated affiliate of approximately $0.9 million, which primarily related to our proportionate share of Tres Holdings’ net income. For a further discussion of our investment in Tres Holdings, see Item 1, Financial Statements, Note 5.

Our storage and transportation segment's revenues decreased by $5.3 million during the three months ended March 31, 2015 compared to the same period in 2014, primarily due to the Tres Palacios deconsolidation described above. Partially offsetting this decrease were higher revenues of approximately $1.4 million due to additional firm storage and transportation services resulting from organic growth projects placed in service during 2014 and 2015, primarily the NS-1 Expansion project, which increased volumes delivered into Millennium Pipeline. During the three months ended March 31, 2015, total firm throughput from our Northeast storage and transportation services averaged approximately 1.6 Bcf/d compared to 1.4 Bcf/d during the same period in 2014.

Our storage and transportation segment's costs of product/services sold and operations and maintenance expenses decreased by $3.5 million and $1.9 million during the three months ended March 31, 2015 compared to the same period in 2014, primarily due to the Tres Palacios deconsolidation described above. The costs of product/services sold and operations and maintenance expenses related to our other storage and transportation operations were relatively flat during the three months ended March 31, 2015 compared to the same period in 2014.

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NGL and Crude Services

Our NGL and crude services segment's EBITDA increased by approximately $6.5 million during the three months ended March 31, 2015 compared to the same period in 2014. The increase was driven by a period over period decrease in costs of product/services sold of approximately $246.6 million, partially offset by a $233.6 million decrease in revenues. These revenue and costs of product/services sold decreases were primarily driven by our Arrow and crude marketing operations and our NGL terminalling, supply and logistics operations.

While the net decrease in revenues from our Arrow and crude marketing operations was $96.4 million during the three months ended March 31, 2015 compared to the same period in 2014, the costs of product/services sold related to these operations decreased by $108.2 million. The net decrease in revenues and costs of product/services sold was driven by the decreases in market prices on crude oil, which caused average crude oil prices on our crude oil sales to decrease by over 50% during the three months ended March 31, 2015 compared to the same period in 2014. Our revenues did not decrease as much as our costs of product/services sold because crude oil, natural gas and water volumes increased by 50%, 121% and 102% during the three months ended March 31, 2015 compared to the same period in 2014, as new wells were connected to our system.

Revenues from our NGL terminalling, supply and logistics operations decreased by $151.3 million during the three months ended March 31, 2015 compared to the same period in 2014, compared to a decrease of $141.0 million in its costs of product services sold period over period. These decreases were driven by decreased demand for propane and butane at our NGL terminals and other facilities resulting from lower commodity prices, and the fact that we experienced a milder winter during early 2015 compared to the unusually cold winter during 2014, which reduced our opportunities to capture incremental demand and margin opportunities in these operations.

Partially offsetting the net decreases in revenues from our Arrow, crude marketing and NGL operations was a $6.8 million increase in revenues resulting from higher volumes on our COLT Hub as a result of our expansion of this facility (including placing our release and departure tracks in service in December 2014) and increased utilization of non-firm capacity on the system. During the three months ended March 31, 2015 and 2014, we loaded approximately 123,000 MBbls/d and 98,000 MBbls/d of crude on rail cars entering the facility. We also experienced an increase in revenues of $6.7 million during the three months ended March 31, 2015 related to our crude transportation operations acquired in 2014.

During the three months ended March 31, 2015, we experienced higher operations and maintenance expense of $6.9 million primarily due to the acquisition of our crude oil transportation fleet in 2014.

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

Other Results

Our consolidated EBITDA for the three months ended March 31, 2015 was $126.3 million, an increase of $14.3 million compared to the same period in 2014. Our consolidated Adjusted EBITDA for the three months ended March 31, 2015 was $141.9 million, an increase of $25.3 million compared to the same period in 2014. The increase in our EBITDA and Adjusted EBITDA was primarily driven by our segment results described above. Partially offsetting those results were the general and administrative expenses of our Corporate operations which were relatively flat during the three months ended March 31, 2015 compared to the same period in 2014. During the first quarter of 2015, we incurred approximately $4.0 million of costs related to our 2015 cost savings initiatives, compared to $6.5 million of costs during the first quarter of 2014, primarily related to the Arrow acquisition and the Crestwood merger.

Items not affecting EBITDA include the following:

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

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Interest and Debt Expense - Interest and debt expense increased by approximately $1.9 million during the three months ended March 31, 2015 compared to the same period in 2014. The following table provides a summary of interest and debt expense (in millions):



	Three Months Ended
	March 31,
	2015		2014
Credit facilities	$	7.3	$	7.2
Senior notes	24.6		23.7
Other debt-related costs	2.4		2.2
Gross interest and debt expense	34.3		33.1
Less: capitalized interest	0.7		1.4
Interest and debt expense, net	$	33.6	$	31.7

Liquidity and Sources of Capital

We are a partnership holding company that derives all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated by operating activities, credit facilities, debt issuances, and sales of our common 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.

CEQP Credit Facility. As of March 31, 2015 we had $134.3 million of available capacity under the CEQP Credit Facility considering our most restrictive debt covenants under that facility. See Item 1, Financial Statements, Note 8 for a more detailed discussion of the CEQP Credit Facility.

Crestwood Midstream utilizes a variety of sources to service its outstanding indebtedness, fund growth capital expenditures, and make distributions to its unitholders. These sources include funds cash generated by its operating subsidiaries, borrowings under the Crestwood Midstream Revolver, debt issuances, and the sales of its common and Class A preferred units under the equity distribution agreement.

•

Crestwood Midstream Revolver. As of March 31, 2015, Crestwood Midstream had $429.1 million of available capacity under its credit facility considering the most restrictive debt covenants in its credit agreement. On April 8, 2015, Crestwood Midstream utilized approximately $315 million of its credit facility to redeem all of its outstanding 2019 Senior Notes. See Item 1, Financial Statements, Note 8 for a more detailed discussion of the Crestwood Midstream Revolver.

•

Preferred Units. During the three months ended March 31, 2015, Crestwood Midstream did not sell any Preferred Units to the Class A Purchasers. Crestwood Midstream expects to issue $60.0 million of Preferred Units to the Class A Purchasers before September 30, 2015, and to use the proceeds from such issuance to fund expansion and development projects, to reduce borrowings under its credit facility, and for other general partnership purposes. See Item 1, Financial Statements, Note 10 for a more detailed description of the Preferred Units.

•

Equity Distribution Agreement. Crestwood Midstream entered into an equity distribution program with certain financial institutions (each, a Manager) under which it is allowed to offer and sell, from time to time through one or more of the Managers, common units having an aggregate offering price of up to $300.0 million. Crestwood Midstream will pay the Managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under this at-the-market program. Crestwood Midstream did not issue any common units under this equity distribution program as of March 31, 2015 and through the date of this filing.

•

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

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As of March 31, 2015, we were in compliance with all our debt covenants related to the CEQP Credit Facility, Crestwood Midstream Revolver and our Senior Notes. See Item 1, Financial Statements, Note 8 for a more detailed description of these credit facilities and Senior Notes.

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



	Three Months Ended
	March 31,
	2015			2014
Net cash provided by operating activities	$	156.6		$	81.9
Net cash used in investing activities	(65.2		)	(114.3		)
Net cash provided by (used in) financing activities	(32.5		)	34.9

Operating Activities

Our operating cash flows increased approximately $74.7 million during the three months ended March 31, 2015 compared to the same period in 2014 primarily due to lower costs of product/services sold of approximately $256.3 million primarily due to lower prices in our G&P and NGL and crude services operations described above, and a $62.0 million net cash inflow from working capital resulting primarily from lesser working capital needs of our NGL terminalling business. Partially offsetting these impacts was a $240.1 million decrease in operating revenues primarily from our Arrow operations and our NGL terminalling business 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 three months ended March 31, 2015 (in millions). We have identified additional growth capital project opportunities for each of our reporting segments. Additional commitments or expenditures will be made at our discretion, and any discontinuation of the construction of these projects will likely result in less future cash flows and earnings.



Growth capital	$	35.0
Maintenance capital	5.4
Other ⁽¹⁾	7.0
Purchases of property, plant and equipment	47.4
Reimbursements of property, plant and equipment	22.9
Net purchases of property, plant and equipment	$	24.5

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

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

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

Investments in Unconsolidated Affiliates. During the three months ended March 31, 2015 and 2014, we made capital contributions of approximately $18.1 million and $19.8 million to our unconsolidated affiliates to fund their capital projects. For a further discussion of investment in our unconsolidated affiliates, see Item 1, Financial Statements, Note 5.

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Financing Activities

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

Equity Transactions


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

Debt Transactions


•	$688.9 million net proceeds from Crestwood Midstream's issuance of the 2023 Senior Notes during the three months ended March 31, 2015; and


•	$741.0 million increase in net repayments of long-term debt during the three months ended March 31, 2015 compared to the same period in 2014

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 related to our goodwill impairment estimates.

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 the potential value we would receive if we sold the reporting unit, enterprise value, discount rates and projected cash flows. Estimating projected cash flows requires us to make certain assumptions as it relates to future operating performance and financial condition of our customers. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others including our customer's ability to honor their financial obligations. 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 impairment testing prove inaccurate, we could incur an 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. In particular, we continue to monitor the recoverability of the goodwill related to our Barnett Shale (G&P) reporting unit given the recent actions of Quicksilver related to its filing for protection under Chapter 11 of the U.S. Bankruptcy Code in March 2015. Although we continue to believe that our goodwill is recoverable related to this reporting unit, future adverse changes related to Quicksilver's financial condition or its actions related to shutting-in production could impact the fair value of the reporting unit. A 2% decrease in the estimated future cash flows or a 0.2% increase in the discount rate used to estimate the fair value for that reporting unit could have potentially resulted in an impairment of all or a portion of the $257.2 million of goodwill related to our Barnett Shale reporting unit.

In addition, we continue to monitor the recoverability of the goodwill related to our West Coast reporting unit. As described in our 2014 Annual Report on Form 10-K, we acquired all of the reporting units in our NGL and crude services segment during 2013 (including our West Coast reporting unit), 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 their fair value. As a result, any decrease in the forecasted future cash flows of those businesses from the date of acquisition could result in the fair value of the reporting unit to fall below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit's goodwill could be impaired.

Our West Coast reporting unit is a fully integrated NGL facility which includes natural gas processing, NGL fractionation, butane isomerization, NGL storage and truck/rail loading and unloading. The facility operates by contracting for various short

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and long term natural gas and NGL supplies and provides a wide range of individual and integrated services to its customers. Many of the supply contracts and service agreements are for terms of one year or less and are typically renewed on an annual basis. Historically, the facility has been successful in renewing its supply and services contracts at terms, generally, no less favorable than the previous year. In April 2015, a supply and services contract with a traditional West Coast reporting unit customer was not renewed, which could have an adverse impact on the estimated future cash flows used to estimate the fair value of that reporting unit. In the future, if we are unable to regain that business or replace the level of revenues historically generated by that contract with third party supplies and services, it could impact the fair value of that reporting unit and potentially result in an impairment of all or a portion of the $85.9 million of goodwill related to our West Coast reporting unit.


Item 3.	Quantitative and Qualitative Disclosures About Market Risk

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

Credit Risk

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


Item 4.	Controls and Procedures

Disclosure Controls and Procedures

As of March 31, 2015, we carried out an evaluation under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as to the effectiveness, design and operation of our disclosure controls and procedures (as defined in the Securities Exchange Act of 1934, as amended (Exchange Act) Rules 13a-15(e) and 15d-15(e)). We maintain controls and procedures designed to provide reasonable assurance that information required to be disclosed in our reports that we file or submit under the Exchange Act of 1934, as amended, are recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as appropriate, to allow timely decisions regarding required disclosure. Our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our Chief Executive Officer and Chief Financial Officer of our General Partner concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of March 31, 2015.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting during the three months ended March 31, 2015 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

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PART II – OTHER INFORMATION


Item 1.	Legal Proceedings

Part I, Item 1. Financial Statements, Note 12 to the Consolidated Financial Statements, of this Form 10-Q is incorporated herein by reference.

Seymour Investigation. We own a propane storage and distribution facility in Seymour, Indiana. On May 15, 2014, the Environmental Protection Agency (EPA) issued a request relating to our compliance with the chemical accident prevention program at the facility. We responded to the request on August 6, 2014, and at EPA’s request, we submitted additional documentation of compliance on January 30, 2015. Although we have not received a compliance order or settlement agreement from the EPA, we anticipate that the EPA will assess a civil penalty against us and the amount could exceed $100,000.


Item 1A.	Risk Factors

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

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

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

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

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

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

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

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

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

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

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


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

None.


Item 3.	Defaults Upon Senior Securities

None.


Item 4.	Mine Safety Disclosures

Not applicable.


Item 5.	Other Information

None.

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Item 6.	Exhibits



Exhibit Number		Description
3.1		Certificate of Limited Partnership of Inergy, L.P. (incorporated by reference to Exhibit 3.1 to Inergy, L.P.'s Registration Statement on Form S-1 filed on March 14, 2001)

3.1A		Certificate of Correction of Certificate of Limited Partnership of Inergy, L.P. (incorporated by reference to Exhibit 3.1 to Inergy, L.P.'s Form 10-Q filed on May 12, 2003)

3.1B		Amendment to the Certificate of Limited Partnership of Crestwood Equity Partners LP (the “Company”) (f/k/a Inergy, L.P.) dated as of October 7, 2013 (incorporated herein by reference to Exhibit 3.2 to the Company’s Form 8-K filed on October 10, 2013)

3.2		Fifth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners LP dated as of April 11, 2014 (incorporated herein by reference to Exhibit 3.1 to Crestwood Equity Partners LP's Form 8-K filed on April 11, 2014)

3.3		Certificate of Formation of Inergy GP, LLC (incorporated by reference to Exhibit 3.5 to Inergy, L.P.'s Registration Statement on Form S-1/A filed on May 7, 2001)

3.3A		Certificate of Amendment of Crestwood Equity GP LLC (the “General Partner”) (f/k/a Inergy GP, LLC) dated as of October 7, 2013 (incorporated by reference to Exhibit 3.3A to Crestwood Equity Partners LP's Form 10-Q filed on November 8, 2013)

3.4		First Amended and Restated Limited Liability Company Agreement of Inergy GP, LLC dated as of September 27, 2012 (incorporated by reference to Exhibit 3.1 to Inergy, L.P.'s Form 8-K filed on September 27, 2012)

3.4A		Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of the General Partner dated as of October 7, 2013 (incorporated by reference to Exhibit 3.4A to Crestwood Equity Partners LP's Form 10-Q filed on November 8, 2013)

*12.1		Computation of ratio of earnings to fixed charges

*31.1		Certification of Chief Executive Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*31.2		Certification of Chief Financial Officer of the Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

*32.1		Certification of Chief Executive Officer of the Company 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 Chief Financial Officer of the Company 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 EQUITY PARTNERS LP

		By:	CRESTWOOD EQUITY GP LLC
			(its general partner)

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