10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

x	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2017

OR

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

(Exact name of registrant as specified in its charter)	Commission file number	State or other jurisdiction of incorporation or organization	(I.R.S. Employer Identification No.)
Crestwood Equity Partners LP	001-34664	Delaware	43-1918951
Crestwood Midstream Partners LP	001-35377	Delaware	20-1647837

811 Main Street, Suite 3400 Houston, Texas	77002
(Address of principal executive offices)	(Zip code)

(832) 519-2200

(Registrant’s telephone number, including area code)

___________________________________________

Securities registered pursuant to Section 12(b) of the Act:

Crestwood Equity Partners LP	Common Units representing limited partnership interests, listed on the New York Stock Exchange
Crestwood Midstream Partners LP	None

Securities registered pursuant to Section 12(g) of the Act:

Crestwood Equity Partners LP	None
Crestwood Midstream Partners LP	None

Indicate by check mark if registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. 

Crestwood Equity Partners LP	Yes  x    No  ¨
Crestwood Midstream Partners LP	Yes  ¨    No  x

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.     

Crestwood Equity Partners LP	Yes  ¨    No  x
Crestwood Midstream Partners LP	Yes  ¨    No  x

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.

Crestwood Equity Partners LP	Yes  x  No  ¨
Crestwood Midstream Partners LP	Yes  x  No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

Crestwood Equity Partners LP	Yes  x No  ¨
Crestwood Midstream Partners LP	Yes  x No  ¨

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K. 

Crestwood Equity Partners LP	x
Crestwood Midstream Partners LP	x

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

Crestwood Equity Partners LP	Large accelerated filer x	Accelerated filer ¨	Non-accelerated filer ¨	Smaller reporting company ¨	Emerging growth company ¨
Crestwood Midstream Partners LP	Large accelerated filer ¨	Accelerated filer ¨	Non-accelerated filer x	Smaller reporting company ¨	Emerging growth company ¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange act.

Crestwood Equity Partners LP	o
Crestwood Midstream Partners LP	o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).

Crestwood Equity Partners LP	Yes  ¨    No  x
Crestwood Midstream Partners LP	Yes  ¨    No  x

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (June 30, 2017).

Crestwood Equity Partners LP	$1.1 billion
Crestwood Midstream Partners LP	None

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date (February 12, 2018).

Crestwood Equity Partners LP	$26.95 per common unit	71,231,599
Crestwood Midstream Partners LP	None	None

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the following documents are incorporated by reference into the indicated parts of this report:

Crestwood Equity Partners LP	None
Crestwood Midstream Partners LP	None

Crestwood Midstream Partners LP, as a wholly-owned subsidiary of a reporting company, meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this report with the reduced disclosure format as permitted by such instruction.

FILING FORMAT

This Annual Report on Form 10-K is a combined report being filed by two separate registrants: Crestwood Equity Partners LP and Crestwood Midstream Partners LP. Crestwood Midstream Partners LP is a wholly-owned subsidiary of Crestwood Equity Partners LP. Information contained herein related to any individual registrant is filed by such registrant solely on its own behalf. Each registrant makes no representation as to information relating exclusively to the other registrant.

Item 15 of Part IV of this Annual Report includes separate financial statements (i.e., balance sheets, statements of operations, statements of comprehensive income, statements of partners’ capital and statements of cash flows, as applicable) for Crestwood Equity Partners LP and Crestwood Midstream Partners LP. The notes accompanying the financial statements are presented on a combined basis for each registrant. Management’s Discussion and Analysis of Financial Condition and Results of Operations included under Item 7 of Part II is presented for each registrant.

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CRESTWOOD EQUITY PARTNERS LP

CRESTWOOD MIDSTREAM PARTNERS LP

INDEX TO ANNUAL REPORT ON FORM 10-K

		Page
	PART I
Item 1.	Business	6
Item 1A.	Risk Factors	25
Item 1B.	Unresolved Staff Comments	45
Item 2.	Properties	45
Item 3.	Legal Proceedings	45
Item 4.	Mine Safety Disclosures	45
	PART II
Item 5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	48
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	52
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	76
Item 8.	Financial Statements and Supplementary Data	77
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	77
Item 9A.	Controls and Procedures	77
Item 9B.	Other Information	78
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	79
Item 11.	Executive Compensation	84
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	96
Item 13.	Certain Relationships and Related Transactions, and Director Independence	98
Item 14.	Principal Accountant Fees and Services	100
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	101

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GLOSSARY

The terms below are common to our industry and used throughout this report.

/d	per day
AOD	Area of dedication, which means the acreage dedicated to a company by an oil and/or natural gas producer under one or more contracts.
ASC	Accounting Standards Codification.
ASU	Accounting Standards Update.
Barrels (Bbls)	One barrel of petroleum products equal to 42 U.S. gallons.
Base gas	A quantity of natural gas held within the confines of the natural gas storage facility and used for pressure support and to maintain a minimum facility pressure. May consist of injected base gas or native base gas. Also known as cushion gas.
Bcf	One billion cubic feet of natural gas. A standard volume measure of natural gas products.
Cycle	A complete withdrawal and injection of working gas. Cycling refers to the process of completing one cycle.
EPA	Environmental Protection Agency.
FASB	Financial Accounting Standards Board.
FERC	Federal Energy Regulatory Commission.
Firm service	Services pursuant to which customers receive an assured or firm right to (i) in the context of storage service, store product in the storage facility or (ii) in the context of transportation service, transport product through a pipeline, over a defined period of time.
GAAP	Generally Accepted Accounting Principles.
Gas storage capacity	The maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Gas storage capacity excludes base gas.
HP	Horsepower.
Hub	Geographic location of a storage facility and multiple pipeline interconnections.
Hub services	With respect to our natural gas storage and transportation operations, the following services: (i) interruptible storage services, (ii) firm and interruptible park and loan services, (iii) interruptible wheeling services, and (iv) balancing services.
Injection rate	The rate at which a customer is permitted to inject natural gas into a natural gas storage facility.
Interruptible service	Services pursuant to which customers receive only limited assurances regarding the availability of (i) with respect to storage services, capacity and deliverability in storage facilities or (ii) with respect to transportation services, capacity and deliverability from receipt points to delivery points. Customers pay fees for interruptible services based on their actual utilization of the storage or transportation assets.
MMBbls	One million barrels.
MMcf	One million cubic feet of natural gas.
Natural gas	A gaseous mixture of hydrocarbon compounds, primarily methane together with varying quantities of ethane, propane, butane and other gases.
Natural Gas Act	Federal law enacted in 1938 that established the FERC’s authority to regulate interstate pipelines.
Natural gas liquids (NGLs)	Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. NGLs include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).
NYPSC	New York State Public Service Commission.
NYSE	New York Stock Exchange.
Salt cavern	A man-made cavern developed in a salt dome or salt beds by leaching or mining of the salt.
SEC	Securities and Exchange Commission.
Withdrawal rate	The rate at which a customer is permitted to withdraw gas from a natural gas storage facility.
Working gas	Natural gas in a storage facility in excess of base gas. Working gas may or may not be completely withdrawn during any particular withdrawal season.
Working gas storage capacity	See gas storage capacity (above).

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PART I

Item 1. Business

Unless the context requires otherwise, references to (i) “we,” “us,” “our,” “ours,” “our company,” the “Company,” the “Partnership,” “Crestwood Equity,” “CEQP,” and similar terms refer to either Crestwood Equity Partners LP itself or Crestwood Equity Partners LP and its consolidated subsidiaries, as the context requires, and (ii) “Crestwood Midstream” and “CMLP” refers to Crestwood Midstream Partners LP and its consolidated subsidiaries Unless otherwise indicated, information contained herein is reported as of December 31, 2017.

Introduction

Crestwood Equity, a Delaware limited partnership formed in March 2001, is a master limited partnership (MLP) that develops, acquires, owns or controls, and operates primarily fee-based assets and operations within the energy midstream sector. Headquartered in Houston, Texas, we provide broad-ranging infrastructure solutions across the value chain to service premier liquids-rich natural gas and crude oil shale plays across the United States. We own and operate a diversified portfolio of crude oil and natural gas gathering, processing, storage and transportation assets that connect fundamental energy supply with energy demand across North America. Crestwood Equity’s common units representing limited partner interests are listed on the NYSE under the symbol “CEQP.”

Crestwood Equity is a holding company. All of our consolidated operating assets are owned by or through our wholly-owned subsidiary, Crestwood Midstream, a Delaware limited partnership. Our consolidated operating assets primarily include:

• natural gas facilities with approximately 2.4 Bcf/d of gathering capacity and 0.5 Bcf/d of processing capacity;

• NGL facilities with approximately 20,000 Bbls/d of fractionation capacity and 3.1 MMBbls of storage capacity, as well as our portfolio of transportation assets (consisting of truck and rail terminals, truck/trailer units and rail cars) capable of transporting approximately 195,000 Bbls/d of NGLs; and

• crude oil facilities with approximately 125,000 Bbls/d of gathering capacity, 1.5 MMBbls of storage capacity, 20,000 Bbls/d of transportation capacity and 160,000 Bbls/d of rail loading capacity.

In addition, through our equity investments in joint ventures, we have ownership interests in:

• natural gas facilities with approximately 0.3 Bcf/d of gathering capacity, 0.2 Bcf/d of processing capacity, 75.8 Bcf of certificated working storage capacity, and 1.5 Bcf/d of transportation capacity; and

• crude oil facilities with approximately 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of working storage capacity.

Our primary business objective is to maximize the value of Crestwood for our unitholders.

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Ownership Structure

The diagram below reflects a simplified version of our ownership structure as of December 31, 2017:

Crestwood Equity. Crestwood Equity GP LLC, which is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), owns our non-economic general partnership interest. Crestwood Holdings, which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve), also owns approximately 25% of Crestwood Equity’s common units and all of its subordinated units as of December 31, 2017.

Crestwood Midstream. Crestwood Equity owns a 99.9% limited partnership interest in Crestwood Midstream and Crestwood Gas Services GP LLC (CGS GP), a wholly-owned subsidiary of Crestwood Equity, owns a 0.1% limited partnership interest in

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Crestwood Midstream. Crestwood Midstream GP LLC, a wholly-owned subsidiary of Crestwood Equity, owns the non-economic general partnership interest of Crestwood Midstream.

Simplification Merger (2015). On September 30, 2015, Crestwood Midstream merged with a wholly-owned subsidiary of Crestwood Equity, with Crestwood Midstream surviving as a wholly-owned subsidiary of Crestwood Equity (the Simplification Merger). Prior to the Simplification Merger, Crestwood Equity indirectly owned a non-economic general partnership interest in Crestwood Midstream and 100% of its incentive distribution rights (IDRs), which entitled Crestwood Equity to receive 50% of all distributions paid to Crestwood Midstream’s common unit holders in excess of its initial quarterly distribution of $0.37 per common unit. Crestwood Midstream’s common units were also listed on the NYSE under the listing symbol “CMLP”. Upon becoming a wholly-owned subsidiary of Crestwood Equity as a result of the Simplification Merger, Crestwood Midstream’s IDRs were eliminated and its common units ceased to be listed on the NYSE.

Prior to the Simplification Merger, Crestwood Midstream owned all of our operating assets other than the assets comprising our NGL marketing business. Crestwood Operations LLC (Crestwood Operations), a wholly-owned subsidiary of Crestwood Equity, owned and operated the assets comprising our NGL marketing business, consisting mainly of our West Coast NGL assets, our Seymour NGL storage facility, and our NGL transportation terminals and fleet. Upon the closing of the Simplification Merger, Crestwood Equity contributed 100% of its interests in Crestwood Operations to Crestwood Midstream. As a result of this contribution, all of the Company’s assets are owned by or through Crestwood Midstream. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2 for a further discussion of the Simplification Merger.

Our Assets

Our financial statements reflect three operating and reporting segments: (i) gathering and processing (G&P) operations; (ii) storage and transportation (S&T) operations; and (iii) marketing, supply and logistics (MS&L) operations. Below is a description of our operating and reporting segments.

Gathering and Processing

Our G&P operations provide gathering and transportation services (natural gas, crude oil and produced water) and processing, treating and compression services (natural gas) to producers in unconventional shale plays and tight-gas plays in North Dakota, West Virginia, Texas, New Mexico, Wyoming and Arkansas. This segment primarily includes our operations and investments that own (i) our crude oil, gas and produced water gathering systems in the Bakken Shale play; (ii) rich gas gathering systems and processing plants in the Bakken, Marcellus, Barnett, Delaware Permian and Powder River Basin Shale plays; and (iii) dry gas gathering systems in the Barnett, Fayetteville and Delaware Permian Shale plays.

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The table below summarizes certain information about our G&P systems (including our equity investments) as of December 31, 2017:

Shale Play (State)	Counties / Parishes	Pipeline (Miles)	Gathering Capacity	2017 Average Gathering Volumes	Compression (HP)	Number of In-Service Processing Plants	Processing Capacity (MMcf/d)	Gross Acreage Dedication
Bakken North Dakota	McKenzie and Dunn	640 (1)	100 MMcf/d - natural gas gathering 125 MBbls/d - crude oil gathering 40 MBbls/d - water gathering	48 MMcf/d - natural gas gathering 80 MBbls/d - crude oil gathering 35 MBbls/d - water gathering	18,000	1	30	150,000
Marcellus West Virginia	Harrison, Barbour and Doddridge	80	875 MMcf/d	423 MMcf/d	131,380	—	—	140,000
Barnett Texas	Hood, Somervell, Tarrant, Johnson and Denton	507	925 MMcf/d	319 MMcf/d	153,465	1	425	140,000
Fayetteville Arkansas	Conway, Faulkner, Van Buren, and White	173	510 MMcf/d	46 MMcf/d	18,670	—	—	143,000
Granite Wash Texas	Roberts	36	36 MMcf/d	10 MMcf/d	10,400	1	36	22,000
Delaware Permian(2) New Mexico/Texas	Eddy (New Mexico) Loving, Reeves, Ward, Culberson (Texas)	189	165 MMcf/d	74 MMcf/d	33,310 (3)	2	75	214,000
Powder River Basin(3) Wyoming	Converse	211	140 MMcf/d	60 MMcf/d	50,895	1	120	358,000

(1) Consists of 262 miles of natural gas gathering pipeline, 183 miles of crude oil gathering pipeline, and 195 miles of produced water gathering pipeline.

(2) Our Delaware Permian assets in New Mexico and Texas are owned by Crestwood Permian Basin Holdings LLC (Crestwood Permian), our 50% equity method investment.

(3) Includes 16,800 HP that is owned and operated by a third party under a compression services agreement.

(4) Our Powder River Basin assets are owned by Jackalope Gas Gathering Services, L.L.C. (Jackalope), our 50% equity method investment.

We generate G&P revenues predominantly under fee-based contracts, which minimizes our commodity price exposure and provides less volatile operating performance and cash flows. Our principal G&P systems are described below.

Bakken

Our Arrow system gathers crude oil, rich gas and produced water from wells operating on the Fort Berthold Indian Reservation in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota.  Located approximately 60 miles southeast of the COLT Hub, the Arrow system connects to our COLT Hub through Hiland Partners, LP (Hiland) and Andeavor crude oil pipeline systems.  The Arrow system includes approximately 640 miles of gathering lines, a 23-acre central delivery point with 266,000 Bbls of crude oil working storage capacity and multiple pipeline take-away outlets, and salt water disposal wells. We are completing construction of a 30 MMcf/d natural gas processing facility (Bear Den) and associated pipelines that began receiving gas in late 2017. Our operations are anchored by long-term gathering contracts with producers who have dedicated over 150,000 acres to the Arrow system, and our underlying contracts largely provide for fixed-fee gathering services with annual escalators for crude oil, natural gas and produced water gathering services.

Marcellus

We own and operate natural gas gathering and compression systems in Harrison, Doddridge and Barbour Counties, West Virginia. These systems consist of 80 miles of low pressure gathering lines and nine compression and dehydrations stations with 131,380 horsepower. Through these systems, we provide midstream services, primarily to Antero Resources Corporation (Antero), under long-term, fixed-fee contracts across two operating areas: our eastern area of operation (East AOD), where we are the exclusive gatherer, and our western area of operation (Western Area), where we provide compression services.

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In the East AOD, we provide gathering, dehydration and compression services, on a fixed-fee basis, to Antero on approximately 140,000 gross acres dedicated pursuant to a 20-year gathering and compression agreement. Under the gathering agreement, Antero provides for an annual minimum volume commitment of 450 MMcf/d in 2018. We gather and ultimately redeliver Antero’s production to MarkWest Energy Partners, L.P.’s Sherwood gas processing plant and various regional pipeline systems.

In the Western Area, we provide compression and dehydration services, on a fixed-fee basis, to Antero’s gathering facilities predominantly with our West Union and Victoria compressor stations, each with a maximum capacity of 120 MMcf/d. The agreement runs through 2021, subject to Antero’s right to extend the contract term for an additional three years, and provides for a minimum volume commitment of approximately 50% of the throughput capacity of each compressor station.

Barnett

We own and operate three systems in the Barnett Shale, including the Cowtown, Lake Arlington and the Alliance systems.

Our Cowtown system, which is located principally in the southern portion of the Fort Worth Basin, consists of pipelines that gather rich gas produced by customers and deliver the volumes to our plants for processing and the Cowtown plant, which includes two natural gas processing units that extract NGLs from the natural gas stream and deliver customers’ residue gas and extracted NGLs to unaffiliated pipelines for sale downstream. For the year ended December 31, 2017, our processing plant had a total average throughput of 114 MMcf/d of natural gas with an average NGL recovery of 9,541 Bbls/d. In June 2015, we diverted processing volumes from our Corvette plant to the Cowtown plant but we continue to use the compression facilities at the Corvette plant.

Our Lake Arlington system, which is located in eastern Tarrant County, Texas, consists of a dry gas gathering system and related dehydration and compression facilities. Our Alliance system, which is located in northern Tarrant and southern Denton Counties, Texas, consists of a dry gas gathering system and a related dehydration, compression and amine treating facility.

Fayetteville

We own and operate five systems in the Fayetteville Shale, including the Twin Groves, Prairie Creek, Woolly Hollow, Wilson Creek, and Rose Bud systems. Our Twin Groves, Prairie Creek, and Woolly Hollow systems (Conway and Faulkner Counties) consist of three gas gathering, compression, dehydration and treating facilities. Our Wilson Creek system (Van Buren County) consists of a gas gathering system and related dehydration and compression facilities. Our Rose Bud system (White County) consists of a gas gathering system. All of our systems gather natural gas produced by customers and deliver customers’ gas to unaffiliated pipelines for sale downstream.

Equity Investments

Delaware Permian

In October 2016, Crestwood Infrastructure Holdings LLC (Crestwood Infrastructure), our wholly-owned subsidiary, and an affiliate of First Reserve formed a joint venture, Crestwood Permian, to fund and own a natural gas gathering system (the Nautilus gathering system) and other potential investments in the Delaware Permian. As part of this transaction, we transferred to the Crestwood Permian joint venture 100% of the equity interest of Crestwood Permian Basin LLC (Crestwood Permian Basin), which owns the Nautilus gathering system. We manage the joint venture under a long-term management agreement and we account for our 50% ownership interest in Crestwood Permian under the equity method of accounting.

Crestwood Permian Basin has a long-term agreement with SWEPI LP (SWEPI), a subsidiary of Royal Dutch Shell plc, to construct, own and operate the Nautilus gathering system in SWEPI’s operated position in the Delaware Permian. SWEPI has dedicated to Crestwood Permian Basin approximately 100,000 acres and gathering rights for SWEPI’s gas production across a large acreage position in Loving, Reeves and Ward Counties, Texas. The initial build-out of the Nautilus gathering system was completed on June 6, 2017, and includes 20 receipt point meters, 60 miles of pipeline, a 24-mile high pressure header system, 10,080 horsepower of compression and a high pressure delivery point. From the date it was placed into service to December 31, 2017, the Nautilus gathering system had an average throughput of 35 MMcf/d. Crestwood Permian Basin provides gathering, dehydration, compression and liquids handling services to SWEPI under a 20-year fixed-fee gathering agreement. In October 2017, Shell Midstream Partners L.P. (Shell Midstream), a subsidiary of Royal Dutch Shell plc, purchased a 50% equity interest in Crestwood Permian Basin.

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On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico Pipeline LLC

(Crestwood New Mexico), our wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New

Mexico. These assets consist of two dry gas gathering systems (Las Animas systems) and one rich gas gathering system and processing plant (Willow Lake system). Our Willow Lake system includes two plants with a combined capacity of 75MMcf/d processing plant, which are supported by a 10-year fixed-fee agreement with Concho Resources Inc. (Concho) and a seven year contract with Mewbourne Oil Co. (Mewbourne). We deconsolidated Crestwood New Mexico as a result of the contribution. In conjunction with this contribution, First Reserve has agreed to contribute to Crestwood Permian the first $151 million of capital cost required to fund the expansion of the Delaware Basin assets, which includes a new processing plant located in Orla, Texas and associated pipelines (Orla processing plant). See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in Crestwood Permian.

Powder River Basin

Our G&P segment includes our 50% equity interest in the Jackalope joint venture with Williams Partners LP (Williams), which we account for under the equity method of accounting. The joint venture, operated by Williams, owns the Jackalope gas gathering system, which serves a 358,000 gross acre dedication operated by Chesapeake Energy Corporation (Chesapeake) in Converse County, Wyoming. The Jackalope system consists of approximately 211 miles of gathering pipelines, 50,895 horsepower of compression and a 120 MMcf/d processing plant (Bucking Horse). The system connects to 100 well pads and is supported by a 10-year gathering and processing agreement with Chesapeake that includes minimum revenue guarantees for a five to seven year period. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in Jackalope.

The table below summarizes certain contract information of our G&P operations (including our equity investments) as of December 31, 2017:

Shale Play	Type of Services	Type of Contracts(1)	Gross Acreage Dedication	Major Customers	Weighted Average Remaining Contract Terms (in years)
Bakken	Gathering - crude oil, natural gas and water	Mixed	150,000	WPX, Bruin E&P Partners, LLC, Rimrock Energy Partners, LLC, XTO Energy, QEP Resources, Inc., Enerplus	8
Marcellus	Gathering	Fixed-fee	140,000	Antero	14
	Compression	Fixed-fee	—	Antero	2
Barnett	Gathering	Mixed	140,000	BlueStone, Devon Energy, Tokyo Gas America Ltd. (Tokyo Gas)	7
	Processing	Mixed	—	BlueStone, Devon Energy, Tokyo Gas	9
	Compression	Mixed	—	BlueStone, Devon Energy, Tokyo Gas	7
Fayetteville	Gathering	Fixed-fee	143,000	BHP Billiton Petroleum (BHP)	7
	Treating	Fixed-fee	—	BHP	7
Granite Wash	Gathering	Fixed-fee	22,000	Sabine Oil and Gas	7
	Processing	Mixed	—	Sabine Oil and Gas	7
Permian	Gathering	Fixed-fee	214,000	Mewbourne, Concho, Marathon Oil Corp, SWEPI	7
	Processing	Mixed	—	Mewbourne, Matador	4
Powder River Basin	Gathering	Fixed-fee	358,000	Chesapeake	10
	Processing	Fixed-fee	—	Chesapeake	10

(1) Fixed-fee contracts represent contracts in which our customers agree to pay a flat rate based on the amount of gas delivered. Mixed contracts include percent-of-proceeds and fixed-fee arrangements.

Storage and Transportation

Our S&T operations include our COLT Hub, one of the largest crude-by-rail terminals serving Bakken crude oil production, and our equity investments in three joint ventures that own five high-performance natural gas storage facilities with an aggregate certificated working gas storage capacity of approximately 75.8 Bcf, three natural gas pipeline systems with an aggregate firm transportation capacity of 1.5 Bcf/d, and crude oil facilities with approximately 380,000 Bbls of crude oil working storage capacity and 20,000 Bbls/d of rail loading capacity.

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COLT Hub

The COLT Hub consists of our integrated crude oil loading, storage and pipeline terminal located in the heart of the Bakken and Three Forks Shale oil-producing areas in Williams County, North Dakota. It has approximately 1.2 MMBbls of crude oil storage capacity and is capable of loading up to 160,000 Bbls/d. Customers can source crude oil for rail loading through interconnected gathering systems, a twelve-bay truck unloading rack and the COLT Connector, a 21-mile 10-inch bi-directional proprietary pipeline that connects the COLT terminal to our storage tank at Dry Fork (Beaver Lodge/Ramberg junction). The COLT Hub is connected to the Meadowlark Midstream Company, LLC and Hiland crude oil gathering systems and the Dakota Access Pipeline (DAPL) interstate pipeline system at the COLT terminal, and the Enbridge Energy Partners, L.P. and Andeavor interstate pipeline systems at Dry Fork. The gathering systems connected to the COLT Hub can deliver up to approximately 350,000 Bbls/d of crude oil to our terminal.

Equity Investments

Below is a description of the S&T assets owned by our joint ventures.

Northeast Storage Facilities. Our storage and transportation segment includes our 50% equity interest in Stagecoach Gas Services LLC (Stagecoach Gas), which we account for under the equity method of accounting. On June 3, 2016, our wholly-owned subsidiary, Crestwood Pipeline and Storage Northeast LLC (Crestwood Northeast) and Con Edison Gas Pipeline and Storage Northeast, LLC (CEGP), a wholly-owned subsidiary of Consolidated Edison, Inc. (Consolidated Edison), formed Stagecoach Gas to own and further develop our natural gas natural gas storage and transportation business located in the Northeast (the NE S&T assets). During 2016, we contributed to the joint venture the entities owning the NE S&T assets, CEGP contributed to the joint venture $975 million in exchange for a 50% equity interest in Stagecoach Gas, and Stagecoach Gas distributed to us the net cash proceeds received from CEGP. We manage the joint venture’s operations under a long-term management agreement. We deconsolidated the NE S&T assets as a result of the contribution of these assets to Stagecoach Gas as described above. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in Stagecoach Gas.

The Stagecoach Gas joint venture owns and operates four natural gas storage facilities located in New York and Pennsylvania. The facilities are located near major shale plays and demand markets, have low maintenance costs and long useful lives. They have comparatively high cycling capabilities, and their interconnectivity with interstate pipelines offers significant flexibility to customers. These natural gas storage facilities, each of which generates fee-based revenues as of December 31, 2017, include:

• Stagecoach - a FERC certificated 26.2 Bcf multi-cycle, depleted reservoir storage facility owned and operated by a subsidiary of Stagecoach Gas. A 21-mile, 30-inch diameter south pipeline lateral connects the storage facility to Tennessee Gas Pipeline Company, LLC’s (TGP) 300 Line, and a 10-mile, 20-inch diameter north pipeline lateral connects to Millennium Pipeline Company’s (Millennium) system.

• Thomas Corners - a FERC-certificated 7.0 Bcf multi-cycle, depleted reservoir storage facility owned and operated by a subsidiary of Stagecoach Gas. An 8-mile, 12-inch diameter pipeline lateral connects the storage facility to TGP’s 200 Line, and an 8-mile, 8-inch diameter pipeline lateral connects to Millennium. Thomas Corners is also connected to Dominion Transmission Inc.’s (Dominion) system through the Steuben facility discussed below.

• Seneca Lake - a FERC-certificated 1.5 Bcf multi-cycle, bedded salt storage facility owned and operated by a subsidiary of Stagecoach Gas. A 20-mile, 16-inch diameter pipeline lateral connects the storage facility to the Millennium and Dominion systems.

• Steuben - a FERC-certificated 6.2 Bcf single-cycle, depleted reservoir storage facility owned and operated by a subsidiary of Stagecoach Gas. A 15-mile, 12-inch diameter pipeline lateral connects the storage facility to the Dominion system, and a 6-inch diameter pipeline measuring less than one mile connects the Steuben and Thomas Corners storage facilities.

Tres Palacios Storage Facility. Our storage and transportation segment includes our 50.01% equity interest in Tres Palacios Holdings LLC (Tres Holdings), which we account for under the equity method of accounting. Tres Palacios Gas Storage LLC (Tres Palacios), a wholly-owned subsidiary of Tres Holdings, owns a FERC-certificated 34.9 Bcf multi-cycle salt dome natural gas storage facility located in Texas. We manage the joint venture’s operations under a long-term management agreement.

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The Tres Palacios natural gas storage facility’s 63-mile, dual 24-inch diameter header system (including a 52-mile north pipeline lateral and an approximate 11-mile south pipeline lateral) interconnects with 11 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan Inc.’s (Kinder Morgan) Houston Central processing plant. The certificated maximum injection rate of the Tres Palacios storage facility is 1,000 MMcf/d and the certificated maximum withdrawal rate is 2,500 MMcf/d. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our ownership interest in Tres Palacios.

The following provides additional information about the natural gas storage facilities of our S&T equity investments as of December 31, 2017:

Storage Facility / Location	Certificated Working Gas Storage Capacity (Bcf)		Certificated Maximum Injection Rate (MMcf/d)	Certificated Maximum Withdrawal Rate (MMcf/d)	Pipeline Connections
Stagecoach Tioga County, NY; Bradford County, PA	26.2		250	500	TGP’s 300 Line; Millennium; UGI’s Sunbury Pipeline,(1) Transco’s Leidy Line(1)
Thomas Corners Steuben County, NY	7.0		70	140	TGP’s 200 Line; Millennium; Dominion
Seneca Lake Schuyler County, NY	1.5	(2)	73	145	Dominion; Millennium
Steuben Steuben County, NY	6.2		30	60	TGP’s 200 Line; Millennium; Dominion
Northeast Storage Total	40.9		423	845
Tres Palacios	34.9		1,000	2,500	Multiple(3)
Total	75.8		1,423	3,345

(1) Stagecoach is connected to UGI Energy Services, LLC’s (UGI) Sunbury Pipeline and Transcontinental Gas Pipe Line Corporation’s (Transco) Leidy Line through the MARC I Pipeline.

(2) Stagecoach Gas has been authorized by the FERC to expand the facility’s working gas storage capacity to 2 Bcf.

(3) Tres Palacios is interconnected to Florida Gas Transmission Company, LLC, Kinder Morgan Tejas Pipeline, L.P., Houston Pipe Line Company LP, Central Texas Gathering System, Natural Gas Pipeline Company of America, Transco, TGP, Gulf South Pipeline, Valero Natural Gas Pipeline Company, Channel Pipeline Company, and Texas Eastern Transmission, L.P.

Transportation Facilities. Stagecoach Gas owns three natural gas pipeline systems located in New York and Pennsylvania. These natural gas transportation facilities include:

• North-South Facilities - include compression and appurtenant facilities installed to expand transportation capacity on the Stagecoach north and south pipeline laterals. The bi-directional interstate facilities provide more than 538 MMcf/d of firm interstate transportation capacity to shippers. The North-South Facilities generate fee-based revenues under a negotiated rate structure authorized by the FERC.

• MARC I Pipeline - a 39-mile, 30-inch diameter interstate natural gas pipeline that connects the North-South Facilities and TGP’s 300 Line in Bradford County, Pennsylvania, with UGI’s Sunbury Pipeline and Transco’s Leidy Line, both in Lycoming County, Pennsylvania. The bi-directional pipeline provides more than 925 MMcf/d of firm interstate transportation capacity to shippers. The MARC I Pipeline generates fee-based revenues under a negotiated rate structure authorized by the FERC.

• East Pipeline -a 37.5 mile, 12-inch diameter intrastate natural gas pipeline located in New York, which transports 30 MMcf/d of natural gas from Dominion to the Binghamton, New York city gate. The pipeline runs within three miles of the North-South Facilities’ point of interconnection with Millennium. The East Pipeline generates fee-based revenues under a negotiated rate structure authorized by the NYPSC.

Rail Loading Facility. Crestwood Crude Logistics LLC, our wholly-owned subsidiary, has a 50.01% equity interest in Powder River Basin Industrial Complex, LLC (PRBIC), which owns an integrated crude oil loading, storage and pipeline terminal located in Douglas County, Wyoming. PRBIC provides a market for crude oil production from the Powder River Basin. The joint venture, which is operated by our joint venture partner, Twin Eagle Resource Management, LLC (Twin Eagle), sources crude oil production from Chesapeake and other Powder River Basin producers. PRBIC includes 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of crude oil working storage capacity. PRBIC expanded its pipeline terminal to include connections to Kinder Morgan’s Double H Pipeline system in July 2015 and Plains All American Pipeline’s Rocky Mountain Pipeline system in March 2016. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in PRBIC.

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The table below summarizes certain contract information associated with the COLT Hub and the assets of our S&T equity investments as of December 31, 2017:

Facility	Type of Services	Type of Contracts(1)(2)	Contract Volumes	Major Customers	Weighted Average Remaining Contract Terms (in years)
COLT	Rail Loading and Transportation	Mixed	31 MBbl/d	U.S. Oil, Flint Hills Resources, Sunoco Logistics	2
NE S&T Joint Venture:
North-South Facilities	Transportation	Firm	538 MMcf/d	Southwestern Energy, Consolidated Edison, Anadarko Energy Services Company (Anadarko)	2
MARC I Pipeline	Transportation	Firm	925 MMcf/d	Chesapeake, Anadarko, Chief Oil and Gas	3
East Pipeline	Transportation	Firm	30 MMcf/d	NY State Electric & Gas Corp	3
Stagecoach	Storage	Firm	26.3 Bcf	Consolidated Edison, Merrill Lynch Commodities Inc (Merrill Lynch), New Jersey Natural Gas, Repsol Energy North America Corporation (Repsol), Sequent Energy Management	2
Thomas Corners	Storage	Firm	13.0 Bcf	Repsol, Tenaska Gas Storage, LLC	1
Seneca Lake	Storage	Firm	1.5 Bcf	Dominion, NY State Electric & Gas Corp, DTE Energy Trading	2
Steuben	Storage	Firm	9.3 Bcf	PSEG Energy Resources & Trade LLC, Repsol, Pivotal Utility Holdings	1
Tres PalaciosJoint Venture	Storage	Firm	28.5 Bcf	Brookfield Infrastructure Group, Anadarko, Exelon, Merrill Lynch, NJR Energy, Repsol	1
PRBICJoint Venture	Rail Loading	Fixed-fee	10 MBbl/d	Chesapeake	1

(1) Firm contracts represent take-or-pay contracts whereby our customers agree to pay for a specified amount of storage or transportation capacity, whether or not the capacity is utilized. Fixed-fee contracts represent contracts in which our customers agree to pay a flat rate based on the amount of commodity delivered.

(2) Mixed contracts include both firm and fixed-fee arrangements.

Marketing, Supply and Logistics

Our MS&L segment includes our supply and logistics business, our storage and terminals business, our West Coast operations and our crude oil, NGL and produced water trucking operations.

Supply and Logistics. Our Supply and Logistics operations are supported by (i) our fleet of rail and rolling stock with 75,000 Bbls/d of NGL transportation capacity, which also includes our rail-to-truck terminals located in Florida, New Jersey, New York, Rhode Island and North Carolina; and (ii) NGL pipeline and storage capacity leased from third parties, including more than 500,000 Bbls of NGL working storage capacity at major hubs in Mt. Belvieu, Texas and Conway, Kansas.

Storage and Terminals. Our NGL Storage and Terminals operations include our Seymour and Bath storage facilities. The Seymour storage facility is located in Seymour, Indiana, and has 500,000 Bbls of underground NGL storage capacity and 29,000 Bbls of aboveground “bullet” storage capacity. The Seymour facility’s receipts and deliveries are supported by Enterprise’s TEPPCO pipeline, allowing pipeline and truck access. The Bath storage facility is located in Bath, New York and has approximately 2.0 MMBbls of underground NGL storage capacity and is supported by rail and truck terminal facilities capable of loading and unloading 23 rail cars per day and approximately 100 truck transports per day.

West Coast. Our West Coast NGL operations provide processing, fractionation, storage, transportation and marketing services to producers, refiners and other customers. Our facilities located near Bakersfield, California include 24 million gallons of aboveground NGL storage capacity, 25 MMcf/d of natural gas processing capacity, 12,000 Bbls/d of NGL fractionation capacity, 8,000 Bbls/d of butane isomerization capacity, and NGL rail and truck receipt and take-away options. We separate NGLs from natural gas, deliver to local natural gas pipelines, retain NGLs for further processing at our fractionation facility, provide butane isomerization and refrigerated storage services, as well as provide to Western US refineries for motor fuel production. Our isomerization facility chemically changes normal butane to isobutane, which we provide to refineries for motor fuel production. Our operations also consist of wholesale propane assets, primarily including three rail-to-truck terminals located in Hazen, Nevada, Carlin, Nevada, and Shoshoni, Wyoming and a truck terminal located in Salt Lake City, Utah. These terminals are used to provide supply, transportation and storage services to wholesale customers in the western and north central regions of the United States.

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Trucking. Our Trucking operations consist of a fleet of owned and leased trucks with 20,000 Bbls/d of crude oil and produced water transportation capacity and 120,000 Bbls/d of NGL transportation capacity. We provide hauling services to customers in North Dakota, Montana, Wyoming, Texas, New Mexico, Indiana, Mississippi, New Jersey, Ohio, Utah and California.

Customers

For the years ended December 31, 2017, 2016 and 2015, no customer accounted for more than 10% of our total consolidated revenues.

Industry Background

The midstream sector of the energy industry provides the link between exploration and production and the delivery of crude oil, natural gas and their components to end-use markets. The midstream sector consists generally of gathering, processing, storage, and transportation activities. We, through our consolidated operations and our equity investments, gather crude oil and natural gas; process natural gas; fractionate NGLs; store crude oil, NGLs and natural gas; and transport crude oil, NGLs and natural gas.

The diagram below depicts the main segments of the midstream sector value chain:

Crude Oil

Pipelines typically provide the most cost-effective option for shipping crude oil. Crude oil gathering systems normally comprise a network of small-diameter pipelines connected directly to the well head that transport crude oil to central receipt points or interconnecting pipelines through larger diameter trunk lines. Common carrier pipelines frequently transport crude oil from central delivery points to logistics hubs or refineries under tariffs regulated by the FERC or state authorities. Logistic hubs provide storage and connections to other pipeline systems and modes of transportation, such as railroads and trucks. Pipelines not engaged in the interstate transportation of crude may also be proprietary or leased entirely to a single customer.

Trucking complements pipeline gathering systems by gathering crude oil from operators at remote wellhead locations not served by pipeline gathering systems. Trucking is generally limited to low volume, short haul movements because trucking costs escalate sharply with distance, making trucking the most expensive mode of crude oil transportation. Railroads provide additional transportation capabilities for shipping crude oil between gathering storage systems, pipelines, terminals and storage centers and end-users.

Natural Gas

Midstream companies within the natural gas industry create value at various stages along the value chain by gathering natural gas from producers at the wellhead, processing and separating the hydrocarbons from impurities and into lean gas (primarily methane) and NGLs, and then routing the separated lean gas and NGL streams for delivery to end-markets or to the next stage of the value chain.

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A significant portion of natural gas produced at the wellhead contains NGLs. Natural gas produced in association with crude oil typically contains higher concentrations of NGLs than natural gas produced from gas wells. This rich natural gas is generally not acceptable for transportation in the nation’s transmission pipeline system or for residential or commercial use. Processing plants extract the NGLs, leaving residual lean gas that meets transmission pipeline quality specifications for ultimate consumption. Processing plants also produce marketable NGLs, which, on an energy equivalent basis, typically have a greater economic value as a raw material for petrochemicals and motor gasolines than as a component of the natural gas stream.

Gathering.At the earliest stage of the midstream value chain, a network of typically small diameter pipelines known as gathering systems directly connect to wellheads or pad sites in the production area. Gathering systems transport gas from the wellhead to downstream pipelines or a central location for treating and processing. Gathering systems are often designed to be highly flexible to allow gathering of natural gas at different pressures and scalable to allow for additional production and well connections without significant incremental capital expenditures. A byproduct of the gathering process is the recovery of condensate liquids, which are sold on the open market.

Compression.Gathering systems are operated at pressures intended to enable the maximum amount of production to be gathered from connected wells. Through a mechanical process known as compression, volumes of natural gas at a given pressure are compressed to a sufficiently higher pressure, thereby allowing those volumes to be delivered into a higher pressure downstream pipeline to be shipped to market. Because wells produce at progressively lower field pressures as they age, it becomes necessary to add additional compression over time to maintain throughput across the gathering system.

Treating and Dehydration.Treating and dehydration involves the removal of impurities such as water, carbon dioxide, nitrogen and hydrogen sulfide that may be present when natural gas is produced at the wellhead. Impurities must be removed for the natural gas to meet the quality specifications for pipeline transportation, and end users normally cannot consume (and will not purchase) natural gas with a high level of impurities. Therefore, to meet downstream pipeline and end user natural gas quality standards, the natural gas is dehydrated to remove water and is chemically treated to separate the impurities from the natural gas stream.

Processing.Once impurities are removed, pipeline-quality residue gas is separated from NGLs. Most rich natural gas is not suitable for long-haul pipeline transportation or commercial use and must be processed to remove the heavier hydrocarbon components. The removal and separation of hydrocarbons during processing is possible because of the differences in physical properties between the components of the raw gas stream. There are four basic types of natural gas processing methods: cryogenic expansion, lean oil absorption, straight refrigeration and dry bed absorption. Cryogenic expansion represents the latest generation of processing, incorporating extremely low temperatures and high pressures to provide the best processing and most economical extraction.

Natural gas is processed not only to remove heavier hydrocarbon components that would interfere with pipeline transportation or the end use of the natural gas, but also to separate from the natural gas those hydrocarbon liquids that could have a higher value as NGLs than as natural gas. The principal component of residue gas is methane, although some lesser amount of entrained ethane typically remains. In some cases, processors have the option to leave ethane in the gas stream or to recover ethane from the gas stream, depending on ethane’s value relative to natural gas. The processor’s ability to “reject” ethane varies depending on the downstream pipeline’s quality specifications. The residue gas is sold to industrial, commercial and residential customers and electric utilities.

Fractionation. Once NGLs have been removed from the natural gas stream, they can be broken down into their base components to be useful to commercial customers. Mixed NGL streams can be further separated into purity NGL products, including ethane, propane, normal butane, isobutane, and natural gasoline. Fractionation works based on the different boiling points of the different hydrocarbons in the NGL stream, and essentially occurs in stages consisting of the boiling off of hydrocarbons one by one. The entire fractionation process is broken down into steps, starting with the removal of the lighter NGLs from the stream. In general, fractionators are used in the following order: (i) deethanizer, which separates ethane from the NGL stream, (ii) depropanizer, which separates propane, (iii) debutanizer, which boils off the butanes and leaves the pentanes and heavier hydrocarbons in the NGL stream, and (iv) butane splitter (or deisobutanizer), which separates isobutanes and normal butanes.

Transportation and Storage.Once raw natural gas has been treated or processed and the raw NGL mix fractionated into individual NGL components, the natural gas and NGL components are stored, transported and marketed to end-use markets. The natural gas pipeline grid in the United States transports natural gas from producing regions to customers, such as LDCs, industrial users and electric generation facilities.

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Historically, the concentration of natural gas production in a few regions of the United States generally required transportation pipelines to transport gas not only within a state but also across state borders to meet national demand. However, a recent shift in supply sources, from conventional to unconventional, has affected the supply patterns, the flows and the rates that can be charged on pipeline systems. The impacts vary among pipelines according to the location and the number of competitors attached to these new supply sources. These changing market dynamics are prompting midstream companies to evaluate the construction of short-haul pipelines as a means of providing demand markets with cost-effective access to newly-developed production regions, as compared to relying on higher-cost, long-haul pipelines that were originally designed to transport natural gas greater distances across the country.

Natural gas storage plays a vital role in maintaining the reliability of gas available for deliveries. Natural gas is typically stored in underground storage facilities, including salt dome caverns, bedded salt caverns and depleted reservoirs. Storage facilities are most often utilized by pipeline companies to manage temporary imbalances in operations; natural gas end-users, such as LDCs, to manage the seasonality and variability of demand and to satisfy future natural gas needs; and, independent natural gas marketing and trading companies in connection with the execution of their trading strategies.

Competition

Our G&P operations compete for customers based on reputation, operating reliability and flexibility, price, creditworthiness, and service offerings, including interconnectivity to producer-desired takeaway options (i.e., processing facilities and pipelines). We face strong competition in acquiring new supplies in the production basins in which we operate, and competition customarily is impacted by the level of drilling activity in a particular geographic region and fluctuations in commodity prices. Our primary competitors include other midstream companies with G&P operations and producer-owned systems, and certain competitors enjoy first-mover advantages over us and may offer producers greater gathering and processing efficiencies, lower operating costs and more flexible commercial terms.

Our NGL supply and logistics business competes primarily with integrated major oil companies, refiners and processors, and other energy companies that own or control transportation and storage assets that can be optimized for supply, marketing and logistics services.

Natural gas storage and pipeline operators compete for customers primarily based on geographic location, which determines connectivity and proximity to supply sources and end-users, as well as price, operating reliability and flexibility, available capacity and service offerings. Our primary competitors in our natural gas storage market include other independent storage providers and major natural gas pipelines with storage capabilities embedded within their transmission systems. Our primary competitors in the natural gas transportation market include major natural gas pipelines and intrastate pipelines that can transport natural gas volumes between interstate systems. Long-haul pipelines often enjoy cost advantages over new pipeline projects with respect to options for delivering greater volumes to existing demand centers, and new projects and expansions proposed from time to time may serve the markets we serve and effectively displace the service we provide to customers.

Our crude oil rail terminals primarily compete with crude oil pipelines and other midstream companies that own and operate rail terminals in the markets we serve. The crude oil logistics business is characterized by strong competition for supplies, and competition is based largely on customer service quality, pricing, and geographic proximity to customers and other market hubs.

Regulation

Our operations and investments are subject to extensive regulation by federal, state and local authorities. The regulatory burden on our operations increases our cost of doing business and, in turn, impacts our profitability. In general, midstream companies have experienced increased regulatory oversight over the past few years. We cannot predict the extent to which this trend will continue in the foreseeable future or in the long term.

Pipeline and Underground Storage Safety

We are subject to pipeline safety regulations imposed by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA regulates safety requirements in the design, construction, operation and maintenance of jurisdictional natural gas and hazardous liquid pipeline and storage facilities. All of our natural gas pipelines used in gathering, storage and transportation activities are subject to regulation by PHMSA under the Natural Gas Pipeline Safety Act of 1968, as amended (NGPSA), and all of our NGL and crude oil pipelines used in gathering, storage and

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transportation activities are subject to regulation by PHMSA as hazardous liquids pipelines under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (HLPSA).

These federal statutes and PHMSA implementing regulations collectively impose numerous safety requirements on pipeline operators, such as the development of a written qualification program for individuals performing covered tasks on pipeline facilities and the implementation of pipeline integrity management programs. For example, pursuant to the authority under the NGPSA and HLPSA, PHMSA has promulgated regulations requiring pipeline operators to develop and implement integrity management programs for certain gas and hazardous liquid pipelines. The integrity management programs govern pipeline operators’ actions in high-consequence areas, such as areas of high population and areas unusually sensitive to environmental damage. Specifically, integrity management programs require more frequent inspections and other preventative measures to ensure pipeline safety in high consequence areas.

We plan to continue testing under our pipeline integrity management programs to assess and maintain the integrity of our pipelines in accordance with PHMSA regulations. Notwithstanding our preventive and investigatory maintenance efforts, we may incur significant expenses if anomalous pipeline conditions are discovered or due to the implementation of more stringent pipeline safety standards resulting from new or amended legislation. For example, the NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act), which requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. More recently, in June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Pipeline Safety Act) was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016, to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act and the 2016 Pipeline Safety Act, as well as any implementation of PHMSA regulations thereunder, or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

Furthermore, PHMSA is considering changes to its natural gas pipeline regulations to, among other things: (i) expand the scope of high consequence areas; (ii) strengthen integrity management requirements applicable to existing operators; (iii) strengthen or expand non-integrity pipeline management standards relating to such matters as valve spacing, automatic or remotely-controlled valves, corrosion protection, and gathering lines; and (iv) add new regulations to govern underground facilities that are not currently subject to federal regulation. See “We may incur higher costs as a result of pipeline integrity management program testing and additional safety legislation,” under Item 1A. Risk Factors for further discussion on PHMSA rulemaking. We cannot predict the final outcome of these legislative or regulatory efforts or the precise impact that compliance with any resulting new safety requirements may have on our business and investments.

Future environmental regulatory developments, such as more strict environmental laws or regulations, or more stringent enforcement of the existing regulatory requirements could also directly affect our operations and investments. For example, in June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage facilities. These standards will require the use of certain specific emissions control practices, thereby requiring additional controls for pneumatic controllers and pumps, as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, in June 2017, the EPA published a proposed rule to stay certain portions of these 2016 standards for two years and reconsider the entirety of the 2016 standards but has not yet published a final rule and, as a result, the 2016 standards are currently in effect.

States are also expected to implement their own rules, which could be more stringent than federal requirements. In matters that could have an indirect adverse effect on our business by decreasing demand for the services that we offer, the EPA has completed a study of potential adverse impacts that certain drilling methods (including hydraulic fracturing) may have on water quality and public health, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Congress has also considered but not adopted, and several states have

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proposed or enacted, legislation or regulations imposing more stringent or costly requirements for exploration and production companies to develop and produce hydrocarbons.

States are largely preempted by federal law from regulating pipeline safety for interstate pipelines, but most states are certified by the Department of Transportation to assume responsibility for enforcing federal intrastate pipeline regulations and inspection of intrastate pipelines. In practice, because states can adopt stricter standards for intrastate pipelines than those imposed by the federal government for interstate pipelines, states vary considerably in their authority and capacity to address pipeline safety. Our pipelines have operations and maintenance plans designed to keep the facilities in compliance with pipeline safety requirements, and we do not anticipate any significant difficulty in complying with applicable state laws and regulations.

Natural Gas Gathering

Natural gas gathering facilities are exempt from FERC jurisdiction under Section 1(b) of the Natural Gas Act. Although the FERC has not made formal determinations with respect to all of our facilities we consider to be gathering facilities, we believe that our natural gas pipelines meet the traditional tests that the FERC has used to determine whether a pipeline is a gathering pipeline, and not subject to FERC jurisdiction. The distinction between FERC-regulated transmission services and federally unregulated gathering services, however, has been the subject of substantial litigation. The FERC determines whether facilities are gathering facilities on a case-by-case basis, so the classification and regulation of our gathering facilities is subject to change based on future determinations by the FERC, the courts or Congress. If the FERC were to consider the status of an individual facility and determine that the facility and/or services provided are not exempt from FERC regulation under the Natural Gas Act and the facility provides interstate service, the rates for, and terms and conditions of, the services provided by such facility would be subject to FERC. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, adversely affect our results of operations and cash flows. In addition, if any of our facilities were found to have provided services or otherwise operated in violation of the Natural Gas Act or the Natural Gas Policy Act, this could result in the imposition of civil penalties, as well as a requirement to disgorge charges collected for such service in excess of the rate established by the FERC.

States may regulate gathering pipelines. State regulation of gathering facilities generally includes various safety, environmental and, in some circumstances, requirements prohibiting undue discrimination, and complaint-based rate regulation. Our natural gas gathering operations may be subject to ratable take and common purchaser statutes in the states in which we operate. These statutes are designed to prohibit discrimination in favor of one producer over another producer, or one source of supply over another source of supply, and generally require our gathering pipelines to take natural gas without undue discrimination as to source of supply or producer. These statutes have the effect of restricting our right as an owner of gathering facilities to decide with whom we contract to purchase or transport natural gas.

The states in which we operate gathering systems have adopted a form of complaint-based regulation, which allows natural gas producers and shippers to file complaints with state regulators in an effort to resolve grievances relating to gathering access and rate discrimination. To date, these regulations have not had an adverse effect on our systems. We cannot predict whether such a complaint will be filed against us in the future, however, a failure to comply with state regulations can result in the imposition of administrative, civil and criminal remedies.

In Texas, we have filed with the Texas Railroad Commission (TRRC) to establish rates and terms of service for certain of our pipelines. Our assets in Texas include intrastate common carrier NGL pipelines subject to the regulation of the TRRC, which requires that our NGL pipelines file tariff publications containing all the rules and the regulations governing the rates and charges for services we perform. NGL pipeline rates may be limited to provide no more than a fair return on the aggregate value of the pipeline property used to render services.

NGL Storage

Our NGL storage terminals are subject primarily to state and local regulation. For example, the Indiana Department of Natural Resources (INDNR) and the New York State Department of Environmental Conservation (NYSDEC) have jurisdiction over the underground storage of NGLs and NGL related well drilling, well conversions and well plugging in Indiana and New York, respectively. Thus, the INDNR regulates aspects of our Seymour facility, and the NYSDEC regulates aspects of the Bath facility, as well as our proposed storage facility near Watkins Glen.

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We filed an application with the NYSDEC in October 2009, for an underground storage permit for our Watkins Glen NGL storage development project. The agency issued a Positive Declaration for the project in November 2010, and determined in August 2011 that the Draft Supplemental Environmental Impact Statement we submitted for the project was complete. In 2012, we modified our brine pond designs in response to local concerns and submitted to the NYSDEC final drawings and plans for our revised project design. The NYSDEC published a draft storage permit in October 2014, and held an issues conference in February 2015, to determine if any significant issues remained that would require an adjudicatory hearing. In September 2016, we further modified our project design (i.e., reduced storage capacity, eliminated truck and rail transportation options, and eliminated brine pond capacity) in response to local concerns and perceptions. In September 2017, the Chief Administrative Law Judge ruled that the opponents of the project failed to raise any issues requiring adjudication. This ruling has been appealed to the NYSDEC Commissioner. As part of the US Salt divestiture, we retained all surface and sub-surface rights necessary to place the Watkins Glen NGL storage development project into service once we receive all required regulatory approvals. We cannot predict with certainty if and when the permitting process will be concluded.

Crude Oil Transportation

The transportation of crude oil by common carrier pipelines on an interstate basis is subject to regulation by the FERC under the Interstate Commerce Act (ICA), the Energy Policy Act of 1992, and the rules and regulations promulgated under those laws. FERC regulations require interstate common carrier petroleum pipelines to file with the FERC and publicly post tariffs stating their interstate transportation rates and terms and conditions of service. The ICA and FERC regulations also require that such rates be just and reasonable, and to be applied in a non-discriminatory manner so as to not confer undue preference upon any shipper. The transportation of crude oil by common carrier pipelines on an intrastate basis is subject to regulation by state regulatory commissions. The basis for intrastate crude oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate crude oil pipeline rates, varies from state to state. Intrastate common carriers must also offer service to all shippers requesting service on the same terms and under the same rates. Our crude oil pipelines in North Dakota are not common carrier pipelines and, therefore, are not subject to rate regulation by the FERC or any state regulatory commission. We cannot, however, provide assurance that the FERC will not, at some point, either at the request of other entities or on its own initiative, assert that some or all of our crude oil pipelines are subject to FERC requirements for common carrier pipelines, or are otherwise not exempt from the FERC’s filing or reporting requirements, or that such an assertion would not adversely affect our results of operations. In the event the FERC were to determine that these crude oil pipelines are subject to FERC requirements for common carrier pipelines, or otherwise would not qualify for a waiver from the FERC’s applicable regulatory requirements, we would likely be required to (i) file a tariff with the FERC; (ii) provide a cost justification for the transportation charge; (iii) provide service to all potential shippers without undue discrimination; and (iv) potentially be subject to fines, penalties or other sanctions.

Certain of our crude oil operations located in North Dakota are subject to state regulation by the North Dakota Industrial Commission (NDIC). For example, gas conditioning requirements established by the NDIC recently will require operators of crude by rail terminals to report to the NDIC any crude volumes received for loading that exceed federal vapor pressure limits. State legislation has been proposed that, if passed, would authorize and require the NDIC to promulgate regulations under which produced water pipelines would be required to, among other things, install leak detection facilities and post bonds to cover potential remediation costs associated with releases. Moreover, the regulation of our customers’ production activities by the NDIC impacts our operations. For example, during 2016, the NDIC approved additional requirements relating to site construction, underground gathering pipelines and spill containment that became effective on October 1, 2016, while other requirements relating to bonding for underground gathering pipelines, and construction of berms around facilities became effective on January 1, 2017. Additionally, on July 1, 2014, the NDIC issued an order pursuant to which the agency adopted legally enforceable “gas capture percentage goals” targeting the capture of certain percentages of natural gas produced in the state by specified dates, and subsequently modified that order in late 2015. Exploration and production operators in the state may be required to install new equipment to satisfy these goals, and any failure by operators to meet these gas capture percentage goals would subject those operators to production restrictions, which could reduce the amount of commodities we gather on the Arrow system from our customers, and have a corresponding adverse impact on our business and results of operations.

Portions of our Arrow gathering system, which is located on the Fort Berthold Indian Reservation, may be subject to applicable regulation by the Mandan, Hidatsa & Arikara Nation (MHA Nation). An entirely separate and distinct set of laws and regulations may apply to operators and other parties within the boundaries of the Fort Berthold Indian Reservation. Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, the Office of Natural Resources Revenue and the Bureau of Land Management (BLM) promulgate and enforce regulations pertaining to oil and gas operations on Native American lands. These regulations include lease provisions, environmental standards, tribal employment preferences and numerous other matters.

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Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and BLM. However, Native American tribes possess certain inherent authorities to enact and enforce their own internal laws and regulations as long as such laws and regulations do not supersede or conflict with such federal statutes. These tribal laws and regulations may include various fees, taxes, and requirements to extend preference in employment to tribal members or Indian owned businesses. Further, lessees and operators within a Native American reservation may be subject to the pertinent Native American judiciary system, or barred from litigating matters adverse to the pertinent tribe unless there is a specific waiver of the tribe’s sovereign immunity. Therefore, we may be subject to various applicable laws and regulations pertaining to Native American oil and gas leases, fees, taxes and other burdens, obligations and issues unique to oil and gas operations within Native American reservations. One or more of these applicable regulatory requirements, or delays in obtaining necessary approvals or permits necessary to operate on tribal lands, may increase our costs of doing business on Native American tribal lands and have an impact on the economic viability of any well or project with a Native American reservation. Additionally, we cannot guarantee that we will always be able to renew existing rights-of-way or obtain new rights-of-way in Native American lands without experiencing significant costs. For example, following a recent decision issued in May 2017 by the Federal Tenth Circuit Court of Appeals that relied, in part, on a previous Federal Eighth Circuit Court of Appeals decision, tribal ownership of even a very small fractional interest in an allotted land, that is, tribal land owned or at one time owned by an individual Native American landowner, bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators.

In recent years, PHMSA and other federal agencies have reviewed the adequacy of transporting Bakken crude oil by rail transport and, as necessary have pursued rules to better assure the safe transport of Bakken crude oil by rail. For example, in May 2015, PHMSA adopted a final rule that includes, among other things, providing new sampling and testing requirements to improve classification of Bakken crude oil transported.  Additional proposed and final rules issued by PHMSA in July 2016 and August 2016, respectively, mandate a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol, between 2018 and 2029, and may expand the applicability of comprehensive oil spill response plans so that any railroad transporting a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train will have to have a current, comprehensive, written plan. We, as the owner of a Bakken crude loading terminal, may be adversely affected to the extent more stringent rail transport rules result in more significant operating costs in the shipment of Bakken crude oil by rail or as a result of delays or limitations of such shipments. 

Natural Gas Storage and Transportation

Our equity investments’ natural gas pipelines used in gathering, storage and transportation activities are subject to regulation under NGPSA, and all of our equity investments’ crude oil pipelines used in gathering, storage and transportation activities are subject to regulation under HLPSA. On December 14, 2016, PHMSA issued final interim rules that impose new safety related requirements on downhole facilities (including wells, wellbore tubing and casing) of new and existing underground natural gas storage facilities. The final interim rules adopt and make mandatory two American Petroleum Institute Recommend Practices that, among other things, address construction, maintenance, risk-management and integrity-management procedures. PHMSA indicated when it issued the interim final rule that the adoption of these safety standards for natural gas storage facilities represent a first step in a multi-phase process to enhance the safety of underground natural gas storage, with more standards likely forthcoming. Most recently, in response to a petition for reconsideration of the interim final rule received in January 2017, PHMSA published a notice in June 2017, advising that the agency intends to consider the issues raised by the petitioners in a final rule, which it currently expects to issue in 2018. At this time, we cannot predict the impact of any future regulatory actions in this area. To the extent we operate or manage natural gas storage facilities owned by our equity investments, we are evaluating the final interim rules and their potential impact on our equity investments. PHMSA’s interim final rules could significantly increase the costs of operating and maintaining natural gas storage facilities.

The interstate natural gas storage and transportation operations of our equity investments are subject to regulation by the FERC under the Natural Gas Act. Subsidiaries of our Stagecoach Gas and Tres Holdings joint ventures are regulated by the FERC as natural gas companies. Under the Natural Gas Act, the FERC has authority to regulate gas transportation services in interstate commerce, which includes natural gas storage services. The FERC exercises jurisdiction over (i) rates charged for services and the terms and conditions of service; (ii) the certification and construction of new facilities; (iii) the extension or abandonment of services and facilities; (iv) the maintenance of accounts and records; (v) the acquisition and disposition of facilities; (vi) standards of conduct between affiliated entities; and (vii) various other matters. Regulated natural gas companies are prohibited from charging rates determined by the FERC to be unjust, unreasonable, or unduly discriminatory, and both the existing tariff rates and the proposed rates of regulated natural gas companies are subject to challenge.

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The rates and terms and conditions of our natural gas storage and transportation equity investments are found in the FERC-approved tariffs of (i) Stagecoach Pipeline & Storage Company LLC (Stagecoach Pipeline), a wholly-owned subsidiary of Stagecoach Gas that owns the Stagecoach natural gas storage facility, the North-South Facilities and the MARC I Pipeline, (ii) Arlington Storage Company, LLC (Arlington Storage), a wholly-owned subsidiary of Stagecoach Gas that owns the Thomas Corners, Seneca Lake and Steuben natural gas storage facilities, and (iii) Tres Palacios, a wholly-owned subsidiary of Tres Holdings that owns the Tres Palacios natural gas storage facility. Stagecoach Pipeline, Arlington Storage and Tres Palacios are authorized to charge and collect market-based rates for storage services, and Stagecoach Pipeline is authorized to charge and collect negotiated rates for transportation services. Market-based and negotiated rate authority allows our equity investments to negotiate rates with individual customers based on market demand. A loss of market-based or negotiated rate authority or any successful complaint or protest against the rates charged or provided by our equity investments could have an adverse impact on our results of operations.

In addition, the Energy Policy Act of 2005 amended the Natural Gas Act to (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, and FERC rules, regulations or orders thereunder. As a result of the Energy Policy Act of 2005, the FERC has the authority to impose civil penalties for violations of these statutes and FERC rules, regulations and orders, up to approximately $1.2 million per day per violation.

The interstate natural gas storage operations of our equity investments are also subject to non-rate regulation by various state agencies. For example, the NYSDEC has jurisdiction over well drilling, conversion and plugging in New York.  The NYSDEC, therefore, regulates aspects of the Stagecoach, Thomas Corners, Seneca Lake and Steuben natural gas storage facilities.

Supply and Logistics

The transportation of crude oil, water and NGLs by truck is subject to regulations promulgated under the Federal Motor Carrier Safety Act. These regulations, which are administered by the United States Department of Transportation, cover the transportation of hazardous materials.

Environmental and Occupational Safety and Health Matters

Our operations and investments are subject to stringent federal, state, regional and local laws and regulations governing the discharge and emission of pollutants into the environment, environmental protection, or occupational health and safety. These laws and regulations may impose significant obligations on our operations, including (i) the need to obtain permits to conduct regulated activities; (ii) restrict the types, quantities and concentration of materials that can be released into the environment; (iii) apply workplace health and safety standards for the benefit of employees; (iv) require remedial activities or corrective actions to mitigate pollution from former or current operations; and (v) impose substantial liabilities on us for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the (i) assessment of sanctions, including administrative, civil and criminal penalties; (ii) imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; (iii) occurrence of delays in permitting or the development of projects; and (iv) issuance of injunctions restricting or prohibiting some or all of the activities in a particular area.

The following is a summary of the more significant existing federal environmental laws and regulations, each as amended from time to time, to which our business operations and investments are subject:

• The Comprehensive Environmental Response, Compensation and Liability Act, a remedial statute that imposes strict liability on generators, transporters and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;

• The Resource Conservation and Recovery Act, which governs the treatment, storage and disposal of non-hazardous and hazardous wastes;

• The Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring and reporting requirements and which serves as a legal basis for the EPA to adopt climate change regulatory initiatives relating to greenhouse gas (GHG) emissions;

• The Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters;

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• The Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of substances into below-ground formations that may adversely affect drinking water sources;

• The National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments or the more detailed Environmental Impact Statements, may be made available for public review and comment;

• The Endangered Species Act, which restricts activities that may affect federally identified endangered or threatened species, or their habitats through the implementation of operating restrictions or a temporary, seasonal, or permanent ban in affected areas; and

• The Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances in the workplace, potential harmful effects of these substances, and appropriate control measures.

Certain of these federal environmental laws, as well as their state counterparts, impose strict, joint and several liability for costs required to clean up and restore properties where pollutants have been released regardless of whom may have caused the harm or whether the activity was performed in compliance with all applicable laws. 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. In addition, many of the properties owned or leased by us were previously operated by third parties whose management, disposal or release of materials and wastes was not under our control. Accordingly, we may be liable for the costs of cleaning up or remediating contamination arising out of our operations or as a result of activities by others who previously occupied or operated on properties now owned or leased by us. Private parties, including the owners of properties that we lease and facilities where our materials or wastes are taken for recycling or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. We may not be able to recover some or any of these additional costs from insurance.

During 2014, we experienced three releases on our Arrow produced water gathering system that resulted in approximately 28,000 barrels of produced water being released on lands within the boundaries of the Fort Berthold Indian Reservation. In May 2015, we experienced another release of approximately 5,200 barrels of produced water. We have substantially completed our remediation efforts for the spills, and we believe our remediation costs will be recoverable under our insurance policies.

In April 2015, the EPA issued a Notice of Potential Violation (NOPV) under the Clean Water Act relating to the largest of the 2014 water releases. We responded to the NOPV in May 2015, and in April 2017, we entered into an Administrative Order on Consent (the Order) with the EPA. The Order requires us to continue to remediate and monitor the impacted area for no less than four years unless all goals of the Order are satisfied earlier. On December 13, 2017, the EPA and Crestwood signed a Combined Complaint and Consent Agreement (CCCA) whereby we agreed to pay a civil penalty of $49,000 to the EPA and purchase emergency response equipment at an estimated cost of approximately $173,000 for the Three Affiliated Tribes as a Supplemental Environmental Project (SEP). The CCCA and SEP concludes the EPA’s penalty phase related to this matter.

In March 2015, we received a grand jury subpoena from the United States Attorney’s Office in Bismarck, North Dakota, seeking documents and information relating to the largest of the three 2014 water releases. In September 2017, we received a notice from the United States Department of Justice that it completed the investigation with no charges being filed against us.

In August 2015, we received a notice of violation from the Three Affiliated Tribes’ Environmental Division related to our 2014 produced water releases on the Fort Berthold Indian Reservation. The notice of violation imposes fines and requests reimbursements exceeding $1.1 million; however, the notice of violation was stayed in September 2015, upon our posting of a performance bond for the amount contemplated by the notice and pending the outcome of settlement discussions with the EPA related to the NOPV. Although we continue to have productive settlement conversations with the Tribe, we cannot predict if or when we will be able to settle the dispute.

Employees

As of February 9, 2018, we had 954 full-time employees, 298 of which were general and administrative employees and 656 of which were operational. We believe that our relationship with our employees is satisfactory.

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Available Information

Our website is located at www.crestwoodlp.com. We make available, free of charge, on or through our website our annual reports on Form 10-K, which include our audited financial statements, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act as soon as we electronically file such material with the SEC. These documents are also available, free of charge, at the SEC’s website at www.sec.gov. In addition, copies of these documents, excluding exhibits, may be requested at no cost by contacting Investor Relations, Crestwood Equity Partners LP or Crestwood Midstream Partners LP, 811 Main Street, Suite 3400, Houston, Texas 77002, and our telephone number is (832) 519-2200.

We also make available within the “Corporate Governance” section of our website our corporate governance guidelines, the charter of our Audit Committee and our Code of Business Conduct and Ethics. Requests for copies may be directed in writing to Crestwood Equity Partners LP, 811 Main Street, Suite 3400, Houston, Texas 77002, Attention: General Counsel. Interested parties may contact the chairperson of any of our Board committees, our Board’s independent directors as a group or our full Board in writing by mail to Crestwood Equity Partners LP, 811 Main Street, Suite 3400, Houston, Texas 77002, Attention: General Counsel. All such communications will be delivered to the director or directors to whom they are addressed.

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Item 1A. Risk Factors

Risks Inherent in Our Business

Our business depends on hydrocarbon supply and demand fundamentals, which can be adversely affected by numerous factors outside of our control.

Our success depends on the supply and demand for natural gas, NGLs and crude oil, which has historically generated the need for new or expanded midstream infrastructure. The degree to which our business is impacted by changes in supply or demand varies. Our business can be negatively impacted by sustained downturns in supply and demand for one or more commodities, including reductions in our ability to renew contracts on favorable terms and to construct new infrastructure. For example, although capital investment in certain areas may have increased as crude oil prices improved in throughout 2017 and early 2018, significantly lower commodity prices during the past few years have resulted in an industry-wide reduction in capital expenditures by producers and a slowdown in drilling, completion and supply development efforts. Notwithstanding this market downturn, production volumes of crude oil, natural gas and NGLs have continued to grow (or decline at a slower rate than expected). Similarly major factors that will impact natural gas demand domestically will be the realization of potential liquefied natural gas exports and demand growth within the power generation market. Factors expected to impact crude oil demand include the lifting of the United States’ crude oil export ban and production cuts and freezes implemented by Organization of the Petroleum Exporting Countries (OPEC) members and Russia. In addition, the supply and demand for natural gas, NGLs and crude oil for our business will depend on many other factors outside of our control, some of which include:

• adverse changes in general global economic conditions;

• adverse changes in domestic regulations that could impact the supply or demand for oil and gas;

• technological advancements that may drive further increases in production and reduction in costs of developing shale plays;

• competition from imported supplies and alternate fuels;

• commodity price changes, including the recent decline in crude oil and natural gas prices, that could negatively impact the supply of, or the demand for these products;

• increased costs to explore for, develop, produce, gather, process or transport commodities;

• shareholder activism and activities by non-governmental organizations to limit sources of funding for the energy sector or restrict the exploration, development and production of oil and gas:

• adoption of various energy efficiency and conservation measures; and

• perceptions of customers on the availability and price volatility of our services, particularly customers’ perceptions on the volatility of commodity prices over the longer-term.

If volatility and seasonality in the oil and gas industry decrease, because of increased production capacity or otherwise, the demand for our services and the prices that we will be able to charge for those services may decline. In addition to volatility and seasonality, an extended period of low commodity prices, as the industry is currently experiencing, could adversely impact storage and transportation values for some period of time until market conditions adjust. With West Texas Intermediate crude oil prices ranging from $42.53 to $60.42 per barrel in 2017, the sustainability of recent prices improvements and longer-term oil prices cannot be predicted. These commodity price impacts could have a negative impact on our business, financial condition, and results of operations.

Our future growth may be limited if commodity prices remain low, resulting in a prolonged period of reduced midstream infrastructure development and service requirements to customers.

Our business strategy depends on our ability to provide increased services to our customers and develop growth projects that can be financed appropriately. We may be unable to complete successful, accretive growth projects for any of the following reasons, among others:

• we fail to identify (or we are outbid for) attractive expansion or development projects or acquisition candidates that satisfy our economic and other criteria;

• we fail to secure adequate customer commitments to use the facilities to be developed, expanded or acquired; or

• we cannot obtain governmental approvals or other rights, licenses or consents needed to complete such projects or acquisitions on time or on budget, if at all.

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The development and construction of gathering, processing, storage and transportation facilities involves numerous regulatory, environmental, safety, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. When we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular growth project. For instance, if we build a new gathering system, processing plant or transmission pipeline, the construction may occur over an extended period of time and we will not receive material increases in revenues until the project is placed in service. Accordingly, if we do pursue growth projects, we can provide no assurances that our efforts will provide a platform for additional growth for our company.

Our ability to finance new growth projects and make capital expenditures may be limited by our access to the capital markets or ability to raise investment capital at a cost of capital that allows for accretive midstream investments.

The significant decline in energy commodity prices in recent years has led to an increased concern by energy investors regarding the future outlook for the industry. This has resulted in a historic decline in equity and debt valuations in the publicly traded capital markets as well as increased trading volatility. As a result, our publicly traded common units experienced a decrease in value, primarily during 2015 and 2016, with a corresponding increase in yield resulting in a higher cost of capital than we have historically experienced. Our growth strategy depends on our ability to identify, develop and contract for new growth projects and raise the investment capital, at a reasonable cost of capital, required to generate accretive returns from the growth project. This trend may continue and could negatively impact our ability to grow for any of the following reasons:

• access to the public equity and debt markets for partnerships of similar size to us may limit our ability to raise new equity and debt capital to finance new growth projects;

• if market conditions deteriorate below current levels, it is unlikely that we could issue equity at costs of capital that would enable us to invest in new growth projects on an accretive basis; or

• we cannot raise financing for such projects or acquisitions on economically acceptable terms.

The growth projects we complete may not perform as anticipated.

Even if we complete growth projects that we believe will be strategic and accretive, such projects may nevertheless reduce our cash available for distribution due to the following factors, among others:

• mistaken assumptions about capacity, revenues, synergies, costs (including operating and administrative, capital, debt and equity costs), customer demand, growth potential, assumed liabilities and other factors;

• the failure to receive cash flows from a growth project or newly acquired asset due to delays in the commencement of operations for any reason;

• unforeseen operational issues or the realization of liabilities that were not known to us at the time the acquisition or growth project was completed;

• the inability to attract new customers or retain acquired customers to the extent assumed in connection with an acquisition or growth project;

• the failure to successfully integrate growth projects or acquired assets or businesses into our operations and/or the loss of key employees; or

• the impact of regulatory, environmental, political and legal uncertainties that are beyond our control.

In particular, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations and ability to make distributions.

If we complete future growth projects, our capitalization and results of operations may change significantly, and you will not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources. If any growth projects we ultimately complete are not accretive to our cash available for distribution, our ability to make distributions may be reduced.

We may rely upon third-party assets to operate our facilities, and we could be negatively impacted by circumstances beyond our control that temporarily or permanently interrupt the operation of such third-party assets.

Certain of our operations and investments depend on assets owned and controlled by third parties to operate effectively. For example, (i) certain of our “rich gas” gathering systems depend on interconnections, compression facilities and processing plants owned by third parties for us to move gas off our systems; (ii) our crude oil gathering systems depend on third-party

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pipelines to move crude to demand markets or rail terminals and our crude oil rail terminals depend on railroad companies to move our customers’ crude oil to market; and (iii) our natural gas storage facilities rely on third-party interconnections and pipelines to receive and deliver natural gas. Since we do not own or operate these third-party facilities, their continuing operation is outside of our control. If third-party facilities become unavailable or constrained, or other downstream facilities utilized to move our customers’ product to their end destination become unavailable, it could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions.

In addition, the rates charged by processing plants, pipelines and other facilities interconnected to our assets affect the utilization and value of our services. Significant changes in the rates charged by these third parties, or the rates charged by the third parties that own “downstream” assets required to move commodities to their final destinations, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

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. If as a result of market conditions, certain of our producer customers levered to shale production reduce capital spending (or continue capital spending levels lower than historical levels) and/or shut in production for economic reasons, this could result in lower revenues for us. In the event that market conditions deteriorate, this could lead to the loss of a significant customer, which could also cause a significant decline in our revenues. In addition, to the extent our producer customers have weathered the challenges of lower commodity prices over the past few years, we cannot provide any assurance that they will remain viable over a longer period of lower commodity prices.

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

Energy commodity prices have declined substantially since 2014 due to a wide range of factors, including a continuing growth of supply, slowdown or decline in demand, and challenges in economic, financial and monetary markets. Sustained low natural gas, NGL and crude oil prices have recently negatively impacted natural gas and oil exploration and production activity levels industry-wide and in the areas we operate. A continued slowdown in activity can result in a decline in the production of hydrocarbons over time, resulting in reduced throughput on our systems, plants, trucks and terminals. Such a decline could also potentially affect the ability of our customers to continue their operations. As a result, sustained low natural gas and crude oil prices could have a material adverse effect on our business, results of operations, and financial condition. In general, the prices of natural gas, oil, condensate, NGLs and other hydrocarbon products fluctuate in response to changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control.

Our gathering and processing operations depend, in part, on drilling and production decisions of others.

Our gathering and processing operations are dependent on the continued availability of natural gas and crude oil production. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems, or the rate at which production from a well declines. Our gathering systems are connected to wells whose production will naturally decline over time, which means that our cash flows associated with these wells will decline over time. To maintain or increase throughput levels on our gathering systems and utilization rates at our natural gas processing plants, we must continually obtain new natural gas and crude oil supplies. Our ability to obtain additional sources of natural gas and crude oil primarily depends on the level of successful drilling activity near our systems, our ability to compete for volumes from successful new wells, and our ability to expand our system capacity as needed. If we are not able to obtain new supplies of natural gas and crude oil to replace the natural decline in volumes from existing wells, throughput on our gathering and processing facilities would decline, which could have a material adverse effect on our results of operations and distributable cash flow.

Although we have acreage dedications from customers that include certain producing and non-producing oil and gas properties, our customers are not contractually required to develop the reserves and or properties they have dedicated to us. We have no control over producers or their drilling and production decisions in our areas of operations, which are affected by, among other things, (i) the availability and cost of capital; (ii) prevailing and projected commodity prices; (iii) demand for natural gas, NGLs and crude oil; (iv) levels of reserves and geological considerations; (v) governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; and (vi) the availability of drilling rigs and other development services. Fluctuations in energy prices can also greatly affect the development of oil and gas reserves. Drilling and production activity generally decreases as commodity prices decrease, and sustained declines in commodity prices could lead to a material decrease in such activity. Because of these factors, even if oil and gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. Reductions in exploration or production activity in our areas of operations could lead to reduced utilization of our systems.

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Estimates of oil and gas reserves depend on many assumptions that may turn out to be inaccurate, and future volumes on our gathering systems may be less than anticipated.

We normally do not obtain independent evaluations of natural gas or crude oil reserves connected to our gathering systems. We therefore do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. It often takes producers longer periods of time to determine how to efficiently develop and produce hydrocarbons from unconventional shale plays than conventional basins, which can result in lower volumes becoming available as soon as expected in the shale plays in which we operate. If the total reserves or estimated life of the reserves connected to our gathering systems is less than anticipated and we are unable to secure additional sources of natural gas or crude oil, it could have a material adverse effect on our business, results of operations and financial condition.

We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flows and results of operations.

Many of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flows from operations, the incurrence of debt or the issuance of equity. The combination of the reduction of cash flows resulting from declines in commodity prices, a reduction in borrowing bases under reserve-based credit facility and the lack of availability of debt or equity financing may result in a significant reduction of customers’ liquidity and limit their ability to make payments or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues.

Our marketing, supply and logistics operations are seasonal and generally have lower cash flows in certain periods during the year, which may require us to borrow money to fund our working capital needs of these businesses.

The natural gas liquids inventory we pre-sell to our customers is higher during the second and third quarters of a given year, and our cash receipts during that period are lower. As a result, we may have to borrow money to fund the working capital needs of our marketing, supply and logistics operations during those periods. Any restrictions on our ability to borrow money could impact our ability to pay quarterly distributions to our unitholders.

Counterparties to our commodity derivative and physical purchase and sale contracts in our marketing, supply and logistics operations may not be able to perform their obligations to us, which could materially affect our cash flows and results of operations.

We encounter risk of counterparty non-performance in our marketing, supply and logistics operations. Disruptions in the price or supply of NGLs for an extended or near term period of time could result in counterparty defaults on our derivative and physical purchase and sale contracts. This could impair our expected earnings from the derivative or physical sales contracts, our ability to obtain supply to fulfill our sales delivery commitments or our ability to obtain supply at reasonable prices, which could result adversely affect our financial condition and results of operations.

Our marketing, supply and logistics operations are subject to commodity risk, basis risk, or risk of adverse market conditions, which can adversely affect our financial condition and results of operations.

We attempt to lock in a margin for a portion of the commodities we purchase by selling such commodities for physical delivery to our customers or by entering into future delivery obligations under contracts for forward sale. Through these transactions, we seek to maintain a position that is substantially balanced between purchases, and sales or future delivery obligations. Any event that disrupts our anticipated physical supply of commodities could expose us to risk of loss resulting from the need to fulfill our obligations required under contracts for forward sale. Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of basis risk. In a backwardated market (when prices for future deliveries are lower than current prices), basis risk is created with respect to timing. In these instances, physical inventory generally loses value as the price of such physical inventory declines over time. Basis risk cannot be entirely eliminated, and basis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our financial condition and results of operations.

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Changes in future business conditions could cause recorded long-lived assets and goodwill to become further impaired, and our financial condition and results of operations could suffer if there is an additional impairment of long-lived assets and goodwill.

We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value of our assets based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. This differs from our evaluation of goodwill, which is evaluated 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 the carrying amount. This evaluation requires us to compare the fair value of each of our reporting units primarily utilizing discounted cash flows, to its carrying value (including goodwill). If the fair value exceeds the carrying value amount, goodwill of the reporting unit is not considered impaired.

Under GAAP, during the years ended December 31, 2017, 2016 and 2015, we were required to record $121.0 million, $194.0 million and $2,223.8 million of long-lived asset and goodwill impairments related to certain of our reporting units because changes in circumstances or events (of which one of the several indicators of impairment was considered jointly is a significant and other than temporary decrease in our market capitalization) indicated that the carrying values of such assets exceeded their fair value and were not recoverable.

Our long-lived assets and goodwill impairment analyses are sensitive to changes in key assumptions used in our analysis, such as expected future cash flows, the degree of volatility in equity and debt markets and our unit price. If the assumptions used in our analysis are not realized, it is possible a material impairment charge may need to be recorded in the future. We cannot accurately predict the amount and timing of any impairment of long-lived assets or goodwill. Further, as we work toward a turnaround of our business, we will need to continue to evaluate the carrying value of our goodwill. Any additional impairment charges that we may take in the future could be material to our results of operations and financial condition. For a further discussion of our long-lived assets and goodwill impairments, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

Our industry is highly competitive, and increased competitive pressure could adversely affect our ability to execute our growth strategy.

We compete with other energy midstream enterprises, some of which are much larger and have significantly greater financial resources or operating experience, in our areas of operation. Our competitors may expand or construct infrastructure that creates additional competition for the services we provide to customers. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions.

Our level of indebtedness could adversely affect our ability to raise additional capital to fund operations, limit our ability to react to changes in our business or industry, and place us at a competitive disadvantage.

We had approximately $1.5 billion of long-term debt outstanding as of December 31, 2017. Our inability to generate sufficient cash flow to satisfy debt obligations or to obtain alternative financing could materially and adversely affect our business, results of operations, financial condition and business prospects.

Our substantial debt could have important consequences to our unitholders. For example, it could:

• increase our vulnerability to general adverse economic and industry conditions;

• limit our ability to fund future capital expenditures and working capital, to engage in development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive covenants or terms of our debt;

• result in an event of default if we fail to satisfy debt obligations or fail to comply with the financial and other restrictive covenants contained in the agreements governing our indebtedness, which event of default could result in all of our debt becoming immediately due and payable and could permit our lenders to foreclose on any of the collateral securing such debt;

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• require a substantial portion of cash flow from operations to be dedicated to the payment of principal and interest on our indebtedness, therefore reducing our ability to use cash flow to fund operations, capital expenditures and future business opportunities;

• increase our cost of borrowing;

• restrict us from making strategic acquisitions or investments, or cause us to make non-strategic divestitures;

• limit our flexibility in planning for, or reacting to, changes in our business or industry in which we operate, placing us at a competitive disadvantage compared to our peers who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploring; and

• impair our ability to obtain additional financing in the future.

Realization of any of these factors could adversely affect our financial condition, results of operations and cash flows.

Restrictions in our revolving credit facility and indentures governing our senior notes could adversely affect our business, financial condition, results of operations and ability to make distributions.

Our revolving credit facility and indentures governing our senior notes contain various covenants and restrictive provisions that will limit our ability to, among other things:

• incur additional debt;

• make distributions on or redeem or repurchase units;

• make investments and acquisitions;

• incur or permit certain liens to exist;

• enter into certain types of transactions with affiliates;

• merge, consolidate or amalgamate with another company; and

• transfer or otherwise dispose of assets.

Furthermore, our revolving credit facility contains covenants which requires us to maintain certain financial ratios such as (i) a net debt to consolidated EBITDA ratio (as defined in the credit agreement) of not more than 5.50 to 1.0; (ii) a consolidated EBITDA to consolidated interest expense ratio (as defined in our credit agreement) of not less than 2.50 to 1.0, and (iii) a senior secured leverage ratio (as defined in its credit agreement) of not more than 3.75 to 1.0.

Borrowings under our revolving credit facility are secured by pledges of the equity interests of, and guarantees by, substantially all of our restricted domestic subsidiaries, and liens on substantially all of our real property (outside of New York) and personal property. None of our equity investments have guaranteed, and none of the assets of our equity investments secure, our obligations under our revolving credit facility.

The provisions of our credit agreement and indentures governing our senior notes may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility or indentures governing our senior notes could result in events of default, which could enable our lenders or holders of our senior notes, subject to the terms and conditions of our credit agreement or indentures, as applicable, to declare any outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If the payment of any such debt is accelerated, our assets may be insufficient to repay such debt in full, and the holders of our common units could experience a partial or total loss of their investment.

A change of control could result in us facing substantial repayment obligations under our revolving credit facility and indentures governing our senior notes.

Our credit agreement and indentures governing our senior notes contain provisions relating to change of control of Crestwood Equity’s general partner. If these provisions are triggered, our outstanding indebtedness may become due. In such an event, there is no assurance that we would be able to pay the indebtedness, in which case the lenders under the revolving credit facility would have the right to foreclose on our assets and holders of our senior notes would be entitled to require us to repurchase all or a portion of our notes at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of such repurchase, which would have a material adverse effect on us. There is no restriction on our ability or the ability of Crestwood Equity’s general partner or its parent companies to enter into a transaction which would trigger the change of control provision. In certain circumstances, the control of our general partner may be transferred to a third party without unitholder consent, and this may be considered a change in control under our revolving credit facility and senior notes. Please read “The control of our general partner may be transferred to a third party without unitholder consent.”

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Our ability to make cash distributions may be diminished, and our financial leverage could increase, if we are not able to obtain needed capital or financing on satisfactory terms.

Historically, we have used cash flow from operations, borrowings under our revolving credit facilities and issuances of debt or equity to fund our capital programs, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our operations to fund growth. If our cash flow from operations decreases or distributions from our equity investments decrease as a result of lower throughput volumes on our systems or otherwise, our ability to expend the capital necessary to expand our business or increase our future cash distributions may be limited. If our cash flow from operations and the distributions we receive from subsidiaries are insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition or general economic conditions at the time of any such financing or offering. Even if we are successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Further, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the cash distribution rate which could materially decrease our ability to pay distributions. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis.

Increases in interest rates could adversely impact our unit price, ability to issue equity or incur debt for acquisitions or other purposes, and ability to make payments on our debt obligations.

Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Therefore, changes in interest rates either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make payments on our debt obligations.

The loss of key personnel could adversely affect our ability to operate.

Our success is dependent upon the efforts of our senior management team, as well as on our ability to attract and retain both executives and employees for our field operations. Our senior executives have significant experience in the oil and gas industry and have developed strong relationships with a broad range of industry participants. The loss of these executives, or the loss of key field employees operating in competitive markets, could prevent us from implementing our business strategy and could have a material adverse effect on our customer relationships, results of operations and ability to make distributions.

We operate joint ventures that may limit our operational flexibility.

We conduct a meaningful portion of our operations through joint ventures (including our Crestwood Permian, Jackalope, PRBIC, Stagecoach Gas and Tres Palacios joint ventures), and we may enter into additional joint ventures in the future. In a joint venture arrangement, we could have less operational flexibility, as actions must be taken in accordance with the applicable governing provisions of the joint venture. In certain cases, we:

• could have limited ability to influence or control certain day to day activities affecting the operations;

• could have limited control on the amount of capital expenditures that we are required to fund with respect to these operations;

• could be dependent on third parties to fund their required share of capital expenditures;

• may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets; and

• may be required to offer business opportunities to the joint venture, or rights of participation to other joint venture members, participants in certain areas of mutual interest.

In addition, joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture. The performance and ability of our joint venture partners to satisfy their obligations under joint venture arrangements is outside of our control. If these parties do not satisfy their obligations, our business may be adversely affected. Our joint venture partners may be in a position to take actions contrary to our instructions or requests or contrary to our policies or objectives, and disputes between us and our joint venture partners may result in delays, litigation or operational impasses. The risks described above or the failure to continue our joint

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ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to conduct business that is the subject of a joint venture, which could in turn negatively affect our financial condition and results of operations.

Moreover, our decision to operate aspects of our business through joint ventures could limit our ability to consummate strategic transactions. Similarly, due to the perceived challenges of existing joint ventures, companies like ours that fund a considerable portion of their operations through joint ventures may be less attractive merger or take-over candidates. We cannot provide any assurance that our operating model will not negatively affect the value of our common units.

We may not be able to renew or replace expiring contracts.

Our primary exposure to market risk occurs at the time contracts expire and are subject to renegotiation and renewal. As of December 31, 2017, the weighted average remaining term of our consolidated portfolio of natural gas gathering contracts is approximately 10 years, and our consolidated portfolio of crude oil gathering contracts is approximately nine years. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

• the macroeconomic factors affecting natural gas, NGL and crude economics for our current and potential customers;

• the level of existing and new competition to provide services to our markets;

• the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;

• the extent to which the customers in our markets are willing to contract on a long-term basis; and

• the effects of federal, state or local regulations on the contracting practices of our customers.

Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

The fees we charge to customers under our contracts may not escalate sufficiently to cover our cost increases, and those contracts may be suspended in some circumstances.

Our costs may increase at a rate greater than the rate that the fees we charge to third parties increase pursuant to our contracts with them. In addition, some third parties’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas or crude oil is curtailed or cut off. Force majeure events generally include, without limitation, revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, acts of God, explosions, mechanical or physical failures of our equipment or facilities or those of third parties. If our escalation of fees is insufficient to cover increased costs or if any third party suspends or terminates its contracts with us, our business, financial condition, results of operations and ability to make distributions could be materially adversely affected.

Our operations are subject to extensive regulation, and regulatory measures adopted by regulatory authorities could have a material adverse effect on our business, financial condition and results of operations.

Our operations, including our joint ventures, are subject to extensive regulation by federal, state and local regulatory authorities. For example, because Stagecoach Gas transports natural gas in interstate commerce and stores natural gas that is transported in interstate commerce, Stagecoach Gas’ natural gas storage and transportation facilities are subject to comprehensive regulation by the FERC under the Natural Gas Act. Federal regulation under the Natural Gas Act extends to such matters as: 

•rates, operating terms and conditions of service;

• the form of tariffs governing service;

• the types of services we may offer to our customers;

• the certification and construction of new, or the expansion of existing, facilities;

• the acquisition, extension, disposition or abandonment of facilities;

• contracts for service between storage and transportation providers and their customers;

• creditworthiness and credit support requirements;

• the maintenance of accounts and records;

• relationships among affiliated companies involved in certain aspects of the natural gas business;

• the initiation and discontinuation of services; and

• various other matters.

 Natural gas companies may not charge rates that, upon review by the FERC, are found to be unjust and unreasonable or unduly discriminatory. Existing interstate transportation and storage rates may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases proposed by a regulated pipeline or storage provider may be

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challenged and such increases may ultimately be rejected by the FERC. Stagecoach Gas has authority from the FERC to charge and collect (i) market-based rates for interstate storage services provided at the Stagecoach, Thomas Corners, Seneca Lake and Steuben facilities and (ii) negotiated rates for interstate transportation services provided by the North-South Facilities and MARC I Pipeline. The FERC has authorized Tres Palacios to charge and collect market-based rates for interstate storage services provided by its natural gas facilities. The FERC’s “market-based rate” policy allows regulated entities to charge rates different from, and in some cases, less than, those which would be permitted under traditional cost-of-service regulation. Among the sorts of changes in circumstances that could raise market power concerns would be an expansion of capacity, acquisitions or other changes in market dynamics. There can be no guarantee that our joint ventures will be allowed to continue to operate under such rate structures for the remainder of their assets’ operating lives. Any successful challenge against rates charged for their storage and transportation services, or their loss of market-based rate authority or negotiated rate authority, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

There can be no assurance that the FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. Failure to comply with applicable regulations under the Natural Gas Act, the Natural Gas Policy Act of 1978, the Pipeline Safety Act of 1968 and certain other laws, and with implementing regulations associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to approximately $1.2 million per day, per violation.

A change in the jurisdictional characterization of our gathering assets may result in increased regulation, which could cause our revenues to decline and operating expenses to increase.

Our natural gas and crude oil gathering operations are generally exempt from the jurisdiction and regulation of the FERC, except for certain anti-market manipulation provisions. FERC regulation nonetheless affects our businesses and the markets for products derived from our gathering businesses. The FERC’s policies and practices across the range of its oil and gas regulatory activities, including, for example, its policies on open access transportation, rate making, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we have no assurance that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has regularly been the subject of substantial, on-going litigation. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by the FERC, the courts or Congress. If our gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of certain gathering agreements.

State and municipal regulations also impact our business. Common purchaser statutes generally require gatherers to gather or provide services without undue discrimination as to source of supply or producer; as a result, these statutes restrict our right to decide whose production we gather or transport. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we currently operate have adopted complaint-based regulation of gathering activities, which allows oil and gas producers and shippers to file complaints with state regulators in an effort to resolve access and rate grievances. Other state and municipal regulations may not directly regulate our gathering business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of its gathering lines.

Our operations are subject to compliance with environmental and operational health and 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 worker health and safety aspects of our operations, the discharge of materials into the environment and 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, the occurrence of delays in permitting or development of projects and the issuance of injunctions restricting or prohibiting some or all of our activities. 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

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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. For example, in October 2015, the EPA issued a final rule under the federal Clean Air Act lowering the United States NAAQS for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA published a final rule in November 2017 that issued area designations with respect to ground-level ozone for approximately 85% of the U.S. counties as either “attainment/unclassifiable” or “unclassifiable” but has not yet issued non-attainment designations for the remaining areas of the U.S. not addressed under the November 2017 final rule. States are also expected to adopt regulations implementing the NAAQS rule that may be more stringent than the federal standards. In another example, the EPA and U.S. Army of Corps of Engineers (Corp) published a final rule in June 2015 that attempted to clarify federal jurisdiction under the Clean Water Act over waters of the United States, but legal challenges to this rule followed and the rule has been stayed nationwide, with the U.S. Supreme Court accepting review of this rule in January 2017 to determine whether jurisdiction resides with the federal district or appellate courts. Subsequently, the EPA and the Corps have proposed a rulemaking in June 2017 to repeal the June 2015 rule, announced their intent to issue a new rule defining the Clean Water Act’s jurisdiction, and published a proposed rule in November 2017 specifying that the contested May 2015 rule would not take effect until two years after the November 2017 proposed rule is finalized and published in the Federal Registrar. As a result, future implementation of the June 2015 rule is uncertain at this time but to the extent any rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Our compliance with these or other new or amended legal requirements could result in our incurring significant additional expense and operating delays or restrictions with respect to our operations, which may not be fully recoverable from customers and, thus, could reduce net income. Our customers may similarly incur increased costs or restrictions that may limit or decrease those customers’ operations and have an indirect material adverse effect on our business.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating and capital costs and reduced demand for our services.

Climate change continues to attract considerable public and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources. At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has adopted regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (PSD) construction and Title V operating permit reviews for GHGs from certain large stationary sources that are already potential major sources of principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet best available control technology standards that typically will be established by the states. The EPA has also adopted regulations requiring the annual reporting of GHG emissions from specified large GHG emission sources in the United States including certain oil and natural gas production, processing, transmission, storage and distribution facilities as well as certain onshore gathering and boosting systems consisting primarily of gathering pipelines, compressors and process equipment used to perform natural gas compression, dehydration and acid gas removal.

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage facilities. These standards require the use of certain equipment specific emissions control practices, require additional controls for pneumatic controllers and pumps as well as compressors, and impose leak detection and repair requirements for natural gas compressor and booster stations. However, in June 2017, the EPA published a proposed rule to stay certain portions of the June 2016 standards for two years and re-evaluate the entirety of the 2016 standards but the EPA has not yet published a final rule and, as a result, future implementation of the 2016 standards is uncertain at this time. In another example, the BLM published a final rule in November 2016 that imposes requirements to reduce methane emissions from venting, flaring, and leaking on public lands. However, in October 2017, the BLM published a proposed rule that would temporarily suspend or delay certain requirements contained in the November 2016 final rule until January 17, 2019. These rules and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our and our customers’ operations and could delay or curtail our customers’ activities, which could adversely affect our business. On an international level, the United States is one of numerous nations that prepared an international climate change agreement in Paris, France in December 2015, requiring member countries to

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review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. This “Paris agreement” was signed by the United States in April 2016 and became effective in November 2016; however, this agreement does not create any binding obligations for nations to limit their GHG emissions, but does include pledges to voluntarily limit or reduce future emissions. However, in August 2017, the U.S. State Department officially informed the United Nations of the intent of the United States to withdraw from the Paris Agreement. The Paris Agreement provides for a four year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process and/or the terms on which the United States may re-enter the Paris Agreement or a separately negotiated agreement are unclear at this time.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us and our customers to incur increased compliance and operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas that is produced, which may decrease demand for our midstream services. Moreover, any such future laws and regulations that limit emissions of GHGs or that otherwise promote the use of renewable fuels could adversely affect demand for the natural gas our customers produce, which could thereby reduce demand for our services and adversely affect our business. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. In addition, recent non-governmental activism directed at shifting funding away from companies with energy-related assets could result in limitations or restrictions on certain sources of funding for the energy sector.

We may incur higher costs as a result of pipeline integrity management program testing and additional safety legislation.

Pursuant to authority under the NGPSA and HLPSA, PHMSA requires pipeline operators to develop integrity management programs for pipelines located where a leak or rupture could harm “high consequence areas”. The regulations require operators like us to:

• perform ongoing assessments of pipeline integrity;

• identify and characterize applicable threats to pipeline segments that could impact a high consequence area;

• maintain processes for data collection, integration and analysis;

• repair and remediate pipelines as necessary; and

• implement preventive and mitigating actions.

We estimate that the total future costs to complete the testing required by existing PHMSA regulations will not have a material impact to our results. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program itself.

Moreover, new legislation or regulations adopted by PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital costs, operational delays and costs of operations. For example, the 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. More recently, in June 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 2018. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016 to implement the agency’s expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.

With regard to storage facilities, following the leak at a natural gas storage facility, in February 2016, PHMSA issued an advisory bulletin for natural gas storage facility operators, recommending that they review operations to identify the potential leaks and failures caused by corrosion, chemical or mechanical damage, or other material deficiencies in equipment; review storage facility locations and operations of shut-off and isolation systems, and comply with state regulations governing the permitting, drilling, completion, and operation of storage wells, and recommending the voluntary implementation of certain industry recognized recommended practices for natural gas storage facilities. Further in December 2016, PHMSA issued final interim rules that impose new safety-related requirements on downhole facilities (including wells, wellbore tubing and casing) of new and existing underground natural gas storage facilities. The final interim rules adopt and make mandatory two American Petroleum Institute Recommend Practices (API RP 1170 and 1171) that, among other things, address construction, maintenance, risk-management and integrity-management procedures. PHMSA indicated when it issued the interim final rule

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that the adoption of these safety standards for natural gas storage facilities represent a first step in a multi-phase process to enhance the safety of underground natural gas storage, with more standards likely forthcoming. Most recently, in response to a petition for reconsideration of the interim final rule received in January 2017, PHMSA published a notice on June 20, 2017, advising that the agency intends to consider the issues raised by the petitioners in a final rule, which it currently expects to issue in 2018. At this time, we cannot predict the impact of any future regulatory actions in this area.

In January 2017, PHMSA issued a final rule that amends its pipeline safety regulations for the design, construction, testing, operation and maintenance of hazardous liquids pipelines.  The final rule imposes more stringent standards that determine how operators repair aging and high-risk infrastructure, increase the frequency of tests that assess pipeline conditions, and require operators to report more operating and safety data.  Among other things, the final rule: (i) extends an operator’s reporting requirements to gravity and hazardous liquids gathering pipelines; (ii) requires operators to inspect pipelines in areas affected by extreme weather and similar events within a certain timeframe; (iii) impose new requirements to periodically “pig” transmission pipelines in areas outside of high consequence areas; (iv) broadens the requirement for the use of leak detection systems; and (v) increases the use of inline inspection tools.  However, the date of implementation of this final rule by publication in the Federal Registrar remains uncertain following the January 2017 change in Presidential administrations.

We are evaluating PHMSA’s new rules, and we cannot predict the precise impact that compliance with the new rules will have on our business.  The new rules may, among other things, require us or our joint ventures to install new or modified safety controls, undertake additional capital projects or conduct maintenance programs on an expedited basis.  The costs of complying with the new PHMSA rules, as well as other rules under consideration by PHMSA or other agencies, could have a material adverse effect on our cash flows and results of operations.

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

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

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

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

• operator error;

• inadvertent damage from construction, farm and utility equipment;

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

• fires and explosions;

• cyber intrusions; and

• other hazards that could also result in personal injury, including loss of life, property and natural resources damage, pollution of the environmental or suspension of operations.

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

We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities. Although we maintain insurance policies with insurers in such amounts and with such coverages and deductibles as we believe are reasonable and prudent, our insurance may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage.

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We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.

We do not own all of the land on which our pipelines and facilities (particularly our G&P facilities) have been constructed, which subjects us to the possibility of more onerous terms or increased costs to obtain and maintain valid easements and rights-of-way. We obtain standard easement rights to construct and operate pipelines on land owned by third parties, and our rights frequently revert back to the landowner after we stop using the easement for its specified purpose.

Therefore, these easements exist for varying periods of time. Our loss of easement rights could have a material adverse effect on our ability to operate our business, thereby resulting in a material reduction in our revenue, earnings and ability to make distributions.

Terrorist attacks or “cyber security” events, or the threat of them, may adversely affect our business.

The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets of terrorist organizations or “cyber security” events.  These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets, our operations could be disrupted and/or customer information could be stolen. The occurrence of one of these events could cause a substantial decrease in revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation or litigation and or inaccurate information reported from our operations.  These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition.

Risks Inherent in an Investment in Us

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay quarterly distributions to our common and preferred unitholders.

We may not have sufficient cash each quarter to pay quarterly distributions to our common unitholders or, alternatively, we may reallocate a portion of our available cash to debt repayment or capital investment. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, distributions received from our joint ventures, and payments of fees and expenses as well as decisions the board of directors makes regarding acceptable levels of debt or the desire to invest in new growth projects. Our board typically reviews these factors on a quarterly basis. Before we pay any cash distributions on our preferred and common units, we will establish reserves and pay fees and expenses, including reimbursements to our general partner and its affiliates, for all expenses they incur and payments they make on our behalf. These costs will reduce the amount of cash available to pay distributions to our common unitholders and, to the extent we are unable to declare and pay fixed cash distributions on our preferred units, we cannot make cash distributions to our common unitholders until all payments accruing on the preferred units have been repaid.

The amount of cash we have available to distribute on our preferred and common units will fluctuate from quarter to quarter based on, among other things:

• the rates charged for services and the amount of services customers purchase, which will be affected by, among other things, the overall balance between the supply of and demand for commodities, governmental regulation of our rates and services, and our ability to obtain permits for growth projects;

• force majeure events that damage our or third-party pipelines, facilities, related equipment and surrounding properties;

• prevailing economic and market conditions;

• governmental regulation, including changes in governmental regulation in our industry;

• changes in tax laws;

• the level of competition from other midstream companies;

• the level of our operating and maintenance and general administrative costs;

• the level of capital expenditures we make;

• our ability to make borrowings under our revolving credit facility;

• our ability to access the capital markets for additional investment capital; and

• acceptable levels of debt, liquidity and/or leverage.

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including: the level and timing of capital expenditures we make; our debt service requirements and other liabilities; fluctuations in our working capital needs; our ability to borrow funds and access capital markets; restrictions contained in our debt agreements; and the amount of cash reserves established by our general partner.

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Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow given the current trends existing in the capital markets.

Since 2014, the dramatic decrease in commodity prices has negatively impacted the equity and debt markets resulting in limitations on our ability to access the capital markets for new growth capital at a reasonable cost of capital. Historically, we have distributed all of our available cash to our preferred and common unitholders on a quarterly basis and relied upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. If the current capital market trends persist, we may be unable to finance growth externally by accessing the capital markets, and may have to depend on a reallocation of our cash distributions to reduce debt and/or invest in new growth projects. In addition, we may dispose of assets to reduce debt and/or invest in new growth projects, which can impact the level of our cash distributions.

In the event we continue to distribute all of our available cash or decide to reallocate cash to debt reduction, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we decide to reallocate cash to debt reduction or invest in new capital projects, we may be unable to maintain or increase our per unit distribution level. Subject to certain restrictions that apply if we are not able to pay cash distributions to our preferred unitholders, there are no limitations in our partnership agreement on our ability to issue additional units, including units ranking senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unit holders.

We may issue additional common units without common unitholder approval, which would dilute existing common unit holder ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our existing common unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:

• our existing common unitholders’ proportionate ownership interest in us will decrease; 

• the amount of cash available for distribution on each common unit may decrease; 

• the ratio of taxable income to distributions may increase; 

• the relative voting strength of each previously outstanding common unit may be diminished; and 

• the market price of the common units may decline.

Unitholders have less ability to elect or remove management than holders of common stock in a corporation.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect, and do not have the right to elect, our general partner or its board of directors on an annual or other continuing basis. The board of directors of our general partner is effectively chosen by Crestwood Holdings, the general partner and only voting member of Holdings LP, the sole member of our general partner. Although our general partner has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders, the directors of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to its sole member, Holdings LP.

If unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner generally may not be removed except upon the vote of the holders of 66⅔% of the outstanding units voting together as a single class.

Our unitholders’ voting rights are further restricted by a provision in our partnership agreement providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter.

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Common unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.

Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the Delaware Act), we may not make a distribution to our common unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner; (ii) approve some amendments to our partnership agreement; or (iii) take other action under our partnership agreement constitutes “participation in the control” of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.

The amount of cash we have available for distribution to common unitholders depends primarily on our cash flow (including distributions from joint ventures) and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.

The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings and cash distributions received from our joint ventures, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net income.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Crestwood Holdings and its affiliates may sell its common units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units. Additionally, Crestwood Holdings may pledge or hypothecate its common units or is interest in Crestwood Holdings LP.

As of December 31, 2017, Crestwood Holdings and its affiliates beneficially held an aggregate of 17,908,700 limited partner units. The sale of any or all of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market on which the common units are traded. Additionally, Crestwood Holdings may pledge or hypothecate its common units or its interest in Crestwood Holdings LP (Holdings LP), the sole member of our general partner, or its subsidiaries. Such pledge or hypothecation may include terms and conditions that might result in an adverse impact on the trading price of our common units.

Our preferred units contain covenants that may limit our business flexibility.

Our preferred units contain covenants preventing us from taking certain actions without the approval of the holders of a majority or a super-majority of the preferred units, depending on the action as described below. The need to obtain the approval of holders of the preferred units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of its unit holders. The affirmative vote of the then-applicable voting threshold of the outstanding preferred units, voting separately as a class with one vote per preferred unit, shall be necessary to amend our partnership agreement in any manner that (i) alters or changes the rights, powers, privileges or preferences or duties and obligations of the preferred units in any material respect; (ii) except as contemplated in the

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partnership agreement, increases or decreases the authorized number of preferred units; or (iii) otherwise adversely affects the preferred units, including without limitation the creation (by reclassification or otherwise) of any class of senior securities (or amending the provisions of any existing class of partnership interests to make such class of partnership interests a class of senior securities). In addition, our partnership agreement provides certain rights to the preferred unit holders that could impair our ability to consummate (or increase the cost of consummating) a change-in-control transaction, which could result in less economic benefits accruing to our common unit holders.

The control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner, Holdings LP, from transferring its ownership interest in our general partner to a third party. Additionally, Holdings LP’s general partner interest in our general partner is pledged as collateral under a Credit Agreement between Crestwood Holdings and various lenders (Holdings Credit Agreement).  In the event of a default by Crestwood Holdings under the Holdings Credit Agreement, the lenders may foreclose on the pledged general partner interest and take or transfer control of our general partner without unitholder consent. The new owner of our general partner would then be in a position to replace the board of directors and officers of our general partner with its own choices and to control the decisions taken by our board of directors and officers. This effectively permits a “change of control” without the vote or consent of the common unitholders. In addition, such a change of control could result in our indebtedness becoming due. Please read “A change of control could result in us facing substantial repayment obligations under our revolving credit facility and senior notes.”

Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.

Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:

• Our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.

• Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

• Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.

• Our general partner determines which costs it and its affiliates have incurred are reimbursable by us.

• Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.

• Our general partner controls the enforcement of obligations owed to us by it and its affiliates.

• Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.

Our partnership agreement limits our general partner’s fiduciary duties to us and restricts the remedies available for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:

• provides that our general partner is entitled to make decisions in “good faith” if it reasonably believes that the decisions are in our best interests;

• generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and

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• provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2017, the directors and executive officers of our general partner owned approximately 6% of our common units.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income taxpurposes. If the IRS were to treat us as a corporation forfederal income tax purposes, or we were to become subject to material additionalamounts of entity-level taxation for state tax purposes, then our cash available fordistribution to unitholders would be substantially reduced.

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes.

Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes.

Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our common unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise, or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our unitholders.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Although there is no current legislative proposal, a prior legislative proposal would have eliminated the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, in January 2017, final regulations regarding which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code were published in the Federal Registrar. The final regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the final regulations affect our ability to be treated as a partnership for U.S. federal income tax purposes.

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Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our common units, and the costs of any such contest would reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, the costs of any contest with the IRS will be borne indirectly by you and our general partner because the costs will reduce our cash available for distribution.

If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders behalf.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustment directly from us. To the extent possible under the new rules, our general partner may elect to either pay the taxes (including any applicable penalties and interest) directly to the IRS or, if we are eligible, issue a revised information statement to each unitholder with respect to an audited and adjusted return. Although our general partner may elect to have our unitholders take such audit adjustment into account in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders behalf.

Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.

Our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, a unitholder may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.

Tax gain or loss on the disposition of our common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between your amount realized and your tax basis in those common units. Because distributions in excess of your allocable share of our total net taxable income result in a reduction in your tax basis in your common units, the amount, if any, of such prior excess distributions with respect to the units you sell will, in effect, become taxable income to you if you sell such units at a price greater than your tax basis in those common units, even if the price you receive is less than your original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if you sell your units you may incur a tax liability in excess of the amount of cash you receive from the sale.

Furthermore, a substantial portion of the amount realized, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may

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only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for business interest is limited to the sum our business interest income and 30% of our adjusted taxable income. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

Tax-exempt entities face unique tax issues from our owning common units that may result in adverse tax consequences to them.

Investment in our common units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Further, with respect to taxable years beginning after December 31, 2017, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our common units.

Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a Non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a Non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit.

The Tax Cut and Jobs Act imposes a withholding obligation of 10% of the amount realized upon a Non-U.S. unitholder’s sale or exchange of an interest in a partnership that is engaged in a U.S. trade or business. However, due to challenges of administering a withholding obligation applicable to open market trading and other complications, the IRS has temporarily suspended the application of this withholding rule to open market transfers of interest in publicly traded partnerships pending promulgation of regulations or other guidance that resolves the challenges. It is not clear if or when such regulations or other guidance will be issued. Non-U.S. unitholders should consult a tax advisor before investing in our common units.

We will treat each purchaser of our common units as having the same tax benefits without regard to the specific common units purchased. The IRS may challenge this treatment, which could adversely affect the value of our common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will adopt depreciation and amortization positions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of our common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

We prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the Allocation Date), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary

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item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose common units are the subject of a securities loan (i.e., a loan to a “short seller” to cover a short sale of common units) may be considered as having disposed of those common units. If so, he would no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and may recognize gain or loss from the disposition.

Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose common units are the subject of a securities loan may be considered as having disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those common units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those common units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those common units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from a loan to a short seller should modify any applicable brokerage account agreements to prohibit their brokers from borrowing their common units.

Our unitholders will likely be subject to state and local taxes and return filing requirements in jurisdictions where they do not live as a result of investing in our common units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including state and local taxes, unincorporated business taxes, estate, inheritance or intangible taxes and foreign taxes that are imposed by the various jurisdictions in which we do business or own property and in which they do not reside. We own property and conduct business in various parts of the United States. Unitholders may be required to file state and local income tax returns in many or all of the jurisdictions in which we do business or own property. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is our unitholders’ responsibility to file all required U. S. federal, state, local and foreign tax returns.

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Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

A description of our properties is included in Item 1. Business, and is incorporated herein by reference. We also lease office space for our corporate offices in Houston, Texas and Kansas City, Missouri.

We lease and rely upon our customers’ property rights to conduct a substantial part of our operations, and we own or lease the property rights necessary to conduct our storage and transportation operations. We believe that we have satisfactory title to our assets. Title to property may be subject to encumbrances. For example, we have granted to the lenders of our revolving credit facility security interests in substantially all of our real property interests. We believe that none of these encumbrances will materially detract from the value of our properties or from our interest in these properties, nor will they materially interfere with their use in the operation of our business.

Item 3. Legal Proceedings

A description of our legal proceedings is included in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 15, and is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

Crestwood Equity. Crestwood Equity’s common units representing limited partner interests are traded on the NYSE under the symbol “CEQP.” The following table sets forth the range of high and low sales prices of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per common unit for the periods indicated.

Quarters Ended:	Low		High		Cash Distribution Per Unit
2017
December 31, 2017	$	22.15	$	26.10	$	0.600
September 30, 2017	22.30		26.65		0.600
June 30, 2017	20.00		27.35		0.600
March 31, 2017	24.35		28.30		0.600
2016
December 31, 2016	$	18.51	$	25.70	$	0.600
September 30, 2016	18.67		22.22		0.600
June 30, 2016	10.40		23.59		0.600
March 31, 2016	7.90		21.56		0.600

The last reported sale price of Crestwood Equity’s common units on the NYSE on February 12, 2018, was $26.95. As of that date, Crestwood Equity had 71,231,599 common units issued and outstanding, which were held by 259 unitholders of record.

Distribution Policy

Preferred Units. We are required to make quarterly distributions to our preferred unitholders. The holders of the Preferred Units are entitled to receive fixed quarterly distributions of $0.2111 per unit. Through the quarter ending September 30, 2017 (the Initial Distribution Period), distributions on the Preferred Units could be made in additional Preferred Units, cash, or a combination thereof, at our election. Through and for the quarter ended June 30, 2017, we paid distributions on our Preferred Units through the issuance of additional Preferred Units. The number of units distributed was calculated as the fixed quarterly distribution of $0.2111 per unit divided by the cash purchase price of $9.13 per unit. We accrued the fair value of such distribution at the end of the quarterly period and adjusted the fair value of the distribution on the date the additional Preferred Units were distributed. Distributions on the Preferred Units following the Initial Distribution Period will be paid in in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units; and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to our Preferred Unit holders. If we fail to pay the full amount payable to our Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.2567 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if we fail to pay in full any Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

Common Units. Crestwood Equity makes quarterly distributions to its partners within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to our available cash for such quarter. Available cash generally means, with respect to each fiscal quarter, all cash on hand at the end of the quarter less the amount of cash that the general partner determines in its reasonable discretion is necessary or appropriate to:

• provide for the proper conduct of our business, including but not limited to, debt repayments, unit buybacks or capital investment;

• comply with applicable law, any of our debt instruments, or other agreements; or

• provide funds for distributions to unitholders for any one or more of the next four quarters;

46

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made subsequent to the end of the quarter. Working capital borrowings are generally borrowings that are made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to its partners.

On February 14, 2018, Crestwood Equity paid a distribution of $0.60 per limited partner unit ($2.40 per limited partner unit on an annualized basis) to its unitholders of record on February 7, 2018.

Issuer Purchases of Equity Securities

For the year ended December 31, 2017, we relinquished 206,600 common units to cover payroll taxes upon the vesting of restricted units. 

Equity Compensation Plan Information

The following table sets forth in tabular format, a summary of the Crestwood Equity equity compensation plan information as of December 31, 2017:

Plan category	Number of securities to be issued upon exercise of outstanding options, warrants and rights	Weighted- average exercise price of outstanding options, warrants and rights		Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (a))
	(a)	(b)		(c)
Equity compensation plans approved by security holders	—	$	—	—
Equity compensation plans not approved by security holders	—	$	—	4,157,742
Total	—	$	—	4,157,742

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Item 6. Selected Financial Data

Crestwood Midstream. This information has been omitted from this report pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

Crestwood Equity. Crestwood Equity’s consolidated financial statements were originally the financial statements of Legacy Crestwood GP prior to being acquired by us on June 19, 2013. Our acquisition of Legacy Crestwood GP was accounted for as a reverse acquisition under the purchase method of accounting in accordance with the accounting standards for business combinations. The accounting for a reverse acquisition results in the legal acquiree (Legacy Crestwood GP) being the acquirer for accounting purposes. Although Legacy Crestwood GP was the acquirer for accounting purposes, we were the acquirer for legal purposes; consequently, we changed our name from Crestwood Gas Services GP, LLC to Crestwood Equity Partners LP.

The income statement and cash flow data for each of the three years ended December 31, 2017 and balance sheet data as of December 31, 2017 and 2016 were derived from our audited financial statements. We derived the income statement and cash flow data for each of the two years ended December 31, 2014 and the balance sheet data as of December 31, 2015, 2014 and 2013 from our accounting records. The selected financial data is not necessarily indicative of results to be expected in future periods and should be read together with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part IV, Item 15. Exhibits and Financial Statement Schedules included elsewhere in this report.

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. We believe that EBITDA and Adjusted EBITDA are useful to our investors because it allows them to use the same performance measure analyzed internally by our management to evaluate the performance of our businesses and investments without regard to the manner in which they are financed or our capital structure. EBITDA is defined as income before income taxes, plus debt-related costs (interest and debt expense, net, and gain (loss) on modification/extinguishment of debt) and depreciation, amortization and accretion expense. Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates to reflect our proportionate share (based on the distribution percentage) of their EBITDA, excluding impairments. Adjusted EBITDA also considers the impact of certain significant items, such as unit-based compensation charges, gains and losses on long-lived assets, impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, certain costs related to our historical cost saving initiatives, the change in fair value of commodity inventory-related derivative contracts, costs associated with our 2017 realignment of our Marketing, Supply and Logistics operations and related consolidation and relocation of our corporate offices, and other transactions identified in a specific reporting period. The change in fair value of commodity inventory-related derivative contracts is considered in determining Adjusted EBITDA given that the timing of recognizing gains and losses on these derivative contracts differs from the recognition of revenue for the related underlying sale of inventory to which these derivatives relate. Changes in the fair value of other derivative contracts is not considered in determining Adjusted EBITDA given the relatively short-term nature of those derivative contracts. 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 as alternatives 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.

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	Crestwood Equity Partners LP
	Year Ended December 31,
	2017			2016			2015			2014			2013 (1)
	(in million, except per unit data)
Statement of Income Data:
Revenues	$	3,880.9		$	2,520.5		$	2,632.8		$	3,931.3		$	1,426.7
Operating income (loss)	(79.4		)	(108.7		)	(2,084.8		)	117.9			28.2
Loss before income taxes	(167.4		)	(191.8		)	(2,305.1		)	(9.3		)	(49.6		)
Net loss	(166.6		)	(192.1		)	(2,303.7		)	(10.4		)	(50.6		)
Net income (loss) attributable to Crestwood Equity Partners LP	(191.9		)	(216.3		)	(1,666.9		)	56.4			6.7
Performance Measures:
Diluted net income (loss) per limited partner unit: (2)	$	(3.64	)	$	(3.55	)	$	(54.00	)	$	3.30		$	0.59
Distributions declared per limited partner unit(3)	$	2.40		$	3.175		$	5.50		$	5.50		$	6.925
Other Financial Data:
EBITDA (unaudited)	$	161.4		$	152.9		$	(1,844.9	)	$	403.1		$	196.2
Adjusted EBITDA (unaudited)	395.4			455.6			527.4			495.9			297.7
Net cash provided by operating activities	255.9			346.1			440.7			283.0			188.3
Net cash provided by (used in) investing activities	38.7			867.2			(212.7		)	(483.0		)	(1,042.9		)
Net cash provided by (used in) financing activities	(294.9		)	(1,212.2		)	(236.3		)	203.6			859.7
Balance Sheet Data:
Property, plant and equipment, net	$	1,820.8		$	2,097.6		$	3,310.8		$	3,893.8		$	3,905.3
Total assets	4,284.9			4,448.9			5,762.8			8,421.7			8,476.0
Total debt, including current portion	1,492.2			1,523.7			2,502.9			2,356.8			2,218.8
Other long-term liabilities(4)	104.7			44.6			47.5			47.2			140.4
Partners’ capital	2,180.5			2,539.0			2,946.9			5,584.5			5,508.6

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	Crestwood Equity Partners LP
	Year Ended December 31,
	2017			2016			2015			2014			2013 (1)
	(in millions)
Reconciliation of Net Income to EBITDA and Adjusted EBITDA:
Net loss	$	(166.6	)	$	(192.1	)	$	(2,303.7	)	$	(10.4	)	$	(50.6	)
Depreciation, amortization and accretion	191.7			229.6			300.1			285.3			167.9
Interest and debt expense, net	99.4			125.1			140.1			127.1			77.9
(Gain) loss on modification/extinguishment of debt	37.7			(10.0		)	20.0			—			—
Provision (benefit) for income taxes	(0.8		)	0.3			(1.4		)	1.1			1.0
EBITDA	161.4			152.9			(1,844.9		)	403.1			196.2
Unit-based compensation charges	25.5			19.2			19.7			21.3			17.4
(Gain) loss on long-lived assets, net(5)	65.6			65.6			821.2			1.9			(5.3		)
Goodwill impairment(6)	38.8			162.6			1,406.3			48.8			4.1
Loss on contingent consideration(7)	57.0			—			—			8.6			31.4
(Earnings) loss from unconsolidated affiliates, net(8)	(47.8		)	(31.5		)	60.8			0.7			0.1
Adjusted EBITDA from unconsolidated affiliates, net	80.3			61.1			25.3			6.9			2.5
Change in fair value of commodity inventory-related derivative contracts	2.2			14.1			5.4			(10.3		)	10.7
Significant transaction and environmental-related costs and other items(9)	12.4			11.6			33.6			14.9			40.6
Adjusted EBITDA	$	395.4		$	455.6		$	527.4		$	495.9		$	297.7

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	Crestwood Equity Partners LP
	Year Ended December 31,
	2017			2016			2015			2014			2013 (1)
	(in millions)
Reconciliation of Net Cash Provided by Operating Activities to EBITDA and Adjusted EBITDA:
Net cash provided by operating activities	$	255.9		$	346.1		$	440.7		$	283.0		$	188.3
Net changes in operating assets and liabilities	(0.3		)	(57.9		)	(98.0		)	73.8			(19.6		)
Amortization of debt-related deferred costs, discounts and premiums	(7.2		)	(6.9		)	(8.9		)	(8.5		)	(9.2		)
Interest and debt expense, net	99.4			125.1			140.1			127.1			77.9
Market adjustment on interest rate swaps	—			—			0.5			2.7			1.7
Unit-based compensation charges	(25.5		)	(19.2		)	(19.7		)	(21.3		)	(17.4		)
Gain (loss) on long-lived assets, net(5)	(65.6		)	(65.6		)	(821.2		)	(1.9		)	5.3
Goodwill impairment(6)	(38.8		)	(162.6		)	(1,406.3		)	(48.8		)	(4.1		)
Loss on contingent consideration(7)	(57.0		)	—			—			(8.6		)	(31.4		)
Earnings (loss) from unconsolidated affiliates, net, adjusted for cash distributions received	0.1			(7.6		)	(73.6		)	(0.7		)	(0.1		)
Deferred income taxes	2.1			3.1			3.6			5.2			2.8
Provision (benefit) for income taxes	(0.8		)	0.3			(1.4		)	1.1			1.0
Other non-cash income (expense)	(0.9		)	(1.9		)	(0.7		)	—			1.0
EBITDA	161.4			152.9			(1,844.9		)	403.1			196.2
Unit-based compensation charges	25.5			19.2			19.7			21.3			17.4
(Gain) loss on long-lived assets, net(5)	65.6			65.6			821.2			1.9			(5.3		)
Goodwill impairment(6)	38.8			162.6			1,406.3			48.8			4.1
Loss on contingent consideration(7)	57.0			—			—			8.6			31.4
(Earnings) loss from unconsolidated affiliates, net(8)	(47.8		)	(31.5		)	60.8			0.7			0.1
Adjusted EBITDA from unconsolidated affiliates, net	80.3			61.1			25.3			6.9			2.5
Change in fair value of commodity inventory-related derivative contracts	2.2			14.1			5.4			(10.3		)	10.7
Significant transaction and environmental-related costs and other items(9)	12.4			11.6			33.6			14.9			40.6
Adjusted EBITDA	$	395.4		$	455.6		$	527.4		$	495.9		$	297.7

(1) Financial data presented for periods prior to June 19, 2013, solely reflect the operations of Legacy Crestwood GP. Financial data for periods subsequent to June 19, 2013, represent the consolidated operations of Crestwood Equity.

(2) The weighted average number of units outstanding is calculated based on the presumption that the common and subordinated units issued to acquire Legacy Crestwood GP (the accounting predecessor) were outstanding for the entire period prior to the June 19, 2013 acquisition. On the date of the acquisition, all of our limited partner units were considered outstanding. In addition, on November 23, 2015, CEQP completed a 1-for-10 reverse split of its common units. The accounting standards related to earnings per share requires an entity to restate earnings per share when a stock dividend or stock split occurs, and as such, the earnings per unit for the years ended December 31, 2014 and 2013, were restated to reflect the 1-for-10 reverse split.

(3) Reported amounts include the fourth quarter distributions, which are paid in the first quarter of the subsequent year.

(4) Other long-term liabilities primarily include our capital leases, asset retirement obligations, loss on contingent consideration, net and the fair value of unfavorable contracts recorded in purchase accounting.

(5) During 2017, we recognized a gain of approximately $33.6 million from the sale of US Salt. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3. During 2016, we recorded a loss of approximately $32.4 million on the deconsolidation of our NE S&T assets. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 2 and 6. During 2014, we recorded a gain of approximately $30.6 million on the sale of our investment in Tres Palacios. In addition, during 2017, 2015 and 2014, we recorded property, plant and equipment impairments of approximately $81.4 million, $501.7 million and $13.2 million. During 2017, 2016, 2015 and 2014, we recorded intangible asset impairments of approximately $0.8 million, $31.4 million, $316.6 million and $21.3 million. For a further discussion, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Estimates” and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

(6) For a further discussion of our goodwill impairments recorded during 2017, 2016, 2015 and 2014, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Estimates” and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

(7) During 2017, the loss on contingent consideration related to our obligation to CEGP due to our expectation of certain criteria on growth capital projects not being met by Stagecoach Gas. For a further discussion, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6. During 2014 and 2013, we recorded a loss on contingent consideration which reflects the fair value of an earn-out premium associated with the original acquisition of our Marcellus G&P assets from Antero in 2012.

(8) During 2015, we recorded impairments of our PRBIC and Jackalope equity investments of approximately $23.4 million and $51.4 million. For a further discussion of these impairments, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Estimates” and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

(9) Significant transaction and environmental-related costs and other items primarily include costs incurred related to the Simplification Merger and other merger, acquisition and joint venture transactions, as well as costs associated with our historical cost savings initiatives and the realignment of our MS&L operations and related consolidation and relocation of our corporate offices.

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Item 7.    Management’s Discussion and Analysis of Financial Condition and Results of Operations

Our Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our consolidated financial statements and the accompanying footnotes.

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 belief that anticipated cash from operations, cash distributions from entities that we control, and borrowing capacity under our credit facility will be sufficient to meet our anticipated liquidity needs for the foreseeable future; (ii) 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 (iii) our belief that our assets will continue to benefit from the development of unconventional shale plays as significant supply basins; and

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

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

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

• governmental legislation and regulations;

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

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

• weather conditions;

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

• economic conditions;

• costs or difficulties related to the integration of acquisitions and success of our joint ventures’ operations;

• environmental claims;

• operating hazards and other risks incidental to the provision of midstream services, including gathering, compressing, treating, processing, fractionating, transporting and storing energy products (i.e., crude oil, NGLs and natural gas) and related products (i.e., produced water);

• interest rates;

• the price and availability of debt and equity financing, including our ability to raise capital through alternatives like joint ventures; and

• the ability to sell or monetize assets, to reduce indebtedness, to repurchase our equity securities, to make strategic investments, or for other general partnership purposes.

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

Overview

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

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Our Company

We provide broad-ranging services to customers across the crude oil, natural gas and NGL sector of the energy value chain. Our midstream infrastructure is geographically located in or near significant supply basins, especially developed and emerging liquids-rich and crude oil shale plays, across the United States. We own or control:

• natural gas facilities with approximately 2.4 Bcf/d of gathering capacity and 0.5 Bcf/d of processing capacity;

• NGL facilities with approximately 20,000 Bbls/d of fractionation capacity and 3.1 MMBbls of storage capacity, as well as our portfolio of transportation assets (consisting of truck and rail terminals, truck/trailer units and rail cars) capable of transporting approximately 195,000 Bbls/d of NGLs; and

• crude oil facilities with approximately 125,000 Bbls/d of gathering capacity, 1.5 MMBbls of storage capacity, 20,000 Bbls/d of transportation capacity, and 160,000 Bbls/d of rail loading capacity.

In addition, through our equity investments in joint ventures, we have ownership interests in:

• natural gas facilities with approximately 0.3 Bcf/d of gathering capacity, 0.2 Bcf/d of processing capacity, 75.8 Bcf of certificated working storage capacity, and 1.5 Bcf/d of transportation capacity; and

• crude oil facilities with approximately 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of working storage capacity.

Our financial statements reflect three operating and reporting segments: (i) gathering and processing, which includes our natural gas, crude oil and produced water G&P operations; (ii) storage and transportation, which includes our natural gas and crude oil storage and transportation operations; and (iii) marketing, supply and logistics, which includes our NGL supply and logistics business, crude oil storage and rail loading facilities and fleet.

Gathering and Processing

Our G&P operations and investments provide gathering, compression, treating, and processing services to producers in multiple unconventional resource plays across the United States and we have established footprints in “core of the core” areas of many of the largest shale plays. We believe that our strategy of focusing on prolific, low-cost shale plays positions us well to (i) generate greater returns in varying commodity price environments, (ii) capture greater upside economics when development activity occurs, and (iii) in general, better manage through commodity price cycles and production changes associated therewith.

Our G&P operations primarily include:

• Bakken. We own and operate an integrated crude oil, natural gas and produced water gathering system and processing facility (the Arrow system) in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota, some of which is located on Fort Berthold Indian Reservation. The Arrow system consists of 640 miles of low-pressure gathering pipeline capable of gathering 100 MMcf/d of natural gas, 125 MBbls/d of crude oil, 40 MBbls/d of produced water, and the Bear Den processing plant includes approximately 30 MMcf/d of natural gas processing capacity. We also have approximately 266,000 Bbls of crude oil working storage capacity at the Arrow central delivery point;

• Marcellus. We own and operate natural gas gathering and compression systems in Harrison, Doddridge and Barbour Counties, West Virginia. These systems have a total gathering capacity of 875 MMcf/d and 131,380 horsepower of compression;

• Barnett. We own and operate (i) a low-pressure natural gas gathering system with a gathering capacity of approximately 425 MMcf/d of rich gas produced by our customers in Hood and Somervell Counties, Texas, which delivers the rich gas to our processing plant where NGLs are extracted from the natural gas stream; and (ii) low-pressure gathering systems with a gathering capacity of 500 MMcf/d of dry natural gas produced by our customers in Tarrant and Denton Counties, Texas;

53

• Fayetteville. We own and operate five low-pressure gas gathering systems with a gathering capacity of approximately 510 MMcf/d of dry natural gas produced by our customers in Conway, Faulkner, Van Buren, and White Counties, Arkansas;

• Granite Wash. We own and operate a low-pressure natural gas gathering system with a gathering capacity of approximately 36 MMcf/d of rich gas produced by our customers in Roberts County, Texas, and a processing plant that extracts NGLs from the natural gas stream;

• Delaware Permian. We own a 50% equity interest in the Crestwood Permian joint venture with an affiliate of First Reserve. We operate the joint venture, which owns low-pressure dry gas and rich natural gas gathering systems with a primary focus on the Willow Lake system, which includes approximately 75 MMcf/d of processing capacity that serves our customers in Eddy County, New Mexico. The joint venture also owns a 50% equity interest in Crestwood Permian Basin. In October 2017, Shell Midstream purchased a 50% equity interest in Crestwood Permian Basin. Crestwood Permian Basin owns and operates the Nautilus gathering system for SWEPI’s gas production in an area of dedication (approximately 100,000 acres) in Loving, Reeves and Ward Counties, Texas. The initial build-out of the Nautilus gathering system was completed on June 6, 2017, and includes 20 receipt point meters, 60 miles of pipeline, a 24-mile high pressure header system, 10,800 horsepower of compression and a high pressure delivery point. The Nautilus gathering system is supported by a 20-year fixed-fee gathering agreement with SWEPI; and

• Powder River Basin. We own a 50% equity interest in the Jackalope joint venture with Williams. The joint venture, operated by Williams, owns the Jackalope gas gathering system and Bucking Horse processing plant. The Jackalope system is supported by a 10-year gathering and processing agreement with Chesapeake under an area of dedication of approximately 358,000 gross acres in the core of the Powder River Basin;

Although the cash flows from our G&P operations are predominantly fee-based under contracts with original terms ranging from 5-20 years, the results of our G&P operations are significantly influenced by the volumes gathered and processed through our systems. For example, due to market conditions that ultimately resulted in 2015 bankruptcy filings of two of our G&P customers (Quicksilver and Sabine), we gathered significantly lower volumes for those customers during 2015 and 2016 as they continued to shut-in wells during their respective bankruptcy proceedings. In April 2016, BlueStone bought Quicksilver’s assets out of bankruptcy and thereafter returned to production wells that were previously shut-in by Quicksilver. We entered into new 10-year agreements with BlueStone to gather and process its production under fixed-fee and percent-of-proceeds fee structures, and pursuant to the agreements, BlueStone will not shut-in or choke back production for economic purposes through the end of 2018. As a result, the volumes we are now gathering and processing have returned to levels consistent with those preceding Quicksilver’s bankruptcy filing. In March 2017, the Sabine bankruptcy proceedings were settled by the district court for the Southern District of New York, and the outcome was not material to our G&P segment’s results of operations.

The cash flows from our G&P operations can also be impacted in the short term by changing commodity prices, seasonality and weather fluctuations. We gather, process, treat, compress, transport and sell crude oil and natural gas pursuant to a variety of contracts. These contracts include:

• Fixed-fee contracts. Under these contracts, we do not take title to the underlying crude, natural gas or NGLs but charge our customers a fixed-fee per volume gathered, processed, treated, compressed and/or transported. Certain of these agreements can contain commitments for a minimum level of volumes or revenues;

• Percentage-of-proceeds service contracts. Under these contracts, we effectively take title to crude, natural gas or NGLs after the commodity leaves our gathering and processing facilities. We often market and sell those commodities to third parties after they leave our facilities and we will remit a portion of the sales proceeds to our producers;

• Percentage-of-proceeds product contracts. Under these contracts, we effectively take title to crude, natural gas or NGLs before the commodity enters our gathering and processing facilities. We market and sell those commodities to third parties and we will remit a portion of the sales proceeds to our producers; and

• Purchase and sale contracts. Under these contracts, we purchase crude, natural gas or NGLs before the commodity enters our gathering and processing facilities, and we market and sell those commodities to third parties.

Our election to enter primarily into fixed-fee contracts minimizes our G&P segment’s commodity price exposure and provides us more stable operating performance and cash flows.

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Storage and Transportation

Our S&T operations and investments consist of our crude oil terminals in the Bakken and Powder River Basin and our natural gas storage and transportation assets in the Northeast and Texas Gulf Coast, including:

• Bakken. We own and operate the COLT Hub, which is one of the largest crude oil rail terminals in the Bakken Shale based on actual throughput. Located approximately 60 miles from Arrow’s central delivery point, the COLT Hub interconnects with the Arrow system through the Hiland and Andeavor pipeline systems. The COLT Hub, which can receive approximately 350,000 Bbls/d from interconnected gathering systems, is capable of loading up to 160,000 Bbls/d and storing approximately 1.2 MMBbls of crude oil. Moreover, because the COLT Hub and our Arrow system each interconnect with the DAPL interstate system, our Bakken crude oil assets are integrated and offer customers multiple service options since the DAPL interstate pipeline system was placed in service in 2017;

• Powder River Basin. PRBIC, our 50% equity method investment, owns an integrated crude oil loading, storage and pipeline terminal, located in Douglas County, Wyoming, which provides a market for crude oil production from the Powder River Basin. The joint venture, which is operated by our joint venture partner, Twin Eagle, sources crude oil production from Chesapeake and other Powder River Basin producers. PRBIC includes 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of crude oil working storage capacity. The terminal connects to Kinder Morgan’s Double H Pipeline system and Plains All American Pipeline’s Rocky Mountain Pipeline system;

• Marcellus. Stagecoach Gas, our 50% equity method investment, owns 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 or near the dry portion of the Marcellus Shale. The natural gas storage facilities provide 40.9 Bcf of certificated firm storage capacity and 1.5 Bcf/d of firm transportation capacity to producers, utilities, marketers and other customers. The location of these assets relative to New York City and other premium demand markets along the East Coast, together with the formation of our joint venture with a subsidiary of Consolidated Edison, helps to insulate our operations from production and commodity price changes that can impact storage and transportation operators in other geographic regions; and

• Texas Gulf Coast. Tres Holdings, our 50.01% equity method investment owns a FERC-certificated 34.9 Bcf multi-cycle, salt dome natural gas storage facility. The Tres Palacios storage facility’s 63-mile, dual 24-inch diameter header system (including a 52-mile north pipeline lateral and an approximate 11-mile south pipeline lateral) interconnects with 11 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan Inc.’s Houston central processing plant.

The cash flows from our S&T operations are predominantly fee-based under contracts with an original term ranging from 1-10 years. Our current cash flows from crude-by-rail facilities are supported by take-or-pay contracts with refiners and marketers. The rates and durations of the contracts associated with our crude oil terminals have eroded as pipelines come on-line that make crude-by-rail options less economical, which impacts our cash flows from operations. Cash flows from interruptible and other hub services provided by the natural gas storage facilities and pipelines owned by our joint ventures tends to increase during the peak winter season.

Marketing, Supply and Logistics

Our MS&L segment consists of our supply and logistics business, our storage and terminals business, our West Coast operations, and our crude oil, NGL and produced water trucking business. We utilize our over-the-road and rail fleet, processing and storage facilities, and contracted storage and pipeline capacity on a portfolio basis to provide integrated supply and logistics solutions to producers, refiners and other customers. In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP for net proceeds of approximately $223.6 million. As part of the US Salt divestiture, we retained all surface and sub-surface rights necessary to place the Watkins Glen NGL storage development project into service once we receive all required regulatory approvals.

Our MS&L operations primarily include:

• Supply and Logistics. Our Supply and Logistics operations are supported by i) our fleet of rail and rolling stock with 75,000 Bbls/d of NGL transportation capacity, which also includes our rail-to-truck terminals located in Florida, New Jersey, New York, Rhode Island and North Carolina; and ii) NGL pipeline and storage capacity leased from third

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parties, including more than 500,000 Bbls of NGL working storage capacity at major hubs in Mt. Belvieu, Texas and Conway, Kansas;

• Storage and Terminals. Our NGL Storage and Terminals operations include our Seymour and Bath storage facilities, which are supported by third-party pipelines and/or rail and truck terminal facilities;

• West Coast. Our West Coast NGL operations provide processing, fractionation, storage, transportation and marketing services to producers, refiners and other customers. We separate NGLs from natural gas, deliver to local natural gas pipelines, retain NGLs for further processing at our fractionation facility, provide butane isomerization and refrigerated storage services, as well as provide to Western US refineries for motor fuel production. Our operations also consists of wholesale propane assets primarily including three rail-to-truck terminals located in Hazen, Nevada, Carlin, Nevada, and Shoshoni, Wyoming and a truck terminal located in Salt Lake City, Utah. These terminals are used to provide supply, transportation and storage services to wholesale customers in the western and north central regions of the United States; and

• Trucking. Our Trucking operations consist of a fleet of owned and leased trucks with 20,000 Bbls/d of crude oil and produced water transportation capacity and 120,000 Bbls/d of NGL transportation capacity. We provide hauling services to customers in North Dakota, Montana, Wyoming, Texas, New Mexico, Indiana, Mississippi, New Jersey, Ohio, Utah and California.

The cash flows from our marketing, supply and logistics business represent sales to creditworthy customers typically under contracts with durations of one year or less, and tend to be seasonal in nature due to customer profiles and their tendencies to purchase NGLs during peak winter periods.

Outlook and Trends

Our business objective is to create long-term value for our unitholders. We expect to create long-term value by consistently generating stable operating margins and improved cash flows from operations by prudently financing our investments, maximizing throughput on our assets, and effectively controlling our operating and administrative costs. Our business strategy depends, in part, on our ability to provide increased services to our customers at competitive fees, including opportunities to expand our services resulting from expansions, organic growth projects and acquisitions that can be financed appropriately.

Through the challenging market environment from 2014 through 2017, we have taken a number of strategic steps to better position the Company as a stronger, better capitalized company that can over time accretively grow cash flows and sustainably resume growing our distributions. Those strategic steps included (i) simplifying our corporate structure to eliminate our incentive distribution rights (IDRs) and create better alignment of interests with our unitholders; (ii) divesting assets to reduce approximately $1 billion of long-term debt to ensure long-term balance sheet strength; (iii) realigning our operating structure to significantly reduce operating and administrative expenses; (iv) forming strategic joint ventures to enhance our competitive position around certain operating assets; and (v) focusing our growth capital expenditures on our highest return organic projects around our core growth assets in the Bakken Shale and Delaware Permian. We will remain focused on efficiently allocating capital expenditures by investing in accretive, organic growth projects, maintaining low-cost operations (through increased operating efficiencies and cost discipline) and maintaining our balance sheet strength through continued financial discipline. We expect to focus on expansion and greenfield opportunities in the Bakken Shale and Delaware Permian in the near term, while closely monitoring longer-term expansion opportunities in the Powder River Basin and northeast Marcellus. As a result, the Company is well positioned to execute its business plan and capitalize on the improving market conditions around many of our core assets.

While market conditions remain challenging around some of our assets, the Company continues to be positioned to generate consistent results in a low commodity price environment without sacrificing revenue upside as market conditions improve. For example, many of our more mature G&P assets are supported by long-term, core acreage dedications in shale plays that are economic to varying degrees based upon natural gas, NGL and crude oil prices, the availability of infrastructure to flow production to market, and the operational and financial condition of our diverse customer base. In addition, a substantial portion of our midstream investments are based on fixed-fee, take-or-pay or minimum volume commitment agreements that ensure a minimum level of cash flow regardless of actual commodity prices or volumetric throughput. Over time, we expect cash flows from our more mature, non-core, assets to stabilize and potentially increase with the improving commodity price environment, while the growth from our core assets in the Bakken Shale, Delaware Permian, Powder River Basin and northeast Marcellus drive significant growth to the Company.

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Below is a discussion of events that highlight our core business and financing activities. Through continued execution of our plan, we have materially improved the strategic and financial position of the Company and expect to capitalize on increasing opportunities in an improving but competitive market environment, which will position us to achieve our chief business objective to create long-term value for our unitholders.

Gathering and Processing

Bakken. In the Bakken, we are expanding and upgrading our Arrow system water handling facilities and increasing natural gas capacity on the system, which should allow for substantial growth in volumetric throughput across all of our crude oil, produced water and natural gas gathering systems. We are completing construction of a 30 MMcf/d natural gas processing facility and associated pipelines that began receiving gas in late 2017. In addition, we are constructing a 120 MMcf/d cryogenic plant that is designed to fulfill 100% of the processing requirements for producers on the Arrow system upon expiration of third-party processing contracts in the third quarter 2019. We expect to invest approximately $195 million on the expansion with a targeted in-service date in the second quarter 2019. Upon completion of the expansion, we expect to have a combined 150 MMcf/d of gas processing capacity in the Bakken. We believe the installation of a gas processing solution on the Arrow system will, among other things, spur greater development activity around the Arrow system, allow us to provide greater flow assurance to our producer customers and reduce flaring of natural gas, and reduce the downstream constraints currently experienced by producers on the Fort Berthold Indian Reservation.

Delaware Permian. In the Delaware Permian, we have identified gathering and processing and transportation opportunities in and around our existing assets, including our joint ventures. Through our Crestwood Permian joint venture, we are expanding our gathering and processing capacity in the region, which includes the construction of a 200 MMcf/d natural gas processing facility in Orla, Texas, and associated pipelines, as well as our interconnection capacity to accommodate greater takeaway options for residue gas and NGLs. The initial cost of the expansion project is expected to cost approximately $170 million with an in-service date in the second half of 2018. We are also evaluating expansion opportunities to provide midstream services for crude oil and produced water, including crude gathering, crude oil and condensate storage and terminalling, condensate stabilization, truck loading/unloading options and connections to third party pipelines and produced water gathering, disposal and recycling.

On June 21, 2017, we contributed to Crestwood Permian 100% of theequity interest of Crestwood New Mexico, our wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New Mexico. This contribution was treated as a transaction between entities under common control, and accordingly we deconsolidated Crestwood New Mexico and our investment in Crestwood Permian was increased by the historical book value of these assets of approximately $69.4 million. In conjunction with this contribution, First Reserve has agreed to contribute to Crestwood Permian the first $151 million of capital costs required to fund the expansion of the Delaware Basin assets, which includes the Orla processing plant and associated pipelines. In October 2017, CPB Subsidiary Holdings LLC, a wholly-subsidiary of Crestwood Permian, entered into a credit agreement with certain lenders. The five year term credit agreement allows for revolving loans, letters of credit and swingline loans in an aggregate principal amount of up to $150 million. Borrowings under the credit agreement will be used to fund expansion projects and for general corporate purposes.

Crestwood Permian Basin has a long-term agreement with SWEPI to construct, own and operate a natural gas gathering system in SWEPI's operated position in the Delaware Permian. SWEPI has dedicated to Crestwood Permian Basin approximately 100,000 acres and gathering rights for SWEPI's gas production across a large acreage position in Loving, Reeves, Ward and Culberson Counties, Texas. The Nautilus gathering system will be constructed to ultimately include 194 miles of low pressure gathering lines, 36 miles of high pressure trunklines and centralized compression facilities which are expandable over time as production increases, producing gas gathering capacity of approximately 250 MMcf/d. In addition, the Orla processing plant described above, will be further expanded and integrated to connect the Nautilus gas gathering system to the Orla plant. The initial build-out of the Nautilus gathering system was completed on June 6, 2017, and includes 20 receipt point meters, 60 miles of pipeline, a 24-mile high pressure header system, 10,800 horsepower of compression and a high pressure delivery point. Crestwood Permian Basin provides gathering, dehydration, compression and liquids handling services to SWEPI under a 20-year fixed-fee gathering agreement. In October 2017, Shell Midstream purchased a 50% equity interest in Crestwood Permian Basin for approximately $37.9 million in cash.

Marketing, Supply and Logistics

Our MS&L operations own NGL storage and terminalling assets in the Northeast U.S. and our West Coast processing facility. During 2017, we experienced NGL market headwinds in the Northeast, with our NGL exports and other market dynamics causing price differentials to narrow between purchasing NGLs in the summer (which are stored in our NGL facilities) and

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selling NGLs in the winter. These dynamics also caused the rates that we were able to charge for storing NGLs in our facilities to decline from their historical levels. Also during 2017, our West Coast customers also experienced headwinds, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S. This caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016.

In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP for net proceeds of approximately $223.6 million.

Regulatory Matters

Many aspects of the energy midstream sector, such as crude-by-rail activities and pipeline integrity, have experienced increased regulatory oversight over the past few years. However, under the current Presidential Administration, we anticipate changes in policy that could lessen the degree of regulatory scrutiny we face in the near term.

In December 2017, the Tax Cuts and Jobs Act (the Tax Act) was passed by the U.S. Congress, which modified several aspects of the U.S. income tax code beginning in 2018. We are currently evaluating how many of these modifications will impact master limited partnerships such as CEQP and its unitholders. In particular, we are evaluating the impact that the Tax Act will have on our unitholders’ ability to deduct business interest from their taxable income, since the Tax Act requires that the business interest deduction be limited to the sum of business interest income and 30% of adjusted taxable income. For the purposes of this limitation, adjusted taxable income will be computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.

Critical Accounting Estimates and Policies

Our significant accounting policies are described in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. We have discussed the development and selection of the following critical accounting estimates and related disclosures with the Audit Committee of the board of directors of our general partner.

Goodwill Impairment

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

We estimate the fair value of our reporting units based on a number of factors, including discount rates, projected cash flows and the potential value we would receive if we sold the reporting unit. We also compare the total fair value of our reporting units to our overall enterprise value, which considers the market value for our common and preferred units. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our reporting units (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our customers, such as their future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. If the assumptions embodied in the projections prove inaccurate, we could incur a future impairment charge. In addition, the use of the income approach to determine the fair value of our reporting units (see further discussion of the income approach below) could result in a different fair value if we had utilized a market approach, or a combination thereof.

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We acquired substantially all of our reporting units in 2013, 2012 and 2011, which required us to record the assets, liabilities and goodwill of each of those reporting units at fair value on the date they were acquired. As a result, any level of decrease in the forecasted cash flows of these businesses or increases in the discount rates utilized to value those businesses from their respective acquisition dates would likely result in the fair value of the reporting unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill is impaired.

Current commodity prices are significantly lower compared to commodity prices during 2014, and that decrease has adversely impacted forecasted cash flows, discount rates and stock/unit prices for most companies in the midstream industry, including us. In light of these circumstances, we evaluated the carrying value of our reporting units and determined it was more likely than not that the goodwill associated with several of our reporting units was impaired and as a result, we recorded goodwill impairments on several of our reporting units during 2017, 2016 and 2015 as shown in the table below (in millions). During 2017, we adopted the provision of ASU 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which allows companies to apply a single test to determine if goodwill is impaired and the amount of any impairment, which is reflected in our 2017 goodwill impairments.

	Goodwill Impairments during the Year Ended December 31, 2015		Goodwill Impairments during the Year Ended December 31, 2016		Goodwill Impairments during the Year Ended December 31, 2017		Goodwill at December 31, 2017
G&P
Fayetteville	$	72.5	$	—	$	—	$	—
Marcellus	—		8.6		—		—
Arrow	—		—		—		45.9
S&T
COLT	623.4		44.9		—		—
MS&L
West Coast	85.9		—		2.4		—
Supply and Logistics	99.0		65.5		—		101.7
Storage and Terminals	53.7		14.1		36.4		—
Trucking	148.4		29.5		—		—
Watkins Glen	66.2		—		—		—
Total Crestwood Midstream	$	1,149.1	$	162.6	$	38.8	$	147.6
Barnett (G&P)	257.2		—		—		—
Total Crestwood Equity	$	1,406.3	$	162.6	$	38.8	$	147.6

The goodwill impairments recorded during 2017 related to our MS&L West Coast and Storage and Terminals operations. The goodwill impairment related to our MS&L West Coast operations resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for gathering, processing and logistics services from our West Coast operations to remain relatively flat over the past several years. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. The goodwill impairment related to our MS&L Storage and Terminals operations resulted from decreasing forecasted cash flows to be generated by those operations. During 2017, we experienced NGL market headwinds in the Northeast with NGL exports and other market dynamics causing price differentials to narrow between purchasing NGLs in the summer (which are then stored in our NGL facilities) and selling NGLs in the winter. These dynamics also caused the rates that we are able to charge for storing NGLs in our facilities to decline from their historical levels. Although our MS&L Storage and Terminals operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the decrease that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. We utilized the income approach to determine the fair value of our reporting units given the limited availability of comparable market-based transactions during 2017, and we utilized discount rates ranging from 10% to 12% in applying the income approach to determine the fair value of our reporting units with goodwill as of December 31, 2017, which is a Level 3 fair value measurement.

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As a result of these analyses and impairments, we only have two reporting units with goodwill associated with them at December 31, 2017 (Arrow and Supply and Logistics). We continue to monitor our remaining goodwill, and we could experience additional impairments of the remaining goodwill in the future if we experience a significant sustained decrease in the market value of our common or preferred units or if we receive additional negative information about market conditions or the intent of our customers on our remaining operations with goodwill, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value of those businesses. In particular, a 5% decrease in the forecasted cash flows or a 1% increase in the discount rates utilized to determine the fair value of our business would not have resulted in goodwill impairments at our two remaining reporting units with goodwill associated with them.

Long-Lived Assets

Our long-lived assets consist of property, plant and equipment and intangible assets that have been obtained through multiple historical business combinations and property, plant and equipment that has been constructed in recent years. The initial recording of a majority of these long-lived assets was at fair value, which is estimated by management primarily utilizing market-related information and other projections on the performance of the assets acquired. Management reviews this information to determine its reasonableness in comparison to the assumptions utilized in determining the purchase price of the assets in addition to other market-based information that was received through the purchase process and other sources. These projections also include projections on potential and contractual obligations assumed in these acquisitions. Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can, and often do, differ from our estimates.

We utilize assumptions related to the useful lives and related salvage value of our property, plant and equipment in order to determine depreciation and amortization expense each period. Due to the imprecise nature of the projections and assumptions utilized in determining useful lives, actual results can, and often do, differ from our estimates.

To estimate the useful life of our finite lived intangible assets we utilize assumptions of the period over which the assets are expected to contribute directly or indirectly to our future cash flows. Generally this requires us to amortize our intangible assets based on the expected future cash flows (to the extent they are readily determinable) or on a straight-line basis (if they are not readily determinable) of the acquired contracts or customer relationships. Due to the imprecise nature of the projections and assumptions utilized determining future cash flows, actual results can, and often do, differ from our estimates.

We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value of our assets based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. This differs from our evaluation of goodwill, for which we perform an assessment of the recoverability of goodwill utilizing fair value estimates that primarily utilize discounted cash flows in the estimation process (as described above), and accordingly a reporting unit that has experienced a goodwill impairment may not experience a similar impairment of the underlying long-lived assets included in that reporting unit. During 2017, 2016 and 2015, we recorded the following impairments of our intangible assets and property, plant and equipment:

• During 2017, we incurred $82.2 million of impairments of our property, plant and equipment and intangible assets related to our MS&L West Coast operations, which resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future.

• During 2016, we incurred a $31.4 million impairment of intangible assets related to our MS&L Trucking operations, which resulted from the impact of increased competition on our Trucking business and the loss of several key customer relationships that were acquired in 2013 to which the intangible assets related.

• During 2015, we incurred $8.5 million of impairments of our property, plant and equipment related to our Granite Wash gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our major customer of those assets has declared bankruptcy and has ceased any substantial drilling in the

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Granite Wash in the near future given current and future anticipated market conditions related to natural gas and NGLs. 

• During 2015, we incurred $593.3 million of impairments of our intangible assets and property, plant and equipment related to our Barnett gathering and processing operations, which resulted from the recent actions of our primary customer in the Barnett Shale, Quicksilver, related to its filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015.

• During 2015, we incurred $184.5 million of impairments of our intangible assets and property, plant and equipment related to our Fayetteville and Haynesville gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas.

• During 2015, we incurred $31.2 million of impairments of our property, plant and equipment related to our Watkins Glen marketing, supply and logistics segment development project, which resulted from continued delays and uncertainties in the permitting of our proposed NGL storage facility.

Projected cash flows of our long-lived assets are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. If those cash flow projections indicate that the long-lived asset’s carrying value is not recoverable, we record an impairment charge for the excess of carrying value of the asset over its fair value. The estimate of fair value considers a number of factors, including the potential value we would receive if we sold the asset, discount rates and projected cash flows. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

We continue to monitor our long-lived assets, and we could experience additional impairments of the remaining carrying value of these long-lived assets in the future if we receive additional negative information about market conditions or the intent of our long-lived assets’ customers, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value of those investments.

Equity Method Investments

We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, we adjust the carrying values of the asset downward, if necessary, to their estimated fair values.

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

Because our Jackalope and PRBIC equity method investments were acquired in 2013, any level of decrease in the forecasted cash flows of these investments or increases in the discount rates utilized to value those investments from their respective acquisition dates would likely result in the fair value of the equity method investment falling below their carrying value, and could result in an assessment of whether that investment is impaired.

During 2015, we recorded a $51.4 million and $23.4 million impairment of our Jackalope and PRBIC equity method investments, respectively, as a result of decreasing forecasted cash flows and increasing the discount rate utilized in determining the fair value of the equity method investment considering the continued decrease in commodity prices and its impact on the midstream industry and our equity method investments’ customers.

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We continue to monitor our equity method investments, and we could experience additional impairments of the remaining carrying value of these investments in the future if we receive additional negative information about market conditions or the intent of our equity method investments’ customers, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value of those investments.

Variable Interest Entities

We evaluate all legal entities in which we hold an ownership interest to determine if the entity is a variable interest entity (VIE). Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership or other interests in an entity that change with changes in the fair value of the VIE’s assets. When we conclude that we hold an interest in a VIE we must determine if we are the entity’s primary beneficiary. A primary beneficiary is deemed to have a controlling financial interest in a VIE.

We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any interests in a VIE that is not consolidated. Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use primarily a qualitative analysis to determine if an entity is a VIE. We evaluate the entity’s need for continuing financial support; the equity holder’s lack of a controlling financial interest; and/or if an equity holder’s voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We use primarily a qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE, either on a standalone basis or as part of a related party group. We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions. As a result of this analysis, we concluded that our investment in Crestwood Permian is a VIE that we are not the primary beneficiary of, and as a result, we account for our investment in Crestwood Permian as an equity method investment.

Our other equity investments are not considered to be VIEs. However, any future changes in the design or nature of the activities of these entities may require us to reconsider our conclusions associated with these entities. Such reconsideration would require the identification of the variable interests in the entity and a determination on which party is the entity’s primary beneficiary. If an equity investment were considered a VIE and we were determined to be the primary beneficiary, the change could cause us to consolidate the entity. The consolidation of an entity that is currently accounted for under the equity method could have a significant impact on our financial statements. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for more information on our equity method investments.

How We Evaluate Our Operations

We evaluate our overall business performance based primarily on EBITDA and Adjusted EBITDA. We do not utilize depreciation, amortization and accretion expense in our key measures because we focus our performance management on cash flow generation and our assets have long useful lives.

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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. We believe that EBITDA and Adjusted EBITDA are useful to our investors because it allows them to use the same performance measure analyzed internally by our management to evaluate the performance of our businesses and investments without regard to the manner in which they are financed or our capital structure. EBITDA is defined as income before income taxes, plus debt-related costs (interest and debt expense, net, and gain (loss) on modification/extinguishment of debt) and depreciation, amortization and accretion expense. Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates to reflect our proportionate share (based on the distribution percentage) of their EBITDA, excluding impairments. Adjusted EBITDA also considers the impact of certain significant items, such as unit-based compensation charges, gains and losses on long-lived assets, impairments of long-lived assets and goodwill, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, certain costs related to our historical cost saving initiatives, the change in fair value of commodity inventory-related derivative contracts, costs associated with our 2017 realignment of our Marketing, Supply and Logistics operations and related consolidation and relocation of our corporate offices, and other transactions identified in a specific reporting period. The change in fair value of commodity inventory-related derivative contracts is considered in determining Adjusted EBITDA given that the timing of recognizing gains and losses on these derivative contracts differs from the recognition of revenue for the related underlying sale of inventory to which these derivatives relate. Changes in the fair value of other derivative contracts is not considered in determining Adjusted EBITDA given the relatively short-term nature of those derivative contracts. 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 as alternatives to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.

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

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Results of Operations

The following table summarizes our results of operations (in millions).

	Crestwood Equity									Crestwood Midstream
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017			2016
Revenues	$	3,880.9		$	2,520.5		$	2,632.8		$	3,880.9		$	2,520.5
Costs of product/services sold	3,374.7			1,925.1			1,883.5			3,374.7			1,925.1
Operations and maintenance	136.0			158.1			190.2			136.0			155.0
General and administrative	96.5			88.2			116.3			93.1			85.6
Depreciation, amortization and accretion	191.7			229.6			300.1			202.7			240.5
Loss on long-lived assets, net	(65.6		)	(65.6		)	(821.2		)	(65.6		)	(65.6		)
Goodwill impairment	(38.8		)	(162.6		)	(1,406.3		)	(38.8		)	(162.6		)
Loss on contingent consideration	(57.0		)	—			—			(57.0		)	—
Operating loss	(79.4		)	(108.7		)	(2,084.8		)	(87.0		)	(113.9		)
Earnings (loss) from unconsolidated affiliates, net	47.8			31.5			(60.8		)	47.8			31.5
Interest and debt expense, net	(99.4		)	(125.1		)	(140.1		)	(99.4		)	(125.1		)
Gain (loss) on modification/extinguishment of debt	(37.7		)	10.0			(20.0		)	(37.7		)	10.0
Other income, net	1.3			0.5			0.6			0.8			—
(Provision) benefit for income taxes	0.8			(0.3		)	1.4			—			—
Net loss	(166.6		)	(192.1		)	(2,303.7		)	(175.5		)	(197.5		)
Add:
Interest and debt expense, net	99.4			125.1			140.1			99.4			125.1
(Gain) loss on modification/extinguishment of debt	37.7			(10.0		)	20.0			37.7			(10.0		)
Provision (benefit) for income taxes	(0.8		)	0.3			(1.4		)	—			—
Depreciation, amortization and accretion	191.7			229.6			300.1			202.7			240.5
EBITDA	161.4			152.9			(1,844.9		)	164.3			158.1
Unit-based compensation charges	25.5			19.2			19.7			25.5			19.2
Loss on long-lived assets, net	65.6			65.6			821.2			65.6			65.6
Goodwill impairment	38.8			162.6			1,406.3			38.8			162.6
Loss on contingent consideration	57.0			—			—			57.0			—
(Earnings) loss from unconsolidated affiliates, net	(47.8		)	(31.5		)	60.8			(47.8		)	(31.5		)
Adjusted EBITDA from unconsolidated affiliates, net	80.3			61.1			25.3			80.3			61.1
Change in fair value of commodity inventory-related derivative contracts	2.2			14.1			5.4			2.2			14.1
Significant transaction and environmental-related costs and other items(1)	12.4			11.6			33.6			12.4			11.6
Adjusted EBITDA	$	395.4		$	455.6		$	527.4		$	398.3		$	460.8

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	Crestwood Equity									Crestwood Midstream
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017			2016
EBITDA:
Net cash provided by operating activities	$	255.9		$	346.1		$	440.7		$	262.2		$	353.8
Net changes in operating assets and liabilities	(0.3		)	(57.9		)	(98.0		)	(2.4		)	(56.8		)
Amortization of debt-related deferred costs, discounts and premiums	(7.2		)	(6.9		)	(8.9		)	(7.2		)	(6.9		)
Interest and debt expense, net	99.4			125.1			140.1			99.4			125.1
Market adjustment on interest rate swaps	—			—			0.5			—			—
Unit-based compensation charges	(25.5		)	(19.2		)	(19.7		)	(25.5		)	(19.2		)
Loss on long-lived assets, net	(65.6		)	(65.6		)	(821.2		)	(65.6		)	(65.6		)
Goodwill impairment	(38.8		)	(162.6		)	(1,406.3		)	(38.8		)	(162.6		)
Loss on contingent consideration	(57.0		)	—			—			(57.0		)	—
Earnings (loss) from unconsolidated affiliates, net, adjusted for cash distributions received	0.1			(7.6		)	(73.6		)	0.1			(7.6		)
Deferred income taxes	2.1			3.1			3.6			—			(0.2		)
Provision (benefit) for income taxes	(0.8		)	0.3			(1.4		)	—			—
Other non-cash expense	(0.9		)	(1.9		)	(0.7		)	(0.9		)	(1.9		)
EBITDA	161.4			152.9			(1,844.9		)	164.3			158.1
Unit-based compensation charges	25.5			19.2			19.7			25.5			19.2
Loss on long-lived assets, net	65.6			65.6			821.2			65.6			65.6
Goodwill impairment	38.8			162.6			1,406.3			38.8			162.6
Loss on contingent consideration	57.0			—			—			57.0			—
(Earnings) loss from unconsolidated affiliates, net	(47.8		)	(31.5		)	60.8			(47.8		)	(31.5		)
Adjusted EBITDA from unconsolidated affiliates, net	80.3			61.1			25.3			80.3			61.1
Change in fair value of commodity inventory-related derivative contracts	2.2			14.1			5.4			2.2			14.1
Significant transaction and environmental-related costs and other items(1)	12.4			11.6			33.6			12.4			11.6
Adjusted EBITDA	$	395.4		$	455.6		$	527.4		$	398.3		$	460.8

(1) Significant transaction and environmental-related costs and other items for the years ended December 31, 2017, 2016 and 2015, primarily include costs incurred related to the Simplification Merger and other merger, acquisition and joint venture transactions, as well as costs associated with our historical cost savings initiatives and the realignment of our MS&L operations and related consolidation and relocation of our corporate offices.

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Segment Results

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

Crestwood Equity	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics
Revenues	$	1,688.2		$	37.2		$	2,155.5
Intersegment revenues	134.5			6.7			(141.2		)
Costs of product/services sold	1,480.8			0.3			1,893.6
Operations and maintenance expenses	68.4			4.2			63.4
Loss on long-lived assets, net	(14.4		)	—			(48.2		)
Goodwill impairments	—			—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—
Earnings from unconsolidated affiliates, net	18.9			28.9			—
Other income, net	0.8			—			—
EBITDA for the year ended December 31, 2017	$	278.8		$	11.3		$	(29.7	)
Revenues	$	1,118.8		$	165.3		$	1,236.4
Intersegment revenues	108.6			4.2			(112.8		)
Costs of product/services sold	917.0			5.1			1,003.0
Operations and maintenance expenses	77.0			21.4			59.7
Loss on long-lived assets, net	(2.0		)	(32.2		)	(31.4		)
Goodwill impairments	(8.6		)	(44.9		)	(109.1		)
Earnings from unconsolidated affiliates, net	20.3			11.2			—
EBITDA for the year ended December 31, 2016	$	243.1		$	77.1		$	(79.6	)
Revenues	$	1,381.0		$	266.3		$	985.5
Intersegment revenues	66.7			—			(66.7		)
Costs of product/services sold	1,103.9			20.1			759.5
Operations and maintenance expenses	89.0			31.7			69.5
Loss on long-lived assets, net	(787.3		)	(1.6		)	(32.3		)
Goodwill impairments	(329.7		)	(623.4		)	(453.2		)
Loss from unconsolidated affiliates, net	(43.4		)	(17.4		)	—
EBITDA for the year ended December 31, 2015	$	(905.6	)	$	(427.9	)	$	(395.7	)

Crestwood Midstream
Revenues	$	1,688.2		$	37.2		$	2,155.5
Intersegment revenues	134.5			6.7			(141.2		)
Costs of product/services sold	1,480.8			0.3			1,893.6
Operations and maintenance expenses	68.4			4.2			63.4
Loss on long-lived assets net	(14.4		)	—			(48.2		)
Goodwill impairments	—			—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—
Earnings from unconsolidated affiliates, net	18.9			28.9			—
Other income, net	0.8			—			—
EBITDA for the year ended December 31, 2017	$	278.8		$	11.3		$	(29.7	)
Revenues	$	1,118.8		$	165.3		$	1,236.4
Intersegment revenues	108.6			4.2			(112.8		)
Costs of product/services sold	917.0			5.1			1,003.0
Operations and maintenance expenses	77.0			18.3			59.7
Loss on long-lived assets, net	(2.0		)	(32.2		)	(31.4		)
Goodwill impairments	(8.6		)	(44.9		)	(109.1		)
Earnings from unconsolidated affiliates, net	20.3			11.2			—
EBITDA for the year ended December 31, 2016	$	243.1		$	80.2		$	(79.6	)

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Segment Results

Below is a discussion of the factors that impacted EBITDA by segment for the years ended December 31, 2017, 2016 and 2015.

Gathering and Processing

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

EBITDA for CEQP’s and CMLP’s gathering and processing segment increased by approximately $35.7 million for the year ended December 31, 2017 compared to 2016. During the year ended December 31, 2017, our gathering and processing segment’s revenues increased by approximately $595.3 million compared to 2017, partially offset by an increase in costs of product/services sold of approximately $563.8 million during 2017 compared to 2016.

The increases in revenues and costs during the year ended December 31, 2017 were primarily driven by our Arrow operations, which experienced a $611.0 million increase in revenues and a $578.5 million increase in costs of product/services compared to 2016. The increase in Arrow’s revenues and costs was primarily driven by higher average prices on Arrow’s agreements under which it purchases and sells crude oil. In addition, crude, gas and water volumes gathered by our Arrow system increased by 30%, 10% and 27%, respectively, during the year ended December 31, 2017 compared to 2016, due to the connection of 97 wells on our Arrow system during 2017 compared to 48 wells during 2016.

Partially offsetting the increase in our gathering and processing segment’s revenues and costs from our Arrow operations during the year ended December 31, 2017 compared to 2016, were lower revenues and costs of approximately $16.4 million and $10.6 million, respectively, from our Permian operations as a result of the deconsolidation of Crestwood New Mexico in June 2017. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6.

Our gathering and processing segment’s operations and maintenance expenses decreased by approximately $8.6 million during the year ended December 31, 2017 compared to 2016, due to continued cost-reduction efforts undertaken in our operations and the deconsolidation of Crestwood New Mexico.

Our gathering and processing segment’s EBITDA for the year ended December 31, 2017 includes a loss on long-lived assets of approximately $14.4 million, primarily related to the retirement and/or disposition of certain of our Marcellus and Arrow gathering and processing assets.

The comparability of our G&P segment’s EBITDA was impacted by an $8.6 million impairment recorded during the year ended December 31, 2016 related to our Marcellus operations. For a further discussion of these impairments, see “Critical Accounting Estimates and Policies” above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

Our gathering and processing segment’s EBITDA was also impacted by a decrease in earnings from unconsolidated affiliates of approximately $1.4 million during the year ended December 31, 2017 compared to 2016. The decrease was primarily driven by a $10.3 million decrease in equity earnings from Jackalope resulting from a reduction in revenues at the equity investment as a result of the restructuring of its contracts with Chesapeake effective January 1, 2017. Jackalope and Chesapeake replaced the cost-of-service based contract with a fixed-fee gathering and processing contract that includes minimum revenue guarantees for a five to seven year period. Partially offsetting the decrease in equity earnings from Jackalope was an increase in equity earnings from our Crestwood Permian equity investment of approximately $8.9 million during the year ended December 31, 2017 compared 2016, primarily due to the contribution of Crestwood New Mexico to Crestwood Permian in June 2017, and the Nautilus system coming online in June 2017.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

EBITDA for CEQP’s G&P segment increased by approximately $1,148.7 million for the year ended December 31, 2016 compared to 2015. The comparability of our G&P’s segment results year-over-year was significantly impacted by property, plant and equipment, intangible asset and goodwill impairments recorded during 2016 and 2015, which are further described below.

During the year ended December 31, 2016, our G&P segment’s revenues were lower by approximately $220.3 million compared to 2015, partially offset by lower costs of product/services sold of approximately $186.9 million. These decreases were primarily driven by our Arrow operations, which experienced a $193.9 million reduction in revenues during the year ended December 31, 2016 compared to 2015, offset by a $194.0 million decrease in costs of product/services sold. These

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decreases in Arrow’s revenues and costs were driven by lower market prices on crude oil, which caused average prices on Arrow’s agreements under which it purchases and sells crude to decrease. Gathering volumes on the Arrow system were relatively flat in 2016 compared to 2015.

Also contributing to the decrease in our G&P segment’s revenues were lower service revenues from our Marcellus and Barnett operations of approximately $20.7 million and $14.8 million, respectively, during the year ended December 31, 2016 compared to 2015. During the year ended December 31, 2016, we experienced a decrease in our gathering and compression volumes on our Marcellus system due to lack of drilling from our primary customer, Antero, as a result of the decline in commodity prices. Our gathering and compression volumes were 0.4 Bcf/d and 0.5 Bcf/d, respectively during the year ended December 31, 2016 compared to 0.5 Bcf/d and 0.6 Bcf/d during 2015. Our Barnett operations experienced a decrease in service revenues during 2016 compared to 2015 as a result of our primary customer, Quicksilver, ceasing drilling and shutting in production during the first quarter of 2016 as a result of its filing for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In April 2016, BlueStone bought Quicksilver’s assets out of bankruptcy and thereafter returned to production wells that were previously shut-in by Quicksilver. We entered into new 10-year gathering and processing agreements with BlueStone and pursuant to those agreements, BlueStone will not shut-in or choke back production for economic purposes through the end of 2018. As a result, gathering and processing volumes on our Barnett system have returned to levels relatively consistent with those preceding Quicksilver’s bankruptcy filing.

Partially offsetting the decreases from our Arrow, Marcellus and Barnett operations discussed above, were lower operations and maintenance expenses of $12.0 million during the year ended December 31, 2016 compared to 2015, primarily as a result of our cost reduction initiatives implemented in 2015.

Our G&P segment’s EBITDA was also impacted by a goodwill impairment of $8.6 million recorded during 2016 related to our Marcellus operations compared to property, plant and equipment, intangible asset and goodwill impairments of approximately $1,116.0 million recorded during 2015 related to our Barnett, Fayetteville, Granite Wash, and Haynesville operations. For a further discussion of these impairments, see “Critical Accounting Estimates and Policies” above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

Our G&P segment’s EBITDA was impacted by an increase in net earnings from unconsolidated affiliates of approximately $63.7 million. During the year ended December 31, 2016, earnings from our Jackalope equity investment increased by $64.2 million primarily due to a $51.4 million impairment recorded on the investment in 2015 and higher gathering and processing volumes at the facility resulting from Jackalope placing the Bucking Horse processing plant into service in 2015.

Storage and Transportation

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

EBITDA for CMLP’s storage and transportation segment decreased by approximately $68.9 million during the year ended December 31, 2017 compared to 2016. During the year ended December 31, 2017, our storage and transportation segment’s revenues were lower due to a reduction in revenues of approximately $51.1 million from our COLT Hub operations compared to 2016. The decrease was primarily due to a reduction in our rail throughput revenues from the expiration of two rail loading contracts in late 2016, a 58% decrease in rail loading volumes and lower margins resulting from higher average crude oil prices in the Bakken compared to other basins, which has decreased the demand and rates for our rail loading services in 2017 compared to 2016. Also impacting our storage and transportation segment’s EBITDA was $44.9 million of goodwill impairments recorded during the year ended December 31, 2016 related to our COLT Hub operations. For a further discussion of these impairments, see “Critical Accounting Estimates and Policies” above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

The comparability of our storage and transportation segment’s EBITDA was also impacted by a $57 million loss on contingent consideration recorded during the year ended December 31, 2017 related to our Stagecoach Gas joint venture. Pursuant to the Stagecoach Gas limited liability company agreement, we may be required to make payments of up to $57 million to CEGP after December 31, 2020 if certain criteria are not met by Stagecoach Gas by December 31, 2020, including achieving certain performance targets on growth capital projects. These growth capital projects depend on the construction of other third-party expansion projects, and during 2017, those third-party projects experienced regulatory and other delays that caused Stagecoach Gas to delay its growth capital projects. Although Stagecoach Gas anticipates that these growth capital projects will be constructed in the future, it does not expect that these projects will produce meaningful operating results prior to December 31, 2020.

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Our storage and transportation segment’s results was impacted by a $32.4 million loss recognized on the deconsolidation of our Northeast storage and transportation assets as a result of the contribution of these assets to the Stagecoach Gas joint venture in June 2016. The deconsolidation of the Northeast storage and transportation assets resulted in lower revenues and costs of product/services sold of approximately $74.5 million and $4.6 million, respectively, during the year ended December 31, 2017 compared to 2016. We also experienced lower operations and maintenance expenses of approximately $14.1 million during the year ended December 31, 2017 compared to 2016, primarily as a result of the deconsolidation of the Northeast storage and transportation assets. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 2 and 6 for a further discussion of the deconsolidation of our NE S&T assets.

Our storage and transportation segment’s EBITDA was impacted by an increase in earnings from our unconsolidated affiliates. As discussed above, in June 2016, we deconsolidated our Northeast storage and transportation assets as a result of the Stagecoach Gas transaction and began accounting for our 50% equity interest in Stagecoach Gas under the equity method of accounting. We recognized equity earnings from Stagecoach Gas of approximately $25.3 million and $15.9 million during the years ended December 31, 2017 and 2016. Earnings from our Tres Holdings equity investment increased by approximately $2.5 million during the year ended December 31, 2017 compared to 2016, primarily due to property tax accruals recorded by Tres Holdings during 2016.

EBITDA for CEQP’s storage and transportation segment decreased by approximately $65.8 million during the year ended December 31, 2017 compared to 2016. The change in CEQP’s storage and transportation segment’s EBITDA year-over-year was due to all the factors discussed above for CMLP. In addition, in June 2016, the Matagorda County court issued a final judgment related to Tres Palacios’ 2012 and 2013 property tax years which resulted in CEQP recording additional net property taxes (including interest and penalties) of approximately $2.9 million during the year ended December 31, 2016.

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

EBITDA for CEQP’s storage and transportation segment increased by approximately $505.0 million during the year ended December 31, 2016 compared to 2015. The comparability of our storage and transportation segment’s results year-over-year is primarily impacted by goodwill impairments recorded during 2016 and 2015, which are further described below. In addition, on June 3, 2016, we deconsolidated our NE S&T assets as a result of the contribution of the assets to Stagecoach Gas and we recognized a loss of $32.4 million. The deconsolidation of the NE S&T assets also resulted in lower revenues of approximately $102.3 million during the year ended December 31, 2016 compared to the 2015, partially offset by lower costs of product/services sold of approximately $8.7 million year-over-year. We also experienced lower operations and maintenance expense of approximately $11.9 million during the year ended December 31, 2016 compared to 2015, primarily as a result of the deconsolidation of the NE S&T assets. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 2 and 6 for a further discussion of the deconsolidation of our NE S&T assets.

Our COLT Hub operations experienced an increase in revenues of approximately $5.4 million during the year ended December 31, 2016 compared to 2015, primarily due to the recognition in income of previously deferred revenues related to two rail loading contracts that expired in late 2016, which was partially offset by a related reduction in our actual rail throughput revenues resulting from lower rail loading volumes primarily under those contracts. Our lower rail loading volumes were a result of narrowed crude oil locational differences in the Bakken, and were partially offset by a related decrease in costs of product/services sold of $6.3 million during the year ended December 31, 2016 compared to 2015.

Our storage and transportation segment’s EBITDA was also impacted by goodwill impairments related to our COLT Hub operations of approximately $44.9 million and $623.4 million during the years ended December 31, 2016 and 2015. For a further discussion of our goodwill impairments recorded during 2016 and 2015, see “Critical Accounting Estimates and Policies” above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

In June 2016, the Matagorda County court issued a final judgment related to Tres Palacios’ 2012 and 2013 property tax years which resulted in Crestwood Equity recording additional net property taxes (including interest and penalties) of approximately $2.9 million during the year ended December 31, 2016.

Our storage and transportation segment’s EBITDA was impacted by a $28.6 million increase in earnings from unconsolidated affiliates. As discussed above, effective June 3, 2016, we deconsolidated the NE S&T assets as a result of the Stagecoach Gas transaction and began accounting for our 50% equity interest in Stagecoach Gas under the equity method of accounting. We recognized equity earnings from Stagecoach Gas of approximately $15.9 million during the year ended December 31, 2016. Our equity earnings from Tres Holdings were lower by approximately $2.8 million during the year ended December 31, 2016 compared to the same period in 2015, primarily due to an increase in property tax accruals at the equity investment. Our equity earnings from our PRBIC equity investment increased by $15.5 million, primarily due to an impairment of $23.4 million of the

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investment recorded in 2015, partially offset by a $4.4 million loss from the investment in 2016 driven by an impairment recorded at the equity investee level due to declining actual and forecasted revenues from its major customer, Chesapeake.

Marketing, Supply and Logistics

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

EBITDA for our marketing, supply and logistics segment increased by approximately $49.9 million for the year ended December 31, 2017 compared to 2016. The comparability of our marketing, supply and logistics segment’s results was significantly impacted by goodwill, intangible assets and property, plant and equipment impairments of $121.0 million recorded during 2017 and goodwill and intangible asset impairments of $140.5 million recorded during 2016. For a further discussion of our impairments recorded during 2017 and 2016, see “Critical Accounting Estimates and Policies” above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

Our supply and logistics operations experienced an increase in revenues and costs of product/services sold of $465.0 million and $457.9 million, respectively, during the year ended December 31, 2017 compared to 2016. During 2016, we experienced unseasonably warm weather which resulted in lower demand for NGLs compared to increased demand experienced during 2017. The costs of product/services sold increase includes losses of $31.2 million and a loss of $7.8 million during the years ended December 31, 2017 and 2016 related to our commodity-based derivative contracts. These changes in the fair value of our derivative contracts resulted from higher average NGL prices compared to 2016, which resulted in an increase in our liabilities from price risk management activities associated with contracts that provide fixed prices on future sales of our NGL inventory.

During the year ended December 31, 2017, our storage and terminals operations (including our West Coast operations) experienced a $173.6 million and $174.4 million increase in revenues and costs of product/services sold, respectively, compared to 2016. These increases were primarily driven by increases in NGL prices during the year ended December 31, 2017. Although our net operating results were relatively consistent during the year ended December 31, 2017 compared to 2016, we experienced NGL market headwinds in the Northeast during 2017, with NGL exports and other market dynamics causing price differentials to narrow between purchasing NGLs in the summer (which are then stored in our NGL facilities) and selling NGLs in the winter. These dynamics also caused the rates that we are able to charge for storing NGLs in our facilities to decline from their historical levels. Also during 2017, our West Coast customers also experienced headwinds, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S. This caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Considering the fact that the net operating results of our storage and terminals operations (including West Coast) have been relatively consistent over the past several years, we do not anticipate that these operations will grow as fast or to the degree that we expected when we merged with Inergy, LP in 2013 given current market dynamics, which we believe will continue for the foreseeable future.

Revenues and costs of product/services sold from our crude and natural gas marketing operations increased by approximately $261.9 million and $260.5 million, respectively, during the year ended December 31, 2017 compared to 2016. These increases were primarily driven by higher crude marketing volumes due to increased marketing activity surrounding our crude-related operations.

Our NGL and crude trucking operations continued to experience lower operating results in 2017 compared to 2016, with a $12.4 million and $5.7 million decrease in revenues and costs of product/services sold during the year ended December 31, 2017 compared to 2016. This decrease was primarily a result of the realignment of our trucking operations in 2017 to reduce the size of our trucking fleet in response to the continued decline in demand for trucking services due to the continued lower commodity price environment.

Our marketing, supply and logistic segment’s operations and maintenance expenses increased by approximately $3.7 million during the year ended December 31, 2017 compared to 2016. In 2016, we received a $3.1 million property tax refund related to our West Coast operations.

In December 2017, we sold 100% of our equity interests in US Salt to an affiliate of Kissner Group Holdings LP for net proceeds of approximately $223.6 million, and we recognized a gain of approximately $33.6 million from the sale. For a further discussion of this sale, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.

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Year Ended December 31, 2016 Compared to Year Ended December 31, 2015

EBITDA for our marketing, supply and logistics segment increased by approximately $316.1 million during the year ended December 31, 2016 compared to 2015. The comparability of our marketing, supply and logistics segment’s results year over year is impacted by goodwill impairments recorded during 2016 and 2015, which are further described below.

Our NGL and crude trucking operations experienced a continued decrease in the demand for their services due to lower volumes, increased competition, excess trucking capacity in the market place and the low commodity price environment during the year ended December 31, 2016, resulting in a 18% and 65% decrease in NGL and crude volumes transported, respectively, compared to 2015. This resulted in a $34.6 million decrease in revenues during the year ended December 31, 2016 compared to 2015, and a $21.8 million decrease in costs of services sold from these operations during the same period.

During the year ended December 31, 2016, our storage and terminals operations (including our West Coast operations) experienced a $147.7 million increase in revenues compared to 2015, in addition to an increase in costs of product/services sold of approximately $167.6 million. Although these operations experienced an increase in demand for its propane-related services year-over-year, it experienced lower demand for its butane-related services (which tend to generate higher per unit margins than its propane services). The lower butane demand was driven by lower NGL commodity prices and tightening of basis differentials on these operations in 2016 compared to 2015.

Our supply and logistics operations experienced a decrease in revenues of approximately $58.0 million and a decrease in costs of product/services sold of $51.0 million during the year ended December 31, 2016 compared to 2015. These decreases were due to the low commodity price environment coupled with warmer weather during 2016 compared to 2015, which resulted in lower demand for the butane-related services provided by these operations. These revenues and costs of services decreases include a loss of $7.8 million on our commodity-based derivative contracts of during the year ended December 31, 2016 and a gain of $18.9 million during the year ended December 31, 2015.

During the year ended December 31, 2016, revenues from our crude marketing operations increased by approximately $146.8 million compared to 2015, in addition to an increase of approximately $147.6 million in our costs of product/services sold year-over-year, both of which were driven by higher crude marketing volumes due to increased marketing activity surrounding our crude-related operations during 2016.

Our marketing, supply and logistics segment’s operations and maintenance expense decreased by $9.8 million during the year ended December 31, 2016 compared to 2015, primarily due to our cost-savings initiative implemented in 2015.

Our marketing, supply and logistics segment’s EBITDA for the year ended December 31, 2016 was also impacted by intangible asset and goodwill impairments of approximately $140.5 million related to our supply and logistics, storage and terminals and trucking operations compared to property, plant and equipment and goodwill impairments of $484.4 million related to our West Coast, supply and logistics, storage and terminals, trucking and Watkins Glen operations in 2015. For a further discussion of our impairments recorded during 2016 and 2015, see “Critical Accounting Estimates” above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

Other EBITDA Results

General and Administrative Expenses.

During the year ended December 31, 2017, our general and administrative expenses increased compared to 2016, primarily due to an increase in unit-based compensation charges based on higher average awards outstanding in 2017 compared to 2016, and the impact of performance units granted during 2017 under the Crestwood Equity Long Term Incentive Plan (Crestwood LTIP). For a further discussion of Crestwood LTIP, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13. In addition, we incurred additional expense during the year ended December 31, 2017, related to the consolidation and relocation of our three corporate offices into two offices located in Houston and Kansas City.

During 2015, we completed a number of cost-reduction efforts, including the Simplification Merger (see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2 for a discussion of the Simplification Merger), and as a result we decreased our ongoing operations and maintenance expense and general and administrative expense. During the year ended December 31, 2016 compared to 2015, we experienced a decrease of approximately $28.1 million in Crestwood Equity’s general and administrative expenses primarily as a result of our cost-savings initiatives.

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Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense. During the year ended December 31, 2017, our depreciation, amortization and accretion expense decreased compared to 2016 and 2015, primarily due to the deconsolidation of our Crestwood New Mexico operations in June 2017, the deconsolidation of our NE S&T assets in June 2016, and a reduction in the carrying value of certain of our assets as a result of impairments on our property, plant and equipment and intangible assets recorded during 2015.

Interest and Debt Expense, Net. During the year ended December 31, 2017, interest and debt expense, net decreased compared to 2016 and 2015, primarily due to the repayments of Crestwood Midstream’s 2020 Senior Notes and 2022 Senior Notes. For a discussion of our long-term debt and related transactions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 9.

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

	CEQP						CMLP
	Year Ended December 31,						Year Ended December 31,
	2017		2016		2015		2017		2016		2015
Credit facilities	$	18.6	$	18.7	$	25.2	$	18.6	$	18.7	$	17.2
Senior notes	76.4		99.9		108.4		76.4		99.9		107.8
Other debt-related costs	7.3		7.2		9.0		7.3		7.2		8.0
Gross interest and debt expense	102.3		125.8		142.6		102.3		125.8		133.0
Less: capitalized interest	2.9		0.7		2.5		2.9		0.7		2.5
Interest and debt expense, net	$	99.4	$	125.1	$	140.1	$	99.4	$	125.1	$	130.5

Gain (Loss) on Modification/Extinguishment of Debt. During the year ended December 31, 2017, we recognized a loss on extinguishment of debt of approximately $37.7 million in conjunction with the tender of the remaining principal amounts of

Crestwood Midstream's 2020 Senior Notes and 2022 Senior Notes. During the year ended December 31, 2016, we recognized a gain on extinguishment of debt of approximately $10.0 million in conjunction with the early tender of a portion of Crestwood Midstream’s 2020 Senior Notes and 2022 Senior Notes.

During the year ended December 31, 2015, we recognized a $20.0 million loss on extinguishment of debt related to the termination of Crestwood Equity’s credit facility, the redemption of Crestwood Midstream’s 2019 Senior Notes and modification of Crestwood Midstream’s credit facility.

Net Income (Loss) Attributable to Non-Controlling Partners. In September 2015, Crestwood Midstream became a wholly-owned subsidiary of Crestwood Equity as a result of the Simplification Merger, which materially impacted the change in Crestwood Equity’s net income (loss) attributable to non-controlling partners for the year ended December 31, 2016 compared to 2015. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 12 for further detail of Crestwood Equity’s net income (loss) attributable to non-controlling partners.

Liquidity and Sources of Capital

Crestwood Equity is a holding company that derives all of its operating cash flow from its operating subsidiaries.  Our principal sources of liquidity include cash generated by operating activities from our subsidiaries, distributions from our joint ventures, borrowings under the CMLP credit facility, and sales of equity and debt securities. Our operating subsidiaries use cash from their respective operations to fund their operating activities, maintenance and growth capital expenditures, and service their outstanding indebtedness. We believe our liquidity sources and operating cash flows are sufficient to address our future operating, debt service and capital requirements.

We make cash quarterly distributions to our common unitholders within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to our available cash for such quarter. We also pay cash quarterly distributions of approximately $15 million to our preferred unitholders. We believe our operating cash flows will well exceed cash distributions to our partners and our preferred unitholders at current levels, and as a result, we will have substantial operating cash flows as a source of liquidity for our growth capital expenditures.

In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP for

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net proceeds of approximately $223.6 million. We used the proceeds from the divestiture to reduce borrowings under the CMLP credit facility and reinvest in on-going organic growth projects in the Bakken and Delaware Basin discussed in Outlook and Trends above, and we expect the proceeds from this divestiture will eliminate the need to access the equity capital markets to fund our current capital programs.

As of December 31, 2017, we had $499.3 million of available capacity under our credit facility considering the most restrictive debt covenants in the credit agreement. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, tender offers or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. As of December 31, 2017, we were in compliance with all of our debt covenants applicable to the credit facility and our senior notes. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 9 for a more detailed description of the credit facility and senior notes.

The following table provides a summary of Crestwood Equity’s cash flows by category (in millions):

	Year Ended December 31,
	2017			2016			2015
Net cash provided by operating activities	$	255.9		$	346.1		$	440.7
Net cash provided by (used in) investing activities	38.7			867.2			(212.7		)
Net cash used in financing activities	(294.9		)	(1,212.2		)	(236.3		)

Operating Activities

Our operating cash flows decreased approximately $90.2 million for the year ended December 31, 2017 compared to 2016, primarily due to a $125.6 million decrease in our storage and transportation segment’s revenues primarily due to the deconsolidation of our Northeast storage and transportation assets and a reduction in rail throughput revenues from our COLT operations. This was partially offset by a $1,488.5 million increase in revenues from our gathering and processing and marketing, supply and logistics operations discussed above, offset by a $1,449.6 million increase in costs of product/services sold primarily related to these segments’ operations.

Our operating cash flows decreased approximately $94.6 million for the year ended December 31, 2016 compared to 2015, primarily due to a $112.3 million decrease in operating revenues as a result of the deconsolidation of the NE S&T assets in June 2016 and from our gathering and processing segment’s operations due primarily to the effect of lower commodity prices on that segment. The unfavorable cash flow impacts were partially offset by lower operations and maintenance expenses of approximately $32.1 million, primarily due to the deconsolidation of the NE S&T assets.

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.

During 2018, we anticipate growth capital expenditures of approximately $250 million to $300 million, which includes contributions to our equity investments related to their capital projects. In addition, we expect to spend between approximately $15 million to $20 million on maintenance capital expenditures and approximately $25 million to $30 million on capital expenditures that are directly reimbursable by our customers. We anticipate that our growth and reimbursable capital expenditures in 2018 will increase the services we can provide to our customers and the operating efficiencies of our systems. We expect to finance our capital expenditures with a combination of cash generated by our operating subsidiaries, distributions received from our equity investments and borrowings under our credit facility.

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We have identified additional growth capital project opportunities for each of our reporting segments. Additional commitments or expenditures will be made at our discretion, and any discontinuation of the construction of these projects will likely result in less future cash flow and earnings. The following table summarizes our capital expenditures for the year ended December 31, 2017 (in millions).

Growth capital	$	141.4
Maintenance capital	22.0
Other(1)	25.0
Purchases of property, plant and equipment	188.4
Reimbursements of property, plant and equipment	(19.6		)
Net	$	168.8

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

In addition to the capital expenditures described in the table above, our cash flows from investing activities were also impacted by the following significant items during the years ended December 31, 2017, 2016 and 2015:

Net Proceeds from the Sale of Assets. In December 2017, we sold 100% of our equity interests in US Salt to an affiliate of Kissner Group Holdings LP for net proceeds of approximately $223.6 million. In June 2016, we contributed to Stagecoach Gas the entities owning the NE S&T assets, CEGP contributed $975 million in exchange for a 50% equity interest in Stagecoach Gas, and Stagecoach Gas distributed to us the net cash proceeds received from CEGP. For a further discussion of these transactions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 2, 3 and 6.

Investments in Unconsolidated Affiliates. During the years ended December 31, 2017, 2016 and 2015, we made cash contributions of approximately $58 million, $12.4 million and $42 million, respectively, to our joint ventures to fund their growth capital projects and their operating activities. In addition, in June 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico at our historical book value of approximately $69.4 million. This contribution was treated as a non-cash transaction between entities under common control.

Distributions from our joint ventures increased during each of the three years ended December 31, 2017, primarily due to the formation of the Crestwood Permian and Stagecoach joint ventures in October 2016 and June 2016, respectively. In addition, we experienced an increase in distributions from our Jackalope equity investment during the year ended December 31, 2016 compared to 2015, as a result of Jackalope placing an expansion project into service in 2015.

Financing Activities

Significant items impacting our financing activities during the years ended December 31, 2017, 2016 and 2015 included the following:

Equity Transactions

• In December 2017, Crestwood Niobrara redeemed 100% of the outstanding preferred units issued to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE) for an aggregate purchase price of $202.7 million and issued $175 million of new preferred units to CN Jackalope Holdings LLC. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 12;

• Distributions to preferred unitholders of approximately $15 million; prior to September 30, 2017, we had the option to make quarterly distributions to our preferred unitholders by issuing additional preferred units;

• Decrease in distributions to partners of approximately $52.2 million during the year ended December 31, 2017 compared to 2016, primarily due to a reduction in distributions paid per limited partner unit from $1.375 to $0.60 beginning with the first quarter 2016 distribution; increase in distributions to partners of approximately $48.3 million for the year ended December 31, 2016 compared to 2015, primarily due to the increase in the number of limited partner units outstanding as a result of the Simplification Merger;

• Decrease in distributions paid to non-controlling partners of $219 million in 2016 compared to 2015, due primarily to the Simplification Merger; distributions paid to non-controlling partners during the year ended December 31, 2017 were flat compared to 2016;

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• $15.2 million of net proceeds from the issuance of CEQP common units during the year ended December 31, 2017; and

• Increase in taxes paid for unit-based compensation vesting of approximately $4.7 million, primarily due to higher vesting of unit-based compensation awards during the year ended December 31, 2017 compared to 2016.

Debt Transactions

• During the year ended December 31, 2017, our debt-related transactions resulted in net repayments of approximately $76.3 million compared to net repayments of $974.5 million in 2016 and net proceeds of $131.5 million in 2015. During 2017 and 2016, we redeemed all amounts outstanding under Crestwood Midstream’s 2020 Senior Notes and 2022 Senior Notes. During 2017 and 2015, we issued $500 million of senior unsecured notes due in 2025 and $700 million senior unsecured notes due in 2023, respectively. For a further discussion of these and other debt-related transactions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 9.

Contractual Obligations

We are party to various contractual obligations. A portion of these obligations are reflected in our financial statements, such as long-term debt and other accrued liabilities, while other obligations, such as operating leases, capital commitments and contractual interest amounts are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of December 31, 2017 (in millions):

	Less than 1 Year		1-3 Years		3-5 Years		Thereafter		Total
Long-term debt:
Principal	$	0.9	$	319.3	$	0.4	$	1,200.0	$	1,520.6
Interest(1)	85.9		162.9		145.0		75.6		469.4
Future minimum payments under operating leases(2)	35.2		53.3		19.2		18.8		126.5
Asset retirement obligations	—		—		—		27.5		27.5
Fixed price commodity purchase commitments(3)	447.3		32.0		—		—		479.3
Standby letters of credit	52.2		—		—		—		52.2
Purchase commitments and other contractual obligations(4)	65.8		—		—		—		65.8
Total contractual obligations	$	687.3	$	567.5	$	164.6	$	1,321.9	$	2,741.3

(1) $318.2 million of our long-term debt is variable interest rate debt at Alternate Base rate or Eurodollar rate plus an applicable spread. These rates plus their applicable spreads were between 3.94% and 6.00% at December 31, 2017. These rates have been applied for each period presented in the table.

(2) See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 15 for a further discussion of these obligations.

(3) Fixed price purchase commitments are volumetrically offset by third party fixed price sale contracts.

(4) Primarily related to growth and maintenance contractual purchase obligations in our G&P segment and environmental obligations included in other current liabilities on our balance sheet. Other contractual purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations.

Off-Balance Sheet Arrangements

As of December 31, 2017, we have not entered into any transactions, agreements or other arrangements that would result in off-balance sheet liabilities.

Our equity interest in Crestwood Permian is considered to be a variable interest entity. We are not the primary beneficiary of Crestwood Permian and as a result, we account for our investment in Crestwood Permian as an equity method investment. For a further discussion of our investment in Crestwood Permian, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable rate debt. The market risk inherent in our debt instruments is the potential change arising from increases or decreases in interest rates as discussed below.

For fixed rate debt, changes in the interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows.

As of December 31, 2017, both the carrying value and fair value of our fixed rate debt instruments was approximately $1.2 billion. As of December 31, 2016, both the carrying value and fair value of our fixed rate debt instruments (including debt fair value adjustments) was approximately $1.5 billion. For a further discussion of our fixed rate debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules, Note 9.

We are subject to the risk of loss associated with changes in interest rates on our credit facility. At December 31, 2017, we had obligations totaling $318.2 million outstanding under the credit facility. These obligations expose us to the risk of increased interest payments in the event of increases in short-term interest rates. Floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the interest rate on the our credit facility were to fluctuate by 1% from the rate as of December 31, 2017, our annual interest expense would have changed by approximately $3.2 million.

Commodity Price, Market and Credit Risk

Inherent in our business are certain business risks, including market risk and credit risk.

Market Risk

We typically do not take title to the natural gas, NGLs or crude oil that we gather, store, or transport for our customers. However, we do take title to (i) the NGLs and crude oil marketed or supplied by our NGL and crude oil supply and logistics operations (marketing, supply and logistics segment); (ii) NGLs under certain of our percent-of-proceeds contracts (G&P segment); and (iii) crude oil and natural gas purchased from our Arrow and Granite Wash producer customers (G&P segment).  Our current business model is designed to minimize our exposure to fluctuations in commodity prices, although we are willing to assume commodity price risk in certain processing and marketing activities.  We remain subject to volumetric risk under contracts without minimal volume commitments or take-or-pay pricing terms, but absent other market factors that could adversely impact our operations (i.e., market conditions that negatively influence our producer customers’ decisions to develop or produce hydrocarbons), changes in the price of natural gas, NGLs or crude oil should not materially impact our operations. 

In our marketing, supply and logistics operations, we consider market risk to be the risk that the value of our NGL and crude services segment’s portfolio will change, either favorably or unfavorably, in response to changing market conditions. We take an active role in managing and controlling market risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. 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 December 31, 2017, were energy marketers, propane retailers, resellers, and dealers.

We engage in hedging and risk management transactions, including various types of forward contracts, options, swaps and futures contracts, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions and to help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes only when we have a matching purchase commitment from our marketing customers. However, we may experience net unbalanced positions from time to time, which we believe to be immaterial in amount. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio. These derivatives are not designated as hedges for accounting purposes.

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The fair value of the derivatives contracts related to price risk management activities as of December 31, 2017 were assets of $7.2 million and liabilities of $48.9 million. We use observable market values for determining the fair value of our trading instruments. In cases where actively quoted prices are not available, other external sources are used that incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis. Our risk management department regularly compares valuations to independent sources and models on a quarterly basis. A theoretical change of 10% in the underlying commodity value would result in a $8.6 million change in the market value of these contracts as there were approximately 2 MMBbls of net unbalanced positions at December 31, 2017. Inventory positions of approximately 2 MMBbls would substantially offset this theoretical change at December 31, 2017.

Credit Risk

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 and controlling credit risk and have established control procedures, which are reviewed on an ongoing basis. We have diversified our credit risk through having long-term contracts with many investment grade customers and creditworthy producers. Additionally, we perform credit analyses of our customers on a regular basis pursuant to our corporate credit policy. We have not had any significant losses due to failures to perform by our counterparties.

Under a number of our customer contracts, there are provisions that provide for our right to request or demand credit assurances from our customers including the posting of letters of credit, surety bonds, cash margin or collateral held in escrow for varying levels of future revenues. We continue to closely monitor our producer customer base since a majority of our customers in our consolidated gathering and processing and storage and transportation operations are either not rated by the major rating agencies or had below investment grade credit ratings.

Item 8. Financial Statements and Supplementary Data

Reference is made to the financial statements and report of independent registered public accounting firm included later in this report under Part IV, Item 15. Exhibits, Financial Statement Schedules.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.

Item 9A. Controls and Procedures

Disclosure Controls and Procedures

As of December 31, 2017, Crestwood Equity and Crestwood Midstream carried out an evaluation under the supervision and with the participation of their respective management, including the Chief Executive Officers and Chief Financial Officers of their General Partners, 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)). Crestwood Equity and Crestwood Midstream maintain controls and procedures designed to provide reasonable assurance that information required to be disclosed in their respective reports that are filed or submitted 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 their respective management, including the Chief Executive Officers and Chief Financial Officers of their General Partners, as appropriate, to allow timely decisions regarding required disclosure. Such management, including the Chief Executive Officers and Chief Financial Officers of their General Partners, does not expect that the disclosure controls and procedures or the 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. Crestwood Equity’s and Crestwood Midstream’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and the Chief Executive Officers and Chief Financial Officers of their General Partners concluded that such disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2017.

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Changes in Internal Control over Financial Reporting

There have been no changes in Crestwood Equity’s or Crestwood Midstream’s internal control over financial reporting during the fourth quarter of 2017 that have materially affected, or are reasonably likely to materially affect Crestwood Equity’s and Crestwood Midstream’s internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Crestwood Equity’s and Crestwood Midstream’s management is responsible for establishing and maintaining adequate internal control over financial reporting, pursuant to Exchange Act Rules 13a-15(f). Crestwood Equity’s and Crestwood Midstream’s internal control systems were designed to provide reasonable assurance to their respective management and board of directors regarding the preparation and fair presentation of published financial statements in accordance with GAAP.

Management recognizes that there are inherent limitations in the effectiveness of any system of internal control, and accordingly, even effective internal control can provide only reasonable assurance with respect to financial statement preparation and fair presentation. Further, because of changes in conditions, the effectiveness of internal control may vary over time.

Under the supervision and with the participation of Crestwood Equity’s and Crestwood Midstream’s management, including the Chief Executive Officers and Chief Financial Officers, Crestwood Equity and Crestwood Midstream assessed the effectiveness of their respective internal control over financial reporting as of December 31, 2017. In making this assessment, Crestwood Equity and Crestwood Midstream used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based upon such assessment, Crestwood Equity and Crestwood Midstream concluded that, as of December 31, 2017, their respective internal control over financial reporting is effective, based upon those criteria.

Crestwood Equity’s independent registered public accounting firm, Ernst & Young LLP, issued an attestation report dated February 23, 2018, on the effectiveness of our internal control over financial reporting, which is included herein.

Item 9B. Other Information

On February22, 2018, Crestwood Operations entered into an Omnibus Amendment to each Executive Employment

Agreement for Messrs. Phillips, Halpin, Moore, Dougherty and Lambert (“Omnibus Amendment”). Pursuant to the Omnibus Amendment, if, on or before July 1, 2019, there is a Change in Control (as defined in the Omnibus Amendment), the Partnership will issue 150,000 restricted units to Mr. Phillips, 100,000 restricted units to Mr. Halpin, and 75,000 restricted units to Messrs. Moore, Dougherty and Lambert, respectively, which units will be fully vested on their issuance date. Furthermore, if the employment of Messrs. Halpin, Moore, Dougherty or Lambert is terminated during the period beginning three months prior to a Change in Control and ending twelve months after a Change in Control, then the severance amount payable shall be increased to three (3) times base salary and average annual bonus for the prior two years.

The foregoing summary of the material provisions of the Omnibus Amendment is intended to be general in nature and is qualified by the full text of the Omnibus Amendment, which is incorporated by reference herein as an exhibit to the Annual Report on Form 10-K.

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PART III

Item 10, “Directors, Executive Officers and Corporate Governance;” Item 11, “Executive Compensation;” Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters;” and Item 13, “Certain Relationships and Related Transactions, and Director Independence” have been omitted from this report for Crestwood Midstream pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.

Item 10. Directors, Executive Officers and Corporate Governance

Our General Partner Manages Crestwood Equity Partners LP

Crestwood Equity GP LLC, our general partner, manages our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 ²/₃% of the outstanding units, including units held by the general partner and their affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of the general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. Unitholders do not directly or indirectly participate in our management or operations. Our general partner owes a fiduciary duty to the unitholders. Our general partner is liable, as a general partner, for all of our debts (to the extent not paid from our assets), except for specific nonrecourse indebtedness or other obligations. Whenever possible, our general partner intends to incur indebtedness or other obligations that are nonrecourse.

As is commonly the case with publicly-traded limited partnerships, we are managed and operated by the officers of our general partner and are subject to the oversight of the directors of our general partner. The board of directors of our general partner is presently composed of seven directors.

Directors and Executive Officers

The following table sets forth certain information with respect to the executive officers and members of the board of directors of our general partner. Executive officers and directors will serve until their successors are duly appointed or elected.

Executive Officers and Directors	Age	Position with our General Partner
Robert G. Phillips	63	President, Chief Executive Officer and Director
J. Heath Deneke	44	Executive Vice President, Chief Operating Officer
Robert T. Halpin	34	Executive Vice President, Chief Financial Officer
Steven M. Dougherty	45	Senior Vice President, Chief Accounting Officer
Joel C. Lambert	49	Senior Vice President, General Counsel and Chief Compliance Officer
William H. Moore	38	Senior Vice President, Strategy and Corporate Development
Alvin Bledsoe	69	Director
Michael G. France	40	Director
Warren H. Gfeller	65	Director
David Lumpkins	63	Director
John J. Sherman	62	Director
John W. Somerhalder II	62	Director

Robert G. Phillips was elected Chairman, President and Chief Executive Officer of our general partner in June 2013 and has served on the Management Committee of Crestwood Holdings since May 2010. He served as Chairman, President and CEO of Legacy Crestwood from November 2007 until October 2013. Previously, Mr. Phillips served as President and Chief Executive Officer and a Director of Enterprise Products Partners L.P. from February 2005 until June 2007 and Chief Operating Officer and a Director of Enterprise Products Partners L.P. from September 2004 until February 2005. Mr. Phillips also served on the Board of Directors of Enterprise GP Holdings L.P., the general partner of Enterprise Products Partners L.P., from February 2006 until April 2007. He previously served as Chairman of the Board and CEO of GulfTerra Energy Partners, L.P. (GTM), from 1999 to 2004, prior to GTM’s merger with Enterprise Product Partners, LP, and held senior executive management positions with El Paso Corporation, including President of El Paso Field Services from 1996-2004. Prior to that he was Chairman, President and CEO of Eastex Energy, Inc. from 1981-1995. Mr. Phillips previously served as a Director of Pride International, Inc. from October 2007 to May 31, 2011, one of the world’s largest offshore drilling contractors, and was a member of its audit committee. Mr. Phillips has served as a Director of Bonavista Energy Corporation , a Canadian independent oil and gas producer, since May 2015, and is a member of its compensation and governance committees. Mr. Phillips holds a

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B.B.A. from The University of Texas at Austin and a Juris Doctorate from South Texas College of Law. Mr. Phillips was selected to serve as the Chairman of the Board of our general partner because of his deep experience in the midstream business, expansive knowledge of the oil and gas industry, as well as his experience in executive leadership roles for public companies in the energy industry and operational and financial expertise in the oil and gas business generally.

J. Heath Deneke was appointed President, Chief Operating Officer, Pipeline Services Group in June 2015. He served as President, Chief Operating Officer, Pipeline Services Group from June 2015 to August 2017, President, Natural Gas Business Unit of our general partner from October 2013 to June 2015 and as Senior Vice President and Chief Commercial Officer of Legacy Crestwood from August 2012 until October 2013. Prior to joining Legacy Crestwood, Mr. Deneke served in various management positions at El Paso Corporation and its affiliates, including Vice President of Project Development and Engineering for the Pipeline Group, Director of Marketing and Asset Optimization for Tennessee Gas Pipeline Company, LLC and Manager of Business Development and Strategy for Southern Natural Gas Company, LLC. Mr. Deneke holds a bachelor’s degree in Mechanical Engineering from Auburn University.

Robert T. Halpinwas appointed Executive Vice President, Chief Financial Officer in August 2017. He previously served as the Senior Vice President, Chief Financial Officer from March 2015 to August 2017, Vice President, Finance from January 2013 to March 2015 and as Vice President, Business Development from January 2012 to January 2013. Prior to joining Crestwood, from July 2009 to January 2012, he was an Associate at First Reserve and from July 2007 to June 2009, he was an investment banker in the Global Natural Resources Group at Lehman Brothers and subsequently, Barclays Capital following its acquisition of Lehman Brothers’ Investment Banking Division in September 2008. Mr. Halpin holds a B.B.A. in Finance from The University of Texas at Austin.

Steven M. Dougherty was appointed Senior Vice President, Chief Accounting Officer of our general partner in October 2013. He served as Senior Vice President, Interim Chief Financial Officer and Chief Accounting Officer of Legacy Crestwood from January 2013 to October 2013. Mr. Dougherty had served as Vice President and Chief Accounting Officer of Legacy Crestwood since June 2012. Prior to joining Legacy Crestwood, Mr. Dougherty was Director of Corporate Accounting at El Paso Corporation since 2001, with responsibility over El Paso’s corporate segment and in leading El Paso’s efforts in addressing complex accounting matters. Mr. Dougherty also had seven years of experience with KPMG LLP, working with public and private companies in the financial services industry. Mr. Dougherty holds a Master of Public Accountancy from The University of Texas at Austin and is a certified public accountant in the State of Texas.

Joel C. Lambert was appointed Senior Vice President, General Counsel and Chief Compliance Officer in August 2017. He served as Senior Vice President, General Counsel and Corporate Secretary of our general partner from October 2013 to August 2017. He served as a director of Legacy Crestwood from October 2010 to October 2013. From 2007 until October 2013, Mr. Lambert served as Vice President, Legal of First Reserve Corporation, a private equity company which invests exclusively in the energy industry. From 1998 to 2006, Mr. Lambert was an attorney in the Business and International Section of Vinson & Elkins LLP. In 1997, he was an Intern at the Texas Supreme Court, and has served as a Military Intelligence Specialist for the United States Army. Mr. Lambert holds a Bachelor of Environmental Design from Texas A&M University and a Juris Doctorate from The University of Texas School of Law.

William H. Moore was appointed Senior Vice President, Strategy and Corporate Development of our general partner in October 2013. He joined Legacy Inergy in 2005 as a legal analyst and has held various positions in corporate and business development, including Vice President, Corporate Development. Mr. Moore holds an M.B.A from Fort Hays State University, and a Juris Doctorate from the University of Kansas School of Law.

Alvin Bledsoe was appointed a director of our general partner in October 2013. He served as a director of Crestwood Midstream GP LLC (CMLP GP ) from October 2013 to October 2015 and as a director of Legacy Crestwood from July 2007 until October 2013. Mr. Bledsoe currently serves as a director of SunCoke Energy, Inc. and SunCoke Energy Partners GP LLC, the general partner of SunCoke Energy Partners, L.P. Prior to his retirement in 2005, Mr. Bledsoe served as a certified public accountant and various senior roles for 33 years at PricewaterhouseCoopers (PwC). From 1978 to 2005, he was a senior client engagement and audit partner for large, publicly-held energy, utility, pipeline, transportation and manufacturing companies. From 1998 to 2000, Mr. Bledsoe served as Global Leader of PwC’s Energy, Mining and Utilities Industries Assurance and Business Advisory Services Group, and from 1992 to 2005 as a managing partner and regional managing partner. During his career, Mr. Bledsoe also served as a member of PwC’s governing body. Mr. Bledsoe was selected to serve as a director of our general partner due to his extensive background in public accounting and auditing, including experience advising publicly-traded energy companies.

Michael G. France was appointed as a director of our general partner in June 2013. He served as a director of CMLP GP from October 2013 to October 2015 and as a director of Legacy Crestwood from October 2010 to October 2013. Mr. France, a Managing Director of First Reserve, a global private equity and infrastructure firm focused exclusively on energy, has been

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with the firm since 2007. Additionally, Mr. France has served on the Management Committee of Crestwood Holdings since May 2010. From 2003 to 2007, Mr. France served as a Vice President in the Natural Resources Group, Investment Banking Division, at Lehman Brothers. From 1999 to 2001, he served as a Senior Consultant at Deloitte & Touche LLP. Mr. France previously served on the board of directors of Cobalt International Energy, Inc. Mr. France holds a B.B.A. (Cum Laude) in Finance from The University of Texas at Austin and a Master of Business Administration from Jones Graduate School of Management at Rice University. Mr. France was elected to serve as a director of our general partner due to his years of experience in financing energy related companies including his energy investment experience at First Reserve and his general knowledge of upstream and midstream energy companies.

Warren H. Gfellerhas been a member of our general partner’s board of directors since March 2001. He served as a director of CMLP GP from December 2011 to October 2015. He has engaged in private investments since 1991. From 1984 to 1991, Mr. Gfeller served as president and chief executive officer of Ferrellgas, Inc., a retail and wholesale marketer of propane and other natural gas liquids. Mr. Gfeller began his career with Ferrellgas in 1983 as an executive vice president and financial officer. Prior to joining Ferrellgas, Mr. Gfeller was the Chief Financial Officer of Energy Sources, Inc. and a CPA at Arthur Young & Co. He has served as a director of HC2 Holdings, Inc. since June 2016 and previously served as a director of Inergy Holdings GP, LLC, Zapata Corporation and Duckwall-Alco Stores, Inc. Mr. Gfeller worked for many years in the energy industry. This experience has given him a unique perspective on our operations, and, coupled with his extensive financial and accounting training and practice, has made him a valuable member of our board of directors.

David Lumpkins has been a director of our general partner since November 2015. He is Chairman of PetroLogistics II, LLC, a petrochemical development company. He was the co-founder and Executive Chairman of Petrologistics, a NYSE listed company which was acquired by Flint Hills Resources in July 2014. Mr Lumpkins was also previously the co-founder and Chairman of PL Midstream, a pipeline transportation and storage company based in Louisiana, which was sold to Boardwalk Partners in 2012. Prior to the formation of these companies, Mr. Lumpkins worked in the investment banking industry for 17 years, principally for Morgan Stanley and Credit Suisse. In 1995, Mr. Lumpkins opened Morgan Stanley’s Houston office and served as head of the firm’s southwest region. He is a graduate of The University of Texas where he also received his MBA. Mr. Lumpkins also serves as a director of Westlake Chemical Partners LP. Mr. Lumpkins’ extensive experience in the petrochemical, energy midstream and finance industries adds significant value to the boards of directors.

John J. Shermanhas served as a director of our general partner since March 2001 and previously served on the board of directors of CMLP’s general partner. He served as Chief Executive Officer and President of our general partner from March 2001 until June 2013 and of our predecessor from 1997 until July 2001. Prior to joining our predecessor, he was a vice president with Dynegy Inc. from 1996 through 1997. He was responsible for all downstream propane marketing operations, which at the time were the country’s largest. From 1991 through 1996, Mr. Sherman was the president of LPG Services Group, Inc., a company he co-founded and grew to become one of the nation’s largest wholesale marketers of propane before Dynegy acquired LPG Services in 1996. From 1984 through 1991, Mr. Sherman was a vice president and member of the management committee of Ferrellgas. He also served as President, Chief Executive Officer and director of Inergy Holdings GP, LLC. He is currently the Chief Executive Officer of MLP Holdings, LLC, Vice Chairman of the Cleveland Indians Baseball Club and a director of Great Plains Energy Inc. and Tech Accel LLC. We believe the breadth of Mr. Sherman’s experience in the energy industry and his past employment described above, as well as his current board of director positions, has given him valuable knowledge about our business and our industry that makes him an asset to our board of directors.

John W. Somerhalder II was appointed as a director of our general partner in October 2013. He has served as a director of CenterPoint Energy, Inc. since October 2016, a director of SunCoke Energy Partners GP LLC, the general partner of SunCoke Energy Partners, L.P. since August 2017 and as a director of Legacy Crestwood from July 2007 to October 2013. Mr. Somerhalder served as the interim Chief Executive Officer of Colonial Pipeline Company from February 2017 through October 2017 and as the President, Chief Executive Officer and a director of AGL Resources Inc. (AGL Resources), a publicly-traded energy services holding company whose principal business is the distribution of natural gas, from March 2006 to December 2015 and as Chairman of the Board of AGL Resources from November 2007 to December 2015. From 2000 to May 2005, Mr. Somerhalder served as the Executive Vice President of El Paso Corporation, where he continued service under a professional services agreement from May 2005 to March 2006. From 2001 to 2005, he served as the President of El Paso Pipeline Group. From 1996 to 1999, Mr. Somerhalder served as the President of Tennessee Gas Pipeline Company, an El Paso subsidiary company. From April 1996 to December 1996, Mr. Somerhalder served as the President of El Paso Energy Resources Company. From 1992 to 1996, he served as the Senior Vice President, Operations and Engineering, of El Paso Natural Gas Company. From 1990 to 1992, Mr. Somerhalder served as the Vice President, Engineering of El Paso Natural Gas Company. From 1977 to 1990, Mr. Somerhalder held various other positions at El Paso Corporation and its subsidiaries until being named an officer in 1990. Mr. Somerhalder was selected to serve as a director of our general partner due to his years of experience in the oil and gas industry and his extensive business and management expertise, including as President, Chief Executive Officer and a director of a publicly-traded energy company.

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Independent Directors

Because we are a limited partnership, the listing standards of the NYSE do not require that we or our general partner have a majority of independent directors on the board, nor that we establish or maintain a nominating or compensation committee of the board. We are, however, required to have an audit committee consisting of at least three members, all of whom are required to be independent as defined by the NYSE. The board of directors has determined that Alvin Bledsoe, Warren Gfeller, David Lumpkins and John W. Somerhalder II qualify as independent pursuant to independence standards established by the NYSE as set forth in Section 303A.02 of the manual. To be considered an independent director under the NYSE listing standards, the board of directors must affirmatively determine that a director has no material relationship with us other than as a director. In making this determination, the board of directors adheres to all of the specific tests for independence included in the NYSE listing standards and considers all other facts and circumstances it deems necessary or advisable.

Board Committees

Audit Committee

The members of the audit committee are Alvin Bledsoe (Chairman), David Lumpkins and John Somerhalder II. Our board has determined that each of the members of our audit committee meet the independence standards of the NYSE and is financially literate. In addition, the board has determined that Mr. Bledsoe is an audit committee financial expert based upon the experience stated in his biography. The audit committee’s primary responsibilities are to monitor: (a) the integrity of our financial reporting process and internal control system; (b) the independence and performance of the independent registered public accounting firm; and (c) the disclosure controls and procedures established by management. Our audit committee charter may be found on our website at www.crestwoodlp.com.

Compensation Committee

Although we are not required by NYSE listing standards to have a compensation committee, two members of our board of directors also serve as members of our compensation committee, which oversees compensation decisions for the executive officers of our general partner, as well as the compensation plans described below. The current members of the compensation committee are Warren Gfeller (Chairman) and Alvin Bledsoe. Our compensation committee charter may be found on our website atwww.crestwoodlp.com.

Conflicts Committee

Our general partner has established a conflicts committee to review specific matters which the board of directors believes may involve conflicts of interest. The members of our conflicts committee are David Lumpkins and John Somerhalder II (Chairman). The conflicts committee will determine if the resolution of any conflict of interest submitted to it is fair and reasonable to us. In addition to satisfying certain other requirements, the members of the conflicts committee must meet the independence standards for service on an audit committee of a board of directors, which standards are established by the NYSE. Any matters approved by the conflicts committee will be conclusively deemed to be fair and reasonable to us, approved by all of our partners and not a breach by our general partner of any duties it may owe us or our unitholders.

Finance Committee

Our general partner has established a finance committee to assist the board of directors in fulfilling its oversight responsibilities across the principal areas of corporate finance and risk management. The members of the finance committee are David Lumpkins (Chairman) and Warren Gfeller.

Board Leadership Structure

The board has no policy that requires that the positions of the Chairman of the Board (the Chairman) and the Chief Executive Officer be separate or that they be held by the same individual. The board believes that this determination should be based on circumstances existing from time to time, including the composition, skills and experience of the board and its members, specific challenges faced by us or the industry in which it operates, and governance efficiency. Based on these factors, Robert Phillips serves as our Chairman and Chief Executive Officer.

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Risk Oversight

We face a number of risks, including environmental and regulatory risks, and others, such as the impact of competition. Management is responsible for the day-to-day management of risks our company faces, while the board of directors, as a whole and through its committees, has responsibility for the oversight of risk management. In fulfilling its risk oversight role, the board of directors must determine whether risk management processes designed and implemented by our management are adequate and functioning as designed. Senior management regularly delivers presentations to the board of directors on strategic matters, operations, risk management and other matters, and is available to address any questions or concerns raised by the board.

Our board committees assist the board in fulfilling its oversight responsibilities in certain areas of risk. The audit committee assists with risk management oversight in the areas of financial reporting, internal controls and compliance with legal and regulatory requirements and our risk management policy relating to our hedging program. The compensation committee assists the board of directors with risk management relating to our compensation policies and programs.

Meetings of Non-Management Directors

Our non-management directors meet in regularly scheduled sessions. Our non-management directors have appointed Warren Gfeller as the lead director to preside at such meetings. In addition, our independent directors meet in executive session at least once a year.

Communication with the Board of Directors

We have established a procedure by which unitholders or interested parties may communicate directly with the board of directors, any committee of the board, any of the independent directors or any one director serving on the board of directors by sending written correspondence addressed to the desired person, committee or group to the attention of Joel C. Lambert, Senior Vice President, General Counsel, 811 Main Street, Suite 3400, Houston, TX 77002. Communications are distributed to the board of directors, or to any individual director or directors as appropriate, depending on the facts and circumstances outlined in the communication.

Code of Ethics/Governance Guidelines

We have adopted a Code of Business Conduct and Ethics that applies to our principal executive officer, principal financial officer, principal accounting officer or controller or persons performing similar functions, as well as to all of our other employees. Additionally, the board of directors has adopted corporate governance guidelines for the directors and the board. The Code of Business Conduct and Ethics and corporate governance guidelines may be found on our website at www.crestwoodlp.com.

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our company’s directors and executive officers, and persons who own more than 10% of any class of equity securities of our company registered under Section 12 of the Exchange Act, to file with the Securities and Exchange Commission initial reports of ownership and report of changes in ownership in such securities and other equity securities of our company. Securities and Exchange Commission regulations require directors, executive officers and greater than 10% unitholders to furnish our company with copies of all Section 16(a) reports they file. To our knowledge, based solely on review of the reports furnished to us and written representations that no other reports were required, during the fiscal year ended December 31, 2017, all section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% unitholders, were met.

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Item 11. Executive Compensation

Compensation Discussion and Analysis

Introduction

We do not directly employ any of the persons responsible for managing our business. Crestwood Equity GP LLC, our general partner, currently manages our operations and activities, and its board of directors and officers make decisions on our behalf. The compensation of the directors and the executive officers of our general partner is determined by the board of directors of our general partner based on the recommendations of our compensation committee.

All of our executive officers also serve in the same capacities as executive officers of our subsidiaries and the compensation of the Named Executive Officers (NEOs) discussed below reflects total compensation for services to all Crestwood entities described in more detail below.

For purposes of this Compensation Discussion and Analysis our NEOs for fiscal 2017 were comprised of:

• Robert G. Phillips, our current President and Chief Executive Officer and Director (Principal Executive Officer);

• Robert T. Halpin, our Executive Vice President and Chief Financial Officer (Principal Financial Officer);

• J. Heath Deneke, our Executive Vice President and Chief Operating Officer;

• William H. Moore, our Senior Vice President, Strategy and Corporate Development; and

• Steven M. Dougherty, our Senior Vice President and Chief Accounting Officer

Compensation Philosophy and Objectives

We employ a compensation philosophy that emphasizes pay for performance. The primary measure of our long-term performance is our ability to maintain sustainable cash distributions to our unitholders and the related unitholder value realized. We believe that by tying a substantial portion of each NEO’s total compensation to financial, operational and safety performance metrics that support sustainability in distributable cash, our pay-for-performance approach aligns the interests of our executive officers with that of our unitholders. Accordingly, the objectives of our total compensation program consist of:

• aligning executive compensation incentives with the creation of unitholder value;

• balancing short and long-term performance;

• tying short-and long-term compensation to the achievement of performance objectives (company, business unit, department and/or individual); and

• attracting and retaining the best possible executive talent for the benefit of our unitholders.

By accomplishing these objectives, we intend to optimize long-term unitholder value.

Compensation Setting Process

Role of Management

In order to make pay recommendations, management, with assistance from management’s consultant, provides the CEO with data from the annual proxy statements and annual reports of companies in our comparator group along with pay information compiled from nationally recognized executive and industry-related compensation surveys. The survey data is used to confirm that pay practices among companies in the comparator group are aligned with the market as a whole.

Chief Executive Officer’s Role in the Compensation Setting Process

Our CEO plays a significant role in the compensation setting process. The most significant aspects of his role are:

• assisting in establishing business performance goals and objectives;

• evaluating executive officer and company performance;

• recommending compensation levels and awards for executive officers other than himself; and

• implementing the approved compensation plans.

Our CEO makes recommendations to the compensation committee with respect to financial metrics to be used and determination of performance for performance-based awards as well as other recommendations regarding non-CEO executive

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compensation, which may be based on our performance, individual performance and the peer group compensation market analysis. The compensation committee considers this information when establishing the total compensation packages of our executive officers. The CEO’s performance and compensation is reviewed, evaluated and established separately by the compensation committee and the full board based on criteria similar to those used for non-CEO executive compensation. The board of directors of our general partner reviews all aspects of executive compensation based on the reports from the compensation committee.

Role of the Compensation Committee

For all NEOs, except the CEO, the compensation committee reviews the CEO’s recommendations, supporting market data, and individual performance assessments. In addition, the compensation committee reviews the reasonableness of the CEO’s pay recommendations based on a competitive market study that includes proxy and annual report data from the approved comparator group and published compensation survey data. For the CEO, in fiscal 2017 the board of directors met in executive session without management present to review the CEO’s performance. In this session, the board of directors reviewed:

• Evaluations of the CEO completed by the board members;

• The CEO’s written assessment of his/her own performance compared with the stated goals; and

• Business performance of the Company relative to established targets.

The compensation committee used these evaluations and the competitive market study to determine the CEO’s long- term incentive amounts, annual cash incentive target, base pay, and any performance adjustments to be made to the CEO’s annual cash incentive payment.

Role of the Compensation Consultant

In June 2017, we engaged Willis Towers Watson to serve as our compensation consultant. Prior to June 2017, Aon Hewitt served as our compensation consultant. Our compensation committee and management believe it is beneficial to have an independent third-party analysis to assist in evaluating and setting executive compensation. Management, in consultation with the compensation committee, chose Willis Towers Watson and Aon Hewitt based on their extensive experience in providing executive compensation advice, including specific experience in the oil and gas industry. For fiscal 2017, Aon Hewitt provided management and the compensation committee with an analysis of our executive compensation programs, including total direct compensation comprised of base salary, annual incentive and long-term incentive compensation, in order to assess the competitiveness of our programs and to provide conclusions and recommendation. Our compensation committee has taken and will take into consideration the discussions, guidance and compensation studies produced by our compensation consultants in order to make compensation decisions. The compensation committee has assessed the independence of the compensation consultants and has concluded that the compensation consultants’ work for the compensation committee does not raise any conflict of interest.

Competitive Benchmarking and Peer Group

Our compensation committee considers competitive industry data in making executive pay determinations. Pursuant to our compensation committee’s decisions to maintain a peer group for executive compensation purposes and in view of evolving industry and competitive conditions, Aon Hewitt, with the assistance of management, proposed certain peer group companies for our compensation committee’s review.

After discussion with Aon Hewitt and reviewing its recommendation of a peer group based on companies with annual revenues, assets and net income similar to ours and taking into account geographic footprint and employee count, our compensation committee determined that the peer group listed below was the most appropriate for purposes of the 2017 executive compensation analyses.

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Boardwalk Pipeline Partners LP	Midcoast Energy Partners, L.P.
Buckeye Partners, L.P.	NuStar Energy L.P.
DCP Midstream Partners, LP	ONEOK Inc.
Enable Midstream Partners, LP	Summit Midstream Partners, LP
EnLink Midstream Partners, LP	Tallgrass Energy Partners, LP
EQT Midstream Partners, LP	Targa Resources Corp.
Genesis Energy LP	Andeavor Logistics LP
Magellan Midstream Partners, L.P.	Western Gas Partners, LP

Aon Hewitt compiled compensation data for the peer group from a variety of sources, including proxy statements and other publicly filed documents, and compiled published survey compensation data from multiple sources. This compensation data was then presented to the compensation committee and used to compare the compensation of our NEOs to our peer group where the peer group had individuals serving in similar positions and to the market.

Elements of Compensation

The principal elements of compensation for the NEOs are the following:

• base salary;

• incentive awards;

• long-term incentive plan awards; and

• retirement and health benefits.

In addition, certain NEOs have received incentive units from Crestwood Holdings, a subsidiary of First Reserve, which plays a key role in enabling our general partner to attract, recruit, hire and retain qualified executive officers.

Base Salary

Base salary is designed to compensate executives commensurate with the level of the position they hold and for sustained individual performance (including experience, scope of responsibility, results achieved and potential). The initial base salaries for our NEOs were determined in 2013 and documented in employment agreements we entered into with each of our executive officers in January 2014 (the Executive Employment Agreements). For a more detailed description of the Executive Employment Agreements, see “Narrative Disclosure to Summary Compensation and Grants of Plan Based Awards Tables-Employment Agreements.”

Base salaries for our NEOs are reviewed on an annual basis and at the time of promotion or other change in responsibilities. In determining the amount of any adjustments, the compensation committee uses market data as a tool for assessing the reasonableness of the base salary amounts of the NEOs as compared to the compensation of executives in similar positions with similar responsibility levels in our industry. However, the final determination of base salary amounts was within the compensation committee’s discretion. Based on our objective to maintain target average base compensation at the 50^th percentile of the market data, the compensation committee approved a standard 3% merit increase for our NEOs effective January 1, 2017. Accordingly, the annual base salaries were increased as follows: Mr. Phillips ($674,650), Mr. Halpin ($412,000), Mr. Deneke ($489,250), Mr. Moore ($360,500) and Mr. Dougherty ($386,250).

With respect to Mr. Deneke, in July 2017 his annual base salary was increased to $525,000 in connection with his promotion to Executive Vice President, Chief Operating Officer.

Annual Incentive Awards

Incentive bonuses are granted based on a percentage of each NEO’s base salary. Incentive awards are designed to reward the performance of key employees, including the NEO’s, by providing annual incentive opportunities for the partnership’s achievement of its annual financial, operational, and individual performance goals. In particular, these bonus awards are provided to the NEOs in order to provide competitive incentives to these individuals who can significantly impact performance and promote achievement of our short-term business objectives.

Annual incentive target payouts were initially established for each of our NEOs pursuant to their Employment Agreements. For a more detailed description of the Executive Employment Agreements, see “Narrative Disclosure to Summary Compensation

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and Grants of Plan Based Awards Tables-Executive Employment Agreements.” The annual target bonus amounts of our NEOs are reviewed on an annual basis and at the time of promotion or other change in responsibilities. In determining the amount of any adjustments, the compensation committee uses market data as a tool for assessing the reasonableness of the annual incentive targets of the NEOs as compared to executives in similar positions with similar responsibility levels in our industry. However, the final determination of annual target bonus amounts is within the compensation committee’s discretion.

Actual bonuses for 2017 were determined based on our achievement of compensation committee approved key performance indicators (KPIs) and a board discretionary component. The KPIs for fiscal 2017 were Adjusted EBITDA, operational and administrative costs, total shareholder return relative to peers and safety. Each KPI is then weighted based on the relative impact to our overall compensation philosophy and objectives. Actual results between the minimum and maximum target thresholds are pro-rated based on the percentage of target reached. Actual results above the maximum threshold are capped at 140% and results below 40% achievement result in 0% achievement for that KPI, excluding total shareholder return relative to peers. The board discretionary component allows our board of directors the ability to increase the total recommended bonus pool as much as 25%, or decrease the bonus pool by as much as 20% based on qualitative factors deemed relevant by the board.

2017 Annual Incentive Awards KPIs	Weighting		Target
Adjusted EBITDA	60	%	$	380.0
Operational and Administrative Costs	20	%	$	248.0
Relative Total Shareholder Return*	5	%	100		%
Total Recordable Incident Rate	5	%	2.0
At-Fault Vehicle Incident Rate	5	%	1.4
Lost Time Injury Rate	5	%	1.2
	100	%	—

^*  Peers include Boardwalk Pipeline Partners LP, Buckeye Partners LP, DCP Midstream, LP, Enable Midstream Partners, LP, EnLink Midstream Partners LP, EQP Midstream Partners LP, Genesis Energy LP, Magellan Midstream Partners, L.P., Midcoast Energy Partners, L.P., NuStar Energy L.P., ONEOK Inc., Summit Midstream Partners LP, Tallgrass Energy Partners, Targa Resources Corp., Andeavor Logistics LP and Western Gas Partners LP.

Based on the company’s KPI achievement, the actual annual incentive bonus pool for fiscal 2017 was established at 110% of target amount. The actual bonus amount paid to the individual NEO is then adjusted based on the individual performance review for such NEO. For 2017, each NEO received the highest performance rating of “1” which increased the actual percentage for such individuals to 135% of target, which is equivalent to the company-wide target payout for “1” performance ratings.

Because of changes made to Mr. Deneke’s compensation in July 2017, the target bonus amount for each of our other NEOs (other than Mr. Deneke) was then further adjusted to avoid Mr. Deneke receiving a disparate award as compared to the other NEOs. The adjustments made assumed that each of our NEOs (other than Mr. Deneke) received their respective new 2018 target bonus amount as of July 2017 and that 2018 base compensation changes were made as of July 2017 (6 months using 2017 target bonus and 6 months using 2018 target bonus). These adjustments resulted in actual 2017 bonus payouts as follows:

Name	2018 Base Salary ($)	Pro-Rated Target Bonus ($)	Percentage of Target Bonus	Total ($)
Robert G. Phillips	750,000	712,500	135%	961,875
Robert T. Halpin	450,000	410,400	135%	554,040
J. Heath Deneke	525,000	548,175	135%	740,036
William H. Moore	385,000	373,000	135%	503,550
Steven M. Dougherty	410,000	318,400	135%	429,840

In addition to annual incentive awards, from time to time the compensation committee may award one-time project completion bonuses. The amount of these awards are recommended by management to the compensation committee based on the size of the project, the strategic importance of the project to the company and the respective individual’s efforts in sourcing and completing the project.

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In the fourth quarter of 2017, the company completed the sale of US Salt LLC to Kissner Group Holdings LP for net proceeds of approximately $223.6 million. The divestiture was critical to provide funds to the company to reinvest in on-going organic growth projects in the Bakken and Delaware Basin. Due to his significant efforts in this project, the compensation committee awarded Mr. Moore a $200,000 completion bonus.

Mr. Deneke receives an additional $10,000 bonus per annum as additional compensation pursuant to the terms of his new employment agreement with us.

Long-Term Incentive Plan Awards

Long-term incentive awards for the NEOs are granted under the Crestwood Equity Partners LP Long Term Incentive Plan in order to promote achievement of our primary long-term strategic business objective of increasing distributable cash flow and increasing unitholder value. This plan was designed to align the economic interests of key employees and directors with those of our common unitholders and to provide an incentive to management for continuous employment with the general partner and its affiliates. Long-term incentive compensation is based upon the common units representing limited partnership interests in us. For fiscal 2017, awards consisted of grants of restricted common units which vest based upon continued service and performance units which vest based on performance conditions. Long-term incentive plan awards are designed to attract and retain executive talent and to align their economic interests with those of common unitholders.

The initial long-term equity incentive targets for our NEOs were established in their Employment Agreements. For a more detailed description of the Executive Employment Agreements, see “Narrative Disclosure to Summary Compensation and Grants of Plan Based Awards Tables-Employment Agreements.” The annual target long-term equity incentives for our NEOs are reviewed on an annual basis and at the time of promotion or other changes in responsibilities. In determining the amount of any adjustments, the compensation committee uses market data as a tool for assessing the reasonableness of long-term incentive targets of the NEOs as compared to executives in similar positions with similar responsibility levels in our industry. However, the final determination of long-term equity awards is within the compensation committee’s discretion. Based on our objective of setting long-term incentive awards at the median of the market data, no changes were made to the annual target long-term incentive awards in 2017. Accordingly, the following restricted units awards were made to our NEOs in 2017:

Name	Target Equity Percentage	2017 Restricted Units Awarded (#)	Value at Grant Date ($)
Robert G. Phillips	300%	76,908	1,991,917
Robert T. Halpin	250%	48,532	1,256,979
J. Heath Deneke	250%	135,567	3,421,185
William H. Moore	180%	29,355	760,294
Steven M. Dougherty	175%	30,382	786,894

Mr. Deneke’s restricted unit awards includes 75,000 restricted units awarded in July 2017 in connection with his new employment agreement, which vests on June 30, 2020. All other restricted unit awards vest ratably over a three-year period.

In addition to the annual restricted unit grants, our NEOs are also eligible to receive performance phantom unit awards. Performance phantom units vest over a three-year performance period and are paid out based on a performance multiplier ranging between 50% and 200%, determined based on the actual performance in the third year of the performance period compared to pre-established performance goals. For all performance units granted in 2017, the performance goals were based on achieving a specified level of distributable cash flow per unit, Adjusted EBITDA, return on capital invested, and three-year relative total shareholder return, based on the Partnership's percentile ranking as compared with companies that are contained in the Alerian MLP Index at the time the goals were set. The compensation committee selected these metrics because we believe these are the key value indicators for our unitholders and will most closely align the interests of our NEOs with those of our unitholders. The compensation committee then weighted the four performance measures as follows:

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Performance Unit Metric	Weighting
Adjusted EBITDA	30%
Distributable Cash Flow per Unit	30%
Return on Capital Invested	20%
Total Unitholder Return	20%

For all performance unit grants, the last year of the respective performance period is used to measure whether the performance goal is achieved. There is generally no payout for performance below the threshold performance goal level. The payout multiplier for performance equal or greater than threshold is determined on a linear scale between performance levels.

In making the 2017 performance unit grants to our NEOs, the compensation committee considered:

• peer benchmarking data specific to each named executive officer; and

• each NEO’s contribution to our long-term growth.

Based on this analysis, the compensation committee approved the following grants of performance units our named executive officers on February 15, 2017:

	Performance Units
Name	Threshold (#)	Target (#)	Maximum (#)	Value at Grant Date ($)
Robert G. Phillips	44,250	89,041	178,082	2,710,939
Robert T. Halpin	13,698	27,397	54,794	834,122
J. Heath Deneke	16,634	33,268	66,536	1,012,884
William H. Moore	10,274	20,548	41,096	625,611
Steven M. Dougherty	10,274	20,548	41,096	625,611

Risk Assessment Related to our Compensation Structure

We believe that the compensation plans and programs for our executive officers, as well as other employees, are appropriately structured and are not reasonably likely to result in a material risk. We believe these compensation plans and programs are structured in a manner that does not promote excessive risk-taking that could reward poor judgment. We also believe that we have allocated compensation among base salary and short and long-term compensation in such a way as to not encourage excessive risk-taking. In particular, we generally do not adjust base annual salaries for our executive officers and other employees significantly from year to year, and therefore the annual base salary of our employees is not generally impacted by our overall financial performance or the financial performance of an operating segment.

Severance and Change of Control Benefits

Our NEOs are entitled to certain severance and change in control benefits as provided their respective Executive Employment Agreements. For a detailed description of the Executive Employment Agreements for our NEOs, see “Potential Payments upon a Change in Control or Termination during Fiscal 2017.”

Other Compensation Related Matters

Retirement and Health Benefits

We offer a variety of health and welfare and retirement programs to all eligible employees. The NEOs are eligible for these programs on the same basis as other employees. We maintain a 401(k) retirement plan that provides eligible employees with an opportunity to save for retirement on a tax advantaged basis. We match 6% of the deferral to the retirement plan (not to exceed the maximum amount permitted by law) made by eligible participants. Our executive officers are also eligible to participate in additional employee benefits available to our other employees.

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Perquisites and Other Compensation

We do not provide perquisites or other personal benefits to any of the NEOs.

Tax Deductibility of Compensation

With respect to the deduction limitations under Section 162(m) of the Code, we are a limited partnership and do not meet the definition of a “corporation” under Section 162(m). Thus the compensation that we pay to our employees is not subject to the deduction limitations under Section 162(m) of the Code.

Compensation Committee Report

We have reviewed and discussed the foregoing Compensation Discussion and Analysis with management. Based on our review and discussion with management, we have recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2017.

Members of the Compensation Committee

Warren Gfeller

Alvin Bledsoe

Summary Compensation Table for Fiscal 2017

The following table sets forth the cash and non-cash compensation earned by our NEOs for the fiscal years ended December 31, 2017, 2016 and 2015.

Name and Principal Position	Fiscal Year	Salary ($)	Bonus ($)	Unit Awards ($)(1)	Non-Equity Incentive Plan Compensation ($)	All Other Compensation ($)(2)	Total ($)
Robert G. Phillips President, Chief Executive Officer and Director	2017	674,650	1,000	4,702,856	961,875	44,439	6,384,820
	2016	655,000	—	1,589,964	655,000	17,088	2,917,052
	2,015	655,000	—	2,935,211	655,000	10,093	4,255,304
Robert T. Halpin Executive Vice President, Chief Financial Officer	2017	412,000	1,000	2,091,101	554,040	16,344	3,074,485
	2016	400,000	115,000	860,017	360,000	15,744	1,750,761
	2015	400,000	—	1,057,804	360,000	16,044	1,833,848
J. Heath Deneke Executive VicePresident and Chief Operating Officer	2017	504,375	11,000	4,434,069	740,036	16,387	5,705,867
	2016	475,000	100,000	1,062,601	427,500	15,780	2,080,881
	2015	475,000	—	1,477,254	427,500	16,080	2,395,834
William H. Moore Senior Vice President, Strategy and Corporate Development	2017	360,500	201,000	1,385,905	503,550	16,254	2,467,209
	2016	350,000	100,000	713,284	350,000	15,654	1,528,938
	2015	350,000	—	482,164	350,000	15,954	1,198,118
Steven M. Dougherty Senior Vice President, Chief Accounting Officer	2017	386,250	1,000	1,412,505	429,840	16,470	2,246,065
	2016	375,000	—	530,990	300,000	15,780	1,221,770
	2015	375,000	—	1,156,195	330,000	16,080	1,877,275

(1) The material terms of our outstanding LTIP awards to our executive officers are described in “Compensation Discussion and Analysis - Long-Term Incentive Plan Awards.” Unit award amounts reflect the aggregate grant date fair value of unit awards granted during the periods presented calculated in accordance with Accounting Standards Codification Topic 718, Compensation - Stock Compensation (ASC 718), disregarding forfeitures and assuming target performance for phantom performance units. The unit awards vest 20% based on market conditions and 80% based on performance conditions. Assuming maximum performance with respect to the performance based vesting conditions, the aggregate grant date fair value of the unit awards granted during 2017 would be $3,962,252 for Mr. Phillips, $1,214,235 for Mr. Halpin, $1,474,438 for Mr. Deneke, $910,687 for Messrs. Moore and Dougherty,

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respectively. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13 for a discussion of the assumptions used to determine the FASB ASC 718 value of the awards.

(2) “All Other Compensation” for Fiscal Year 2017 consisted of the following:

Name	401(k) Matching Contributions ($)	Group Term Life Insurance ($)	Other ($)*	Total ($)
Robert G. Phillips	16,200	1,188	27,051	44,439
Robert T. Halpin	16,200	144	—	16,344
J. Heath Deneke	16,200	187	—	16,387
William H. Moore	16,200	54	—	16,254
Steven M. Dougherty	16,200	270	—	16,470

* Reflects the incremental cost to Crestwood for personal use of corporate aircraft.

Grants of Plan-Based Awards Table for Fiscal 2017

The following table provides information concerning each grant of an award made to our NEOs during fiscal 2017.

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1)			Estimated Future Payout Under Equity Incentive Plan Awards(2)
Name	Grant Date	Threshold ($)	Target  ($)	Maximum ($)	Threshold (#)	Target (#)	Maximum (#)	All Other Unit Awards (#)(3)	Grant Date Fair Value of Unit and Option Awards ($)(4)
Robert G. Phillips	01/05/17							76,908	1,991,917
	02/15/17				44,250	89,401	178,082		2,710,939
		286,200	712,500	998,700
Robert T. Halpin	01/05/17							48,532	1,256,979
	02/15/17				13,698	27,397	54,794	—	834,123
		164,160	410,400	574,560
J. Heath Deneke	01/05/17							60,567	1,568,685
	02/15/17				16,634	33,268	66,536		1,012,884
	07/24/17							75,000	1,852,500
		219,270	548,175	767,445
William H. Moore	01/05/17							29,355	760,295
	02/15/17				10,274	20,548	41,096		625,611
		149,200	373,000	522,200
Steven M. Dougherty	01/05/17							30,382	786,894
	02/15/17				10,274	20,548	41,096		625,611
		127,360	318,400	445,760

(1) Actual amounts paid pursuant to the annual incentive bonus are reported in the “Non-Equity Incentive Plan Compensation” column of the Summary Compensation Table. The amount of the annual bonus may be increased at the discretion of the compensation committee, irrespective of actual KPI performance, as described above in the “Compensation Discussion and Analysis - Incentive Awards.”

(2) Represents grants of performance phantom units granted under the Long Term Incentive Plan. The vesting of the performance units are subject to the attainment of pre-established performance goals based on adjusted distributable cash flow per unit, Adjusted EBITDA, adjusted return on capital employed and total shareholder return relative to the Alerian MLP Index during the third year of a three fiscal year period. The grant date fair value of the performance unit awards reflected in the table is based on a target payout of such awards.

(3) Represents grants of restricted units granted under the Long Term Incentive Plan. The restricted units vest ratably (33.33%) over a three year period beginning on the first anniversary of the grant date. Mr. Deneke’s July 24, 2017 restricted unit award vests in full on June 30, 2020.

(4) Unit award amounts reflect the aggregate grant date fair value of unit awards granted during 2017 calculated in accordance with ASC 718, disregarding forfeitures. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13 for a discussion of the assumptions used to determine the value of the awards.

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Narrative Disclosure to Summary Compensation Table and Grants of Plan-Based Awards Table

Employment Agreements

During January 2014, Crestwood Operations, LLC (Crestwood Operations) entered into new employment agreements (the Executive Employment Agreements) with each of our named executive officers. The Executive Employment Agreements each have an initial term ending December 31, 2015 and will renew automatically for additional one-year periods thereafter if neither party gives advance notice of non-renewal. The Executive Employment Agreements provide for the base salary, target bonus amounts and a target equity compensation grant described in our “Compensation Discussion and Analysis.”

Under the terms of the Executive Employment Agreements, if the named executive officer’s employment is terminated during the initial term or a subsequent one-year renewal by Crestwood Operations without “employer cause” or the executive resigns due to “employee cause” or the named executive officer’s employment with Crestwood Operations terminates as a result of Crestwood Operations’ election not to renew the Executive Employment Agreement or due to the executive’s death or permanent disability, the executive will be entitled to receive, subject to the executive’s execution of a release of claims, severance equal to two (or, in the case of Mr. Phillips, three) times the sum of the executive’s base salary and average annual bonus for the prior two years, payable in equal installments over an 18-month period following termination. In addition, the named executive officer would be entitled to certain subsidized medical benefits over such 18-month period. If the named executive officer fails to comply with covenants in the Executive Employment Agreement, the release of claims or similar agreement, he forfeits the right to receive any severance payment installments following such failure to comply.

On July 21, 2017, Crestwood Operations entered into the Second Amended and Restated Employment Agreement with Heath Deneke (the Deneke Employment Agreement). In consideration of Mr. Deneke entering into the Deneke Employment Agreement and as compensation for his ongoing service, the Partnership issued 75,000 restricted units to Mr. Deneke which shall become vested on June 30, 2020. In addition, if, on or before July 1, 2019, there is a Change in Control (as defined in the Deneke Employment Agreement), the Partnership will issue 125,000 restricted units to Mr. Deneke, which units will be fully vested on their issuance date.

Under the terms of the Deneke Employment Agreement, if Mr. Deneke’s employment is terminated the Company without “employer cause” or Mr. Deneke resigns due to “employee cause” or Mr. Deneke’s employment terminates as a result of death or permanent disability, Mr. Deneke will be entitled to receive severance equal to two times the sum of his base salary and average annual bonus for the prior two years, payable in equal installments over an 12-month period following termination. However, if Mr. Deneke’s employment is terminated during the period beginning three months prior to a Change in Control and ending twelve months after a Change in Control, then the severance amount payable shall be increased to three (3) times his base salary and average annual bonus for the prior two years. If Mr. Deneke fails to comply with covenants in the Deneke Employment Agreement, the release of claims or similar agreement, he forfeits the right to receive any severance payment installments following such failure to comply.

On February 22, 2018, Crestwood Operations entered into an Omnibus Amendment to each Executive Employment Agreement (“Omnibus Amendment”), other than Mr. Deneke’s Executive Employment Agreement, which has been replaced by the Deneke Employment Agreement. Pursuant to the Omnibus Amendment, if, on or before July 1, 2019, there is a Change in Control (as defined in the Omnibus Amendment), the Partnership will issue 150,000 restricted units to Mr. Phillips, 100,000 restricted units to Mr. Halpin, and 75,000 restricted units to Messrs. Moore and Dougherty, respectively, which units will be fully vested on their issuance date. Furthermore, if the employment Messrs. Halpin, Moore or Dougherty is terminated during the period beginning three months prior to a Change in Control and ending twelve months after a Change in Control, then the severance amount payable shall be increased to three (3) times base salary and average annual bonus for the prior two years.

The foregoing summary of the material provisions of the Executive Employment Agreements, the Deneke Employment Agreement and the Omnibus Agreement is intended to be general in nature and is qualified by the full text of the Executive Employment Agreements, , the Deneke Employment Agreement and the Omnibus Agreement, each of which is incorporated by reference herein as an exhibit to this report.

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Outstanding Equity Awards at 2017 Fiscal Year-End

The following table summarizes the outstanding equity awards as of the end of Fiscal 2017 for the each of our NEOs. The table includes restricted units, phantom units and phantom performance units granted under the Crestwood Equity Partners LP Long Term Incentive Plan.

	UNIT AWARDS
Name	Number of Units That Have Not Vested (#)(1)	Market Value of Units That Have Not Vested ($)(2)
Robert G. Phillips	283,171	7,305,812
Robert T. Halpin	132,149	3,409,444
J. Heath Deneke	239,641	6,182,738
William H. Moore	82,675	2,133,015
Steven M. Dougherty	94,860	2,447,388

(1) Mr. Phillips' restricted units vest as follows: 25,636 on January 5, 2018, 37,883 on January 15, 2018, 3,898 on January 16, 2018, 4,720 on January 16, 2018, 25,636 on January 5, 2019, 37,884 on January 15, 2019 and 25,636 on January 5, 2020. Mr. Phillips' phantom units vest as follows: 14,745 on January 16, 2018 and 18,092 on January 16, 2018. Mr. Phillips' 89,041 phantom performance units vest on February 15, 2020. Mr. Halpin's restricted units vest as follows: 16,177 on January 5, 2018, 19,279 on January 15, 2018, 1,250 on January 16, 2018, 1,513 on January 16, 2018, 738 on June 6, 2018, 16,177 on January 5, 2019, 19,279 on January 15, 2019, 738 on June 6, 2019 and 16,178 on January 5, 2020. Mr. Halpin's phantom units vest as follows: 6,027 on January 16, 2018 and 7,396 on January 16, 2018. Mr. Halpin's 27,397 phantom performance units vest on February 15, 2020. Mr. Deneke's restricted units vest as follows: 20,189 on January 5, 2018, 22,894 on January 15, 2018, 1,812 on January 16, 2018, 2,194 on January 16, 2018, 1,475 on June 6, 2018, 20,189 on January 5, 2019, 22,894 on January 15, 2019, 1,476 on June 6, 2019, 20,189 on January 5, 2020 and 75,000 on June 30, 2020. Mr. Deneke's phantom units vest as follows: 8,110 on January 16, 2018 and 9,951 on January 16, 2018. Mr. Deneke's 33,268 phantom performance units vest on February 15, 2020. Mr. Moore's restricted units vest as follows: 9,785 on January 5, 2018, 12,146 on January 15, 2018, 1,166 on January 16, 2018, 1,412 on January 16, 2018, 2,951 on June 6, 2018, 9,785 on January 5, 2019, 12,146 on January 15, 2019, 2,951 on June 6, 2019 and 9,785 on January 5, 2020. Mr. Moore's 20,548 phantom performance units vest on February 15, 2020. Mr. Dougherty's restricted units vest as follows: 10,127 on January 5, 2018, 12,652 on January 15, 2018, 1,250 on January 16, 2018, 1,513 on January 16, 2018, 10,127 on January 5, 2019, 12,652 on January 15, 2019 and 10,128 on January 5, 2020. Mr. Dougherty's phantom units vest as follows: 7,123 on January 16, 2018 and 8,740 on January 16, 2018. Mr. Dougherty's 20,548 phantom performance units vest on February 15, 2020.

(2) Market value for CEQP units based on the NYSE closing price of $25.80 on December 29, 2017.

.

Units Vested During Fiscal 2017

The following table provides information regarding restricted unit vesting during Fiscal 2017 for each of the NEOs. Value realized on upon vesting was calculated by using the NYSE closing price of Crestwood Equity Partners LP on the day immediately prior to the date that the award vested.

	UNIT AWARDS
Name	Number of Units Acquired On Vesting (#)	Value Realized on Vesting ($)
Robert G. Phillips	58,259	1,531,771
Robert T. Halpin	24,256	634,482
J. Heath Deneke	29,182	763,209
William H. Moore	19,236	497,349
Steven M. Dougherty	16,991	445,549

Pension Benefits during Fiscal 2017

We do not offer any pension benefits.

Non-qualified Deferred Compensation during Fiscal 2017

On November 10, 2016, our compensation committee adopted the Crestwood Nonqualified Deferred Compensation Plan (the “NQDC”). The NQDC is a nonqualified deferred compensation plan under which designated eligible participants may elect to defer compensation. Eligible participants include the executive officers, certain other senior officers and members of the Board.

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Subject to applicable tax laws, participants may elect to defer up to 50% of their base salary and up to 100% of incentive compensation earned and equity grants. In addition to elective deferrals, the NQDC permits us to make matching contributions and discretionary contributions. Participants may elect to receive payment of their vested account balances in a single cash payment or in annual installments for a period of up to five (5) years. Payments will be made on March 15 of any year at least one year after the deferral date, or upon separation from service. If a participant’s employment terminates before the designated year, payment is accelerated and paid in a lump sum. Compensation deferred under the Plan represents an unsecured obligation of the Company.

Currently, none of our NEOs participate in the NQDC. Mr. Bledsoe deferred his unit awards pursuant to the Non-Qualified Deferred Compensation Plan and Mr. Somerhalder deferred his unit awards and fees pursuant to the Non-Qualified Deferred Compensation Plan.

Potential Payments upon a Change in Control or Termination during Fiscal 2017

Under the terms of the Executive Employment Agreements, if the named executive officer’s employment is terminated during the initial term or a subsequent one-year renewal by Crestwood Operations without “employer cause” or the executive resigns due to “employee cause” or the named executive officer’s employment with Crestwood Operations terminates as a result of death, permanent disability, or Crestwood Operations’ election not to renew the Executive Employment Agreement, the executive will be entitled to receive, subject to the executive’s execution of a release of claims, severance equal to two (or, in the case of Mr. Phillips, three) times the sum of the executive’s base salary and average annual bonus for the prior two years, payable in equal installments over an 18-month period following termination. In addition, the named executive officer would be entitled to certain subsidized medical benefits over such 18-month period and all restricted and phantom units held by the named executive officer would vest in full.

On July 21, 2017, Mr. Deneke’s Executive Employment Agreement was amended so that if Mr. Deneke’s employment is terminated during the period beginning three months prior to a Change in Control and ending twelve months after a Change in Control, then the severance amount payable shall be increased to three (3) times his base salary and average annual bonus for the prior two years. On February 22, 2018, the Executive Employment Agreements for Messrs. Halpin, Moore and Dougherty were amended to add the same provision.

The following table presents information about the gross payments potentially payable to our named executive officers pursuant to the Executive Employment Agreements, assuming each such named executive officer experienced a qualifying termination of employment on December 31, 2017.

Name	Cash Severance ($)(1)	Accelerated Vesting of Restricted Units ($)(2)	Benefit Continuation ($)(3)	Total ($)
Robert G. Phillips	4,215,000	7,305,812	9,209	11,530,021
Robert T. Halpin	1,660,000	3,409,444	25,171	5,094,615
J. Heath Deneke	1,905,000	6,182,738	25,177	8,112,915
William H. Moore	1,470,000	2,133,015	25,177	3,628,192
Steven M. Dougherty	1,450,000	2,447,388	25,177	3,922,565

(1) As described above, amounts reflect cash severance payments payable upon a qualifying termination without “employer cause” or the named executive officer resigns due to “employee cause” the named executive officer will be entitled to receive pursuant to his Employment Agreements, subject to the executive’s execution of a release of claims. The severance payments are equal to two (or, in the case of Mr. Phillips, three) times the sum of the named executive officer’s base salary and average annual bonus for the prior two years. Mr. Deneke’s cash severance would increase to $2,857,500 in the event his qualifying termination was in connection with a Change in Control. The cash severance payable to each of Messrs. Halpin, Moore and Dougherty would increase to $2,490,000, $2,205,000 and $2,175,000, respectively, in the event his qualifying termination was in connection with a Change in Control.

(2) The amounts reflected in the table above include the value of restricted units and phantom units which would be subject to accelerated vesting upon a change of control or termination without “employer cause” or the named executive officer resigns due to “employee cause.” The value reflected for the restricted units is based on the NYSE closing price of $25.80 for CEQP units on December 29, 2017.

(3) As described above, amounts reflect the value of 18 months’ subsidized medical benefit coverage provided upon a qualifying termination without “employer cause” or the named executive officer resigns due to “employee cause” the named executive officer will be entitled to receive pursuant to his Employment Agreement, subject to the executive’s execution of a release of claims.

Additionally, upon a Change in Control (as defined in the Deneke Employment Agreement) regardless of whether there is termination, the Company shall issue 125,000 restricted units to Mr. Deneke, which amount shall be fully vested on the date of issuance. The value of such restricted units, based on the NYSE closing price of $25.80 for CEQP units on December 29, 2017, is $3,225,000.

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On February 22, 2018, the Executive Employment Agreements for Messrs. Phillips, Halpin, Moore and Dougherty were amended to add a similar provision. Accordingly, if, on or before July 1, 2019, there is a Change in Control (as defined in the Omnibus Amendment), the Partnership shall issue 150,000 units to Mr. Phillips, 100,000 units to Mr. Halpin, 75,000 units to Mr. Dougherty and 75,000 unit Mr. Moore. These units shall be fully vested on their issuance date.

Director Compensation Table for Fiscal 2017

The following table sets forth the cash and non-cash compensation for Fiscal 2017 by each person who served as a non-employee director of our general partner during such time.

Name	Fees Earned or Paid in Cash ($)	Unit Awards ($)(1)	Non-Qualified Deferred Comp Earnings ($)	Total ($)
Alvin Bledsoe	100,000	78,588	106	178,694
Michael France	—	78,588	—	78,588
Warren Gfeller	109,167	78,588	—	187,755
David Lumpkins(1)	100,000	78,588	—	178,588
John Sherman	80,000	78,588	—	158,588
John Somerhalder II	100,000(2)	78,588	1,302	79,890

(1) Reflects the value of restricted unit awards, calculated in accordance with ASC 718, disregarding estimated forfeitures. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13 for a discussion of the assumptions used to determine the FASB ASC Topic 718 value of the awards. These restricted unit grants will vest on the first anniversary of grant. As of December 31, 2017, our non-employee directors held the following restricted unit awards: Mr. France, Mr. Gfeller, Mr. Lumpkins and Mr. Sherman each held 3,131 restricted units. Mr. Bledsoe and Mr. Somerhalder deferred their unit awards pursuant to the Non-Qualified Deferred Compensation Plan.

(2) Mr. Somerhalder deferred his fees pursuant to the Non-Qualified Deferred Compensation Plan.

Compensation of Directors during Fiscal 2017

Officers of our general partner who also serve as directors do not receive additional compensation. Each director receives cash compensation of $80,000 per year for serving on our board of directors. The lead director, audit committee chairperson, conflicts committee chairperson and finance committee chairperson each receive additional cash compensation of $20,000 per year and the compensation committee chairperson receives additional cash compensation of $10,000 per year. All cash compensation is paid to the non-employee directors in quarterly installments. Additionally, each non-employee director receives an annual grant of restricted units under our long-term incentive plan equal to approximately $80,000 in value that vests on the first anniversary of the date of issuance.

On December 21, 2017, our board of directors, based on the recommendation of the compensation committee, approved an increase to our director compensation program. Beginning January 1, 2018, each director will receive cash compensation of $100,000 per year for serving on our board of directors. The lead director, audit committee chairperson, conflicts committee chairperson and finance committee chairperson will continue to receive additional cash compensation of $20,000 per year and the compensation committee chairperson will continue to receive additional cash compensation of $10,000 per year. Additionally, each non-employee director will receive an annual grant of restricted units under our long-term incentive plan equal to approximately $100,000 in value that vests on the first anniversary of the date of issuance.

Each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees.

CEO Pay Ratio

As required by Section 953(b) of the Dodd-Frank Wall Street Reform and Consumer Protection Act, and Item 402(u) of Regulation S-K, we are providing the following information about the relationship of the annual total compensation of our employees and the annual total compensation of our CEO. 

We identified the median employee by examining the 2017 total taxable cash and equity compensation (again, to the extent taxed to the employee in 2017), as reflected in our payroll records as reported to the Internal Revenue Service on Form W-2, for all individuals, including our CEO, who were employed on December 31, 2017. We included all employees, whether employed on a full-time, part-time, temporary or seasonal basis. As of December 31, 2017, we employed 941 such persons.  We annualized the compensation for any employees that were not employed for all of 2017 (not including seasonal or temporary

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employees), but did not make any other assumptions, adjustments, or estimates with respect to total cash compensation or equity. Since all of our employees, including our CEO, are located in the United States, we did not make any cost of living adjustments in identifying the median employee. We believe the use of total cash and equity compensation for all employees is the most appropriate compensation measure since it includes the main elements of compensation for the majority of our employees. 

After identifying the median employee based on total cash and equity compensation, we calculated annual 2017 compensation for the median employee using the same methodology used to calculate the chief executive officer’s total compensation as reflected in the Summary Compensation Table above.  The median employee’s annual 2017 compensation was as follows:

Name	Year	Salary	Bonus	Stock Awards	Non-Equity Incentive Plan Compensation	All Other Compensation	Total
Median Employee	2017	$72,225	$500	$—	$9,734	$—	$82,459

With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2017 Summary Compensation Table included in this Annual Report, which was $6,384,820. Our 2017 ratio of chief executive officer total compensation to our median employee’s total compensation is reasonably estimated to be 77:1.

Compensation Committee Interlocks and Insider Participation

The compensation committee of the board of directors of our general partner oversees the compensation of our executive officers. Warren Gfeller and Alvin Bledsoe served as the members of the compensation committee during Fiscal 2017, and neither of them was an officer or employee of our company or any of its subsidiaries during Fiscal 2017.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters

The following table sets forth certain information as of February 15, 2018, regarding the beneficial ownership of our common units by:

• each person who then beneficially owned more than 5% of such units then outstanding;

• each of the named executive officers of our general partner;

• each of the directors of our general partner; and

• all of the directors and executive officers of our general partner as a group.

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All information with respect to beneficial ownership has been furnished by the respective directors, executive officers or 5% or more unitholders, as the case may be.

Name of Beneficial Owner(1)	Common Units Beneficially Owned	Percentage of Common Units Owned	Preferred Units Beneficially Owned (2)	Percentage of Preferred Units Beneficially Owned
Magnetar Financial LLC(3)	—	—	28,859,396	41.0%
GSO COF II Holdings Partners LP(4)	—	—	20,613,860	29.0%
Crestwood Gas Services Holdings LLC(5)(6)(7)	9,985,462	14.0%	—	—
Crestwood Holdings LLC(5)(6)	7,484,449	10.5%	—	—
Oppenheimer Funds, Inc.(8)	5,658,998	7.9%	—	—
Alvin Bledsoe(9)	33,617	*	—	—
J. Heath Deneke	270,483	*	—	—
Steven M. Dougherty	165,559	*	—	—
Michael G. France	17,131	*	—	—
Warren H. Gfeller	44,832	*	—	—
Robert T. Halpin	240,383	*	—	—
Joel C. Lambert	155,510	*	—	—
David Lumpkins	34,439	*	—	—
William H. Moore	165,411	*	—	—
Robert G. Phillips	379,974	*	—	—
John J. Sherman	3,224,331	4.5%	—	—
John W. Somerhalder II(9)	15,045	*	—	—
Directors and executive officers as a group (13 persons)	4,746,715		—	—

* Indicates less than 1%

(1) Unless otherwise indicated, the contact address for all beneficial owners in this table is 811 Main Street, Suite 3400, Houston, Texas 77002.

(2) The Preferred Units convert to common units on a 1-for-10 basis as set forth in the Crestwood Equity Partners LP Partnership Agreement.

(3) Preferred Units are held in various Magnetar funds as follows: MTP Energy Master Fund Ltd. (12,106,908), MTP Energy CM LLC (6,279,407), MTP Energy Opportunities Fund LLC (3,795,187), Magnetar Structured Credit Fund, LP (1,569,708), Magnetar Constellation Fund IV LLC (1,310,603), Compass HTV LLC (961,667), Magnetar Capital Fund II LP (822,563), Blackwell Partners LLC 600,259), Magnetar Global Event Drive Fund LLC (598,021), Magnetar Andromeda Select Fund LLC (484,260), Hipparchus Fund LP (194,815) and Spectrum Opportunities Fund LP (135,998). The address for Magnetar Financial LLC is 1603 Orrington Avenue, 13th Floor, Evanston, IL 60201.

(4) Mailing address for GSO COF Holdings Partners LP is 345 Park Avenue, 31st Floor, New York, NY 10154.

(5) Crestwood Holdings LLC has shared voting power and shared investment power with Crestwood Gas Services Holdings LLC on 9,985,462 common units. Crestwood Holdings LLC, FR Crestwood Management Co-Investment LLC, Crestwood Holdings Partners LLC, FR XI CMP Holdings LLC, FR Midstream Holdings LLC, First Reserve GP XI, L.P., First Reserve GP XI, Inc., and William E. Macaulay have control over 17,469,911 common units.

(6) Common units owned by Crestwood Gas Services Holdings LLC and Crestwood Holdings LLC are pledged as collateral under the Crestwood Holdings term loan.

(7) Does not include 438,789 subordinated units. The subordinated units may be converted to common units on a one-for-one basis upon the termination of the subordination period as set forth in the Crestwood Equity Partners LP Partnership Agreement.

(8) According to a Schedule 13G/A filed by Oppenheimer Funds, Inc., with the SEC on February 6, 2018, Oppenheimer Funds, Inc. has shared voting and dispositive power over 5,658,998 common units. The address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281.

(9) Includes 7,006 restricted units held in the Crestwood Nonqualified Deferred Compensation Plan.

See Part II, Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities of this report for certain information regarding securities authorized for issuance under our equity compensation plans.

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Item 13. Certain Relationships, Related Transactions and Director Independence

For a discussion of director independence, see Item 10, Directors, Executive Officers and Corporate Governance.

Transactions with Related Persons

First Reserve Joint Venture

In October 2016, Crestwood Infrastructure Holdings LLC, our wholly-owned subsidiary, and an affiliate of First Reserve formed a joint venture, Crestwood Permian Basin Holdings LLC (Crestwood Permian), to fund and own the Nautilus gathering system and other potential investments in the Delaware Permian. On June 21, 2017, the Company contributed contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico Pipeline LLC (Crestwood New Mexico), its wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New Mexico. These assets consist of two dry gas gathering systems (Las Animas systems) and one rich gas gathering system and processing plant (Willow Lake system). In conjunction with this contribution, First Reserve has agreed to contribute to Crestwood Permian the first $151 million of capital cost required to fund the expansion of the Delaware Basin assets, which includes a new processing plant located in Orla, Texas and associated pipelines (Orla processing plant), after which we will fund 100% of capital requirements until both parties have made an equal amount of capital contributions. We will continue to receive 100% of the available cash flow generated by the Willow Lake assets until the earlier of the Orla Plant in-service date or June 30, 2018, at which time the parties will receive distributions on a 50/50 basis.

Review, Approval or Ratification of Transactions with Related Persons

Our related person transactions policy applies to any transaction since the beginning of our fiscal year (or currently proposed transaction) in which we or any of our subsidiaries was or is to be a participant, the amount involved exceeds $120,000 and any director, director nominee, executive officer, 5% or greater unitholder (or their immediate family members) had, has or will have a direct or indirect material interest. A transaction that would be covered by this policy would include, but not be limited to, any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships.

Under our related person transactions policy, related person transactions may be entered into or continue only if the transaction is deemed to be “fair and reasonable” to us, in accordance with the terms of our partnership agreement. Under our partnership agreement, transactions that represent a “conflict of interest” may be approved in one of three ways and, if approved in any of those ways, will be considered “fair and reasonable” to us and the holders of our common units. The three ways enumerated in our related person transactions Policy for reaching this conclusion include:

(i) approval by the Conflicts Committee of the Board (the Conflicts Committee) under Section 7.9 of our partnership agreement (Special Approval);

(ii) approval by our Chief Executive Officer applying the criteria specified in Section 7.9 of our partnership agreement if the transaction is in the normal course of the partnership’s business and is (a) on terms no less favorable to the partnership than those generally being provided to or available from unrelated third parties or (b) fair to the partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership); and

(iii) approval by an independent committee of the Board (either the Audit Committee or a Special Committee) applying the criteria in Section 7.9 of our partnership agreement.

Once a transaction is approved in any of these ways, it is “fair and reasonable” and accordingly deemed (i) approved by all of our partners and (ii) not to be a breach of any fiduciary duties of general partner.

Our general partner determines in its discretion which method of approval is required depending on the circumstances.

Under our partnership agreement, when determining whether a related person transaction is “fair and reasonable,” if our general partner elects to adopt a resolution or a course of action that has not received Special Approval, then our general partner may consider:

• the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;

• any customary or accepted industry practices and any customary or historical dealings with a particular person;

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• any applicable generally accepted accounting practices or principles; and

• such additional factors as the general partner or conflicts committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

A related person transaction that is approved by the conflicts committee is, as discussed in greater detail above, conclusively deemed to be fair and reasonable to us. Under our partnership agreement, the material facts known to our general partner or any of our affiliates regarding the transaction must be disclosed to the conflicts committee at the time the committee gives its approval. When approving a related party transaction, the conflicts committee considers all factors it considers relevant, reasonable or appropriate under the circumstances, including the relative interests of any party to the transaction, customary industry practices and generally accepted accounting principles.

Under our partnership agreement, in the absence of bad faith by the general partner, the resolution, action or terms so made, taken or provided by the general partner with respect to approval of the related party transaction will not constitute a breach of our partnership agreement or any standard of fiduciary duty.

Under our related person transactions policy, as well as under our partnership agreement, there is no obligation to take any particular conflict to the conflicts committee-empaneling that committee is entirely at the discretion of the general partner. In many ways, the decision to engage the conflicts committee can be analogized to the kinds of transactions for which a Delaware corporation might establish a special committee of independent directors. The general partner considers the specific facts and circumstances involved. Relevant facts would include:

• the nature and size of the transaction (i.e., transaction with a controlling unitholder, magnitude of consideration to be paid or received, impact of proposed transaction on the general partner and holders of common units);

• the related person’s interest in the transaction;

• whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances;

• if applicable, the availability of other sources of comparable services or products; and

• the financial costs involved, including costs for separate financial, legal and possibly other advisors at our expense.

When determining whether a related person transaction is in the normal course of our business and is (a) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (b) fair to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us), the general partner considers any facts and circumstances that it deems to be relevant, including:

• the terms of the transaction, including the aggregate value;

• the business purpose of the transaction;

• the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;

• whether the terms of the transaction are comparable to the terms that would exist in a similar transaction with an unaffiliated third party;

• any customary or accepted industry practices;

• any applicable generally accepted accounting practices or principles; and

• such additional factors as the general partner or the conflicts committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

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Item 14. Principal Accountant Fees and Services

The Audit Committee of the Board of Directors of Crestwood Equity GP LLC approved the engagement of Ernst & Young LLP as the principal accountant to audit the partnership’s financial statements as of and for the fiscal year ending December 31, 2017. The following table summarizes the fees for professional services rendered by Ernst & Young LLP for the years ended December 31, 2017 and 2016 (in millions).

	2017		2016
Audit-related fees(1)	$	2.0	$	1.8
All other fees(2)	0.2		0.1
Total	$	2.2	$	1.9

(1) Includes fees related to the performance of the annual audit and quarterly reviews (including internal control evaluation and reporting) of the consolidated financial statements of Crestwood Equity and Crestwood Midstream and its subsidiaries.

(2) Includes fees primarily associated with acquisitions, dispositions and issuances of debt and equity.

The audit committee of Crestwood Equity’s general partner reviewed and approved all audit and non-audit services provided during 2017. Crestwood Midstream is a wholly-owned subsidiary of Crestwood Equity and, as such, it does not have a separate audit committee. Crestwood Equity’s audit committee has adopted a pre-approval policy for audit and non-audit services. For information regarding the audit committee’s pre-approval policies and procedures, see Crestwood Equity’s audit committee charter on its website at www.crestwoodlp.com.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

(a) Exhibits, Financial Statements and Financial Statement Schedules:

1. Financial Statements:

See Index Page for Financial Statements

2. Financial Statement Schedules:

Schedule I: Parent Only Condensed Financial Statements

Schedule II: Valuation and Qualifying Accounts

Other financial statement schedules have been omitted because they are either not required, are immaterial or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.

3. Exhibits:

Exhibit Number	Description
2.1	Agreement and Plan of Merger, dated as of May 5, 2015, by and among Crestwood Equity Partners LP, Crestwood Equity GP LLC, CEQP ST SUB LLC, MGP GP, LLC, Crestwood Midstream Holdings LP, Crestwood Midstream Partners LP, Crestwood Midstream GP LLC and Crestwood Gas Services GP LLC (incorporated by reference to Exhibit 2.1 to Crestwood Equity Partners LP’s Form 8-K filed May 6, 2015)
2.2	Contribution Agreement, dated as of April 20, 2016, by and between Crestwood Pipeline and Storage Northeast LLC and Con Edison Gas Pipeline and Storage Northeast, LLC (incorporated herein by reference to Exhibit 2.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 22, 2016)
3.1	Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-56976) filed on March 14, 2001)
3.2	Certificate of Correction of Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q filed on May 12, 2003)
3.3	Amendment to the Certificate of Limited Partnership of Crestwood Equity Partners LP (f/k/a Inergy, L.P.) (the “Partnership”) dated as of October 7, 2013 (incorporated herein by reference to Exhibit 3.2 to Crestwood Equity Partners LP’s Form 8-K filed on October 10, 2013)
3.4	Fifth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners LP dated 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)
3.5	First Amendment to the Fifth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners LP, dated as of September 30, 2015 (incorporated herein by reference to Exhibit 3.1 to the Crestwood Equity Partners LP’s Form 8-K filed on October 1, 2015)
3.6	Second Amendment to the Fifth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners LP, dated as of November 8, 2017 (incorporated herein by reference to Exhibit 3.1 to Crestwood Equity Partners LP’s Form 8-K filed on November 13, 2017)
3.7	Certificate of Formation of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.5 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
3.8	Certificate of Amendment of Crestwood Equity GP LLC (f/k/a Inergy GP, LLC) dated October 7, 2013 (incorporated herein by reference to Exhibit 3.3A to Crestwood Equity Partners LP’s Form 10-Q filed on November 8, 2013)
3.9	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)

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Exhibit Number	Description
3.10	Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Crestwood Equity GP LLC (f/k/a Inergy GP, LLC) entered into effective October 7, 2013 (incorporated herein by reference to Exhibit 3.4A to Crestwood Equity Partners LP’s Form 10-Q filed on November 8, 2013)
3.11	Certificate of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.4 to Inergy Midstream, L.P.’s Form S-1/A filed on November 21, 2011)
3.12	Amendment to the Certificate of Limited Partnership of Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.2 to Inergy Midstream, L.P.’s Form 8-K filed on October 10, 2013)
3.13	First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P., dated December 21, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy Midstream, L.P.’s Form S-8 filed on December 21, 2011)
3.14	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy Midstream, L.P.’s Form 8-K filed on October 1, 2013)
3.15	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.1 to Crestwood Midstream Partners LP’s Form 8-K filed on October 10, 2013)
3.16	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP dated as of June 17, 2014 (incorporated herein by reference to Exhibit 3.1 to Crestwood Midstream Partners LP’s Form 8-K filed on June 19, 2014)
3.17	Second Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP, dated as of September 30, 2015 (incorporated by reference to Exhibit 3.1 to Crestwood Midstream Partners LP’s Form 8-K filed on October 1, 2015)
3.18	Certificate of Formation of NRGM GP, LLC (incorporated herein by reference to Exhibit 3.7 to Inergy Midstream, L.P.’s Form S-1/A filed on November 21, 2011)
3.19	Certificate of Amendment of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.37 to Crestwood Midstream Partners LP’s Form S-4/A filed on October 28, 2013)
3.20	Amended and Restated Limited Liability Company Agreement of NRGM GP, LLC, dated December 21, 2011 (incorporated herein by reference to Exhibit 3.2 to Inergy Midstream, L.P.’s Form 8-K filed on December 22, 2011)
3.21	Amendment No. 1 to the Amended and Restated Limited Liability Company Agreement of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.39 to Crestwood Midstream Partners LP’s Form S-4/A filed on October 28, 2013)
4.1	Specimen Unit Certificate for Common Units (incorporated herein by reference to Exhibit 4.3 to Inergy L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
4.2	Indenture, dated as of March 14, 2017, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on March 15, 2017)
4.3	Supplemental Indenture dated as of June 5, 2017, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, each existing Guarantor and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 10-Q filed on August 4, 2017)
**4.4	Supplemental Indenture dated as of December 1, 2017, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, each existing Guarantor and U.S. Bank National Association, as trustee
4.5	Indenture, dated as of March 23, 2015, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 8-K filed on March 27, 2015)

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Exhibit Number	Description
4.6	First Supplemental Indenture, dated March 4, 2016, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.3 to Crestwood Midstream Partners LP’s Form 8-K filed on March 7, 2016)
4.7	Supplemental Indenture, dated as of June 3, 2016, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 10-Q filed on August 4, 2016)
4.8	Supplemental Indenture, dated as of September 30, 2016, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 10-Q filed on November 4, 2016)
***4.9	Second Amended and Restated Limited Liability Company Agreement for Crestwood Niobrara LLC, dated December 28, 2017, between Crestwood Midstream Partners LP and CN Jackalope Holdings, LLC
**4.10	Registration Rights Agreement, dated December 28, 2017, by and among Crestwood Equity Partners LP and CN Jackalope Holdings, LLC
4.11	Registration Rights Agreement, dated as of March 14, 2017, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and J.P. Morgan Securities LLC, as representative of the several initial purchasers, with respect to the 5.75% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on March 15, 2017)
4.12	Registration Rights Agreement, dated as of September 30, 2015, by and among Crestwood Equity Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on October 1, 2015)
*10.1	Second Amended and Restated Employment Agreement, dated July 21, 2017, between Heath Deneke and Crestwood Operations LLC (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on July 25, 2017)
**10.2	Omnibus Amendment to Employment Agreements dated February 22, 2018 by and between Crestwood Operations LLC and each of Robert G. Phillips, Robert Halpin, Steven Dougherty, Joel Lambert and William H. Moore
*10.3	Employment Agreement between Robert G. Phillips and Crestwood Operations LLC dated as of January 21, 2014 (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on January 27, 2014)
*10.4	Employment Agreement between Joel Lambert and Crestwood Operations LLC dated as of January 21, 2014 (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s Form 10-K filed on February 28, 2014)
*10.5	Employment Agreement between William H. Moore and Crestwood Operations LLC dated as of January 21, 2014 (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s Form 10-K filed on March 2, 2015)
*10.6	Employment Agreement between Steven M. Dougherty and Crestwood Operations LLC dated as of January 21, 2014 (incorporated herein by reference to Exhibit 10.4 to Crestwood Equity Partners LP’s Form 10-K filed on February 29, 2016)
*10.7	Amended and Restated Employee Agreement between Robert T. Halpin and Crestwood Operations LLC dated as of April 1, 2015 (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s Form 10-K filed on February 29, 2016)
*10.8	Crestwood Equity Partners LP Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.7 to Crestwood Equity Partners LP’s Form 10-K filed on February 28, 2014)
*10.9	Form of Crestwood Equity Partners LP’s Restricted Unit Award Agreement (incorporated herein by reference to Exhibit 4.12 to Crestwood Equity Partner LP’s Form S-8 filed on January 16, 2015)
*10.10	Form of Crestwood Equity Partners LP’s Phantom Unit Award Agreement (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on January 23, 2015)
*10.11	Form of Crestwood Equity Partners LP’s Performance Unit Grant Agreement (incorporated by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 10-Q filed on May 4, 2017)

103

Exhibit Number	Description
*10.12	Crestwood Equity Partners Non-Qualified Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on November 15, 2016)
10.13	Amended and Restated Credit Agreement, dated as of September 30, 2015, by and among Crestwood Midstream Partners LP, as borrower, the lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on October 1, 2015)
10.14	Amendment dated as of April 20, 2016, among Crestwood Midstream Partners LP, as borrower, certain guarantors and financial institutions party thereto, and Wells Fargo Bank, National Association, as administrative agent and collateral agent. (incorporated herein by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 8-K filed on April 22, 2016)
10.15	Guaranty, dated as of April 20, 2016, made by Crestwood Equity Partners LP in favor of Con Edison Gas Pipeline and Storage Northeast, LLC (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 22, 2016)
10.16	Amended and Restated Limited Liability Company Agreement of Stagecoach Gas Services LLC dated as of June 3, 2016. (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on June 8, 2016)
10.17	Gas Gathering Agreement, dated as of April 6, 2016, among Cowtown Pipeline Partners L.P., as Gatherer, and BlueStone Natural Resources II, LLC, as Producer (incorporated herein by reference to Exhibit 10.3 to Crestwood Equity Partners LP’s Form 10-Q filed on August 4, 2016)
10.18	Gas Gathering and Processing Agreement, dated as of April 6, 2016, among BlueStone Natural Resources II, LLC, as Producer, Cowtown Pipeline Partners L.P., as Gatherer, and Cowtown Gas Processing Partners LP, as Processor (incorporated herein by reference to Exhibit 10.4 to Crestwood Equity Partners LP’s Form 10-Q filed on August 4, 2016)
10.19	Gas Gathering Agreement, dated as of April 6, 2016, among BlueStone Natural Resources II, LLC, as Producer, and Cowtown Pipeline Partners L.P., as Gatherer (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s Form 10-Q filed on August 4, 2016)
10.20	Letter Agreement to Gathering and Processing Agreements, dated as of April 6, 2016, among Cowtown Pipeline Partners L.P., Cowtown Gas Processing Partners L.P. and BlueStone Natural Resources II, LLC(incorporated herein by reference to Exhibit 10.6 to Crestwood Equity Partners LP’s Form 10-Q filed on August 4, 2016)
10.21	Guarantee, dated as of February 24, 2012, by Crestwood Holdings LLC and Crestwood Midstream Partners LP, in favor of Antero Resources Appalachian Corporation (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on February 28, 2012)
10.22	Gas Gathering and Compression Agreement, dated as of January 1, 2012, by and between Antero Resources Appalachian Corporation and Crestwood Marcellus Midstream LLC (incorporated herein by reference to Exhibit 10.23 to Crestwood Midstream Partners LP’s Form 10-K filed on February 28, 2013)
10.23	Registration Rights Agreement, dated as of September 30, 2015, by and among Crestwood Equity Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on October 1, 2015)
10.24	Board Representation and Standstill Agreement, dated as of September 30, 2015, by and among Crestwood Equity GP LLC, Crestwood Equity Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 8-K filed on October 1, 2015)
10.25	Support Agreement, dated as of May 5, 2015, by and among Crestwood Equity Partners LP, Crestwood Midstream Partners LP and CGS GP (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on May 6, 2015)
10.26	Equity Distribution Agreement, dated August 4, 2017, by and among Crestwood Equity Partners LP and the Managers named therein (incorporated by reference to Exhibit 1.1 to Crestwood Equity Partners LP’s Form 8-K filed on August 4, 2017)
**12.1	Computation of ratio of earnings to fixed charges - Crestwood Equity Partners LP
**12.2	Computation of ratio of earnings to fixed charges - Crestwood Midstream Partners LP

104

Exhibit Number	Description
16.1	Letter Regarding Change in Certifying Accountant (incorporated herein by reference to Exhibit 16.1 to Inergy, L.P.’s Form 8-K/A filed on July 23, 2013)
**21.1	List of subsidiaries of Crestwood Equity Partners LP
**23.1	Consent of Ernst & Young LLP - Crestwood Equity Partners LP
**23.2	Consent of Ernst & Young LLP - Crestwood Midstream Partners LP
**31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended - Crestwood Equity Partners LP
**31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended - Crestwood Equity Partners LP
**31.3	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended - Crestwood Midstream Partners LP
**31.4	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended - Crestwood Midstream Partners LP
**32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Equity Partners LP
**32.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Equity Partners LP
**32.3	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Midstream Partners LP
**32.4	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Midstream Partners LP
**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

*	Management contracts or compensatory plans or arrangements
**	Filed herewith
***	Confidential treatment has been requested for certain portions which are omitted in the copy of the exhibit electronically filed with the SEC. The omitted information has been filed separately with the SEC pursuant to our application for confidential treatment

(b) Exhibits.

See exhibits identified above under Item 15(a)3.

(c) Financial Statement Schedules.

See financial statement schedules identified above under Item 15(a)2.

105

Crestwood Equity Partners LP

Crestwood Midstream Partners LP

Consolidated Financial Statements

December 31, 2017 and 2016 and each of the

Three Years in the Period Ended

December 31, 2017

Contents

Crestwood Equity Partners LP
Report of Independent Registered Public Accounting Firm	107
Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial Reporting	108
Audited Consolidated Financial Statements:
Consolidated Balance Sheets	109
Consolidated Statements of Operations	110
Consolidated Statements of Comprehensive Income	112
Consolidated Statements of Partners’ Capital	113
Consolidated Statements of Cash Flows	114
Notes to Consolidated Financial Statements	122
Crestwood Midstream Partners LP
Report of Independent Registered Public Accounting Firm	116
Audited Consolidated Financial Statements:
Consolidated Balance Sheets	117
Consolidated Statements of Operations	118
Consolidated Statements of Partners’ Capital	119
Consolidated Statements of Cash Flows	120
Notes to Consolidated Financial Statements	122

106

Report of Independent Registered Public Accounting Firm

The Board of Directors of Crestwood Equity GP LLC and Unitholders of Crestwood Equity Partners LP

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Crestwood Equity Partners LP (the Company) as of December 31, 2017 and 2016, and the related consolidated statements of operations, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and financial statement schedules listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 23, 2018 expressed an unqualified opinion thereon.

Adoption of ASU No. 2017-04

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of measuring goodwill impairment charges as a result of adoption of the amendments to the FASB Accounting Standards Codification resulting from Accounting Standards No. 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment”.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2013.

Houston, Texas

February 23, 2018

107

Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial Reporting

The Board of Directors of Crestwood Equity GP LLC and Unitholders of Crestwood Equity Partners LP

Opinion on Internal Control over Financial Reporting

We have audited Crestwood Equity Partners LP’s internal control over financial reporting as of December 31, 2017, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Crestwood Equity Partners LP (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2017, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets as of December 31, 2017 and 2016 and related consolidated statements of operations, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2017, and the related notes and financial statement schedules listed in the Index at Item 15(a) of the Company and our report dated February 23, 2018 expressed an unqualified opinion thereon.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 23, 2018

108

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED BALANCE SHEETS (in millions, except unit information)
	December 31,
	2017		2016
Assets
Current assets:
Cash	$	1.3	$	1.6
Accounts receivable, less allowance for doubtful accounts of $2.4 million and $1.9 million at December 31, 2017 and 2016	442.7		289.8
Inventory	68.4		66.0
Assets from price risk management activities	7.2		6.3
Prepaid expenses and other current assets	10.9		9.7
Total current assets	530.5		373.4
Property, plant and equipment	2,285.2		2,555.4
Less: accumulated depreciation and depletion	464.4		457.8
Property, plant and equipment, net	1,820.8		2,097.6
Intangible assets	788.8		898.6
Less: accumulated amortization	191.6		241.2
Intangible assets, net	597.2		657.4
Goodwill	147.6		199.0
Investments in unconsolidated affiliates	1,183.0		1,115.4
Other assets	5.8		6.1
Total assets	$	4,284.9	$	4,448.9
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	349.4	$	217.2
Accrued expenses and other liabilities	105.9		90.5
Liabilities from price risk management activities	48.9		28.6
Current portion of long-term debt	0.9		1.0
Total current liabilities	505.1		337.3
Long-term debt, less current portion	1,491.3		1,522.7
Other long-term liabilities	104.7		44.6
Deferred income taxes	3.3		5.3
Commitments and contingencies (Note 15)
Partners’ capital:
Crestwood Equity Partners LP partners’ capital (70,721,563 and 69,499,741 common and subordinated units issued and outstanding at December 31, 2017 and 2016)	1,393.5		1,782.0
Preferred units (71,257,445 and 66,533,415 units issued and outstanding at December 31, 2017 and 2016)	612.0		564.5
Total Crestwood Equity Partners LP partners’ capital	2,005.5		2,346.5
Interest of non-controlling partners in subsidiaries	175.0		192.5
Total partners’ capital	2,180.5		2,539.0
Total liabilities and partners’ capital	$	4,284.9	$	4,448.9

See accompanying notes.

109

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, except unit and per unit data)
	Year Ended December 31,
	2017			2016			2015
Revenues:
Product revenues:
Gathering and processing	$	1,369.1		$	825.5		$	1,051.2
Marketing, supply and logistics	2,093.1			1,144.3			857.5
	3,462.2			1,969.8			1,908.7
Service revenues:
Gathering and processing	317.3			290.7			325.9
Storage and transportation	37.2			165.3			266.3
Marketing, supply and logistics	62.4			92.1			128.0
Related party (Note 16)	1.8			2.6			3.9
	418.7			550.7			724.1
Total revenues	3,880.9			2,520.5			2,632.8
Costs of product/services sold (exclusive of items shown separately below):
Product costs	3,309.5			1,851.9			1,780.0
Product costs - related party (Note 16)	15.3			17.7			28.9
Service costs	49.9			55.5			74.6
Total costs of products/services sold	3,374.7			1,925.1			1,883.5
Expenses:
Operations and maintenance	136.0			158.1			190.2
General and administrative	96.5			88.2			116.3
Depreciation, amortization and accretion	191.7			229.6			300.1
	424.2			475.9			606.6
Other operating expense:
Loss on long-lived assets, net	(65.6		)	(65.6		)	(821.2		)
Goodwill impairment	(38.8		)	(162.6		)	(1,406.3		)
Loss on contingent consideration	(57.0		)	—			—
Operating income (loss)	(79.4		)	(108.7		)	(2,084.8		)

110

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF OPERATIONS (continued) (in millions, except unit and per unit data)
	Year Ended December 31,
	2017			2016			2015
Earnings (loss) from unconsolidated affiliates, net	47.8			31.5			(60.8		)
Interest and debt expense, net	(99.4		)	(125.1		)	(140.1		)
Gain (loss) on modification/extinguishment of debt	(37.7		)	10.0			(20.0		)
Other income, net	1.3			0.5			0.6
Loss before income taxes	(167.4		)	(191.8		)	(2,305.1		)
(Provision) benefit for income taxes	0.8			(0.3		)	1.4
Net loss	(166.6		)	(192.1		)	(2,303.7		)
Net income (loss) attributable to non-controlling partners	25.3			24.2			(636.8		)
Net loss attributable to Crestwood Equity Partners LP	(191.9		)	(216.3		)	(1,666.9		)
Net income attributable to preferred units	62.5			28.7			6.2
Net loss attributable to partners	$	(254.4	)	$	(245.0	)	$	(1,673.1	)
Common unitholders’ interest in net loss	$	(254.4	)	$	(245.0	)	$	(1,673.1	)
Net loss per limited partner unit:
Basic	$	(3.64	)	$	(3.55	)	$	(54.00	)
Diluted	$	(3.64	)	$	(3.55	)	$	(54.00	)
Weighted-average limited partners’ units outstanding (in thousands):
Basic	69,839			69,017			30,983
Dilutive units	—			—			—
Diluted	69,839			69,017			30,983

See accompanying notes.

111

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in millions)
	Year Ended December 31,
	2017			2016			2015
Net loss	$	(166.6	)	$	(192.1	)	$	(2,303.7	)
Change in fair value of Suburban Propane Partners, L.P. units	(0.8		)	0.8			(2.7		)
Comprehensive loss	(167.4		)	(191.3		)	(2,306.4		)
Comprehensive income (loss) attributable to non-controlling partners	25.3			24.2			(636.8		)
Comprehensive loss attributable to Crestwood Equity Partners LP	$	(192.7	)	$	(215.5	)	$	(1,669.6	)

See accompanying notes.

112

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (in millions)
	Preferred				Partners
	Units	Capital			Common Units		Subordinated Units	Capital			Non-Controlling Partners			Total Partners’ Capital
Balance at December 31, 2014	—	$	—		18.2		0.4	$	776.2		$	4,808.3		$	5,584.5
Acquisition of CMLP non-controlling interest and conversion of preferred units	59.3	529.6			49.9		—	3,294.8			(3,824.4		)	—
Issuance of CMLP Class A preferred units	1.4	—			—		—	—			58.8			58.8
Distributions to partners	—	—			—		—	(171.5		)	(234.2		)	(405.7		)
Unit-based compensation charges	—	—			0.1		—	5.7			14.0			19.7
Taxes paid for unit-based compensation vesting	—	—			—		—	(1.6		)	(2.1		)	(3.7		)
Change in fair value of Suburban Propane Partners, L.P. units	—	—			—		—	(2.7		)	—			(2.7		)
Other	—	—			—		—	(0.2		)	(0.1		)	(0.3		)
Net income (loss)	—	6.2			—		—	(1,673.1		)	(636.8		)	(2,303.7		)
Balance at December 31, 2015	60.7	535.8			68.2		0.4	2,227.6			183.5			2,946.9
Distributions to partners	5.8	—			—		—	(219.8		)	(15.2		)	(235.0		)
Unit-based compensation charges	—	—			0.9		—	19.2			—			19.2
Taxes paid for unit-based compensation vesting	—	—			—		—	(0.8		)	—			(0.8		)
Change in fair value of Suburban Propane Partners, L.P. units	—	—			—		—	0.8			—			0.8
Net income (loss)	—	28.7			—		—	(245.0		)	24.2			(192.1		)
Balance at December 31, 2016	66.5	564.5			69.1		0.4	1,782.0			192.5			2,539.0
Distributions to partners	4.8	(15.0		)	—		—	(167.6		)	(15.2		)	(197.8		)
Unit based compensation charges	—	—			0.8		—	25.5			—			25.5
Taxes paid for unit-based compensation vesting	—	—			(0.2	)	—	(5.5		)	—			(5.5		)
Change in fair value of Suburban Propane Partners, L.P. units	—	—			—		—	(0.8		)	—			(0.8		)
Issuance of common units	—	—			0.6		—	15.2			—			15.2
Redemption of non-controlling interest	—	—			—		—	—			(202.7		)	(202.7		)
Issuance of non-controlling interest	—	—			—		—	—			175.0			175.0
Other	—	—			—		—	(0.9		)	0.1			(0.8		)
Net income (loss)	—	62.5			—		—	(254.4		)	25.3			(166.6		)
Balance at December 31, 2017	71.3	$	612.0		70.3		0.4	$	1,393.5		$	175.0		$	2,180.5

See accompanying notes.

113

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)
	Year Ended December 31,
	2017			2016			2015
Operating activities
Net loss	$	(166.6	)	$	(192.1	)	$	(2,303.7	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion	191.7			229.6			300.1
Amortization of debt-related deferred costs	7.2			6.9			8.9
Market adjustment on interest rate swaps	—			—			(0.5		)
Unit-based compensation charges	25.5			19.2			19.7
Loss on long-lived assets, net	65.6			65.6			821.2
Goodwill impairment	38.8			162.6			1,406.3
Loss on contingent consideration	57.0			—			—
(Gain) loss on modification/extinguishment of debt	37.7			(10.0		)	20.0
(Earnings) loss from unconsolidated affiliates, net, adjusted for cash distributions received	(0.1		)	7.6			73.6
Deferred income taxes	(2.1		)	(3.1		)	(3.6		)
Other	0.9			1.9			0.7
Changes in operating assets and liabilities:
Accounts receivable	(170.7		)	(76.9		)	119.7
Inventory	(9.9		)	(22.5		)	2.0
Prepaid expenses and other current assets	1.8			9.2			1.8
Accounts payable, accrued expenses and other liabilities	140.1			74.6			(128.0		)
Reimbursements of property, plant and equipment	19.6			26.0			73.3
Change in price risk management activities, net	19.4			47.5			29.2
Net cash provided by operating activities	255.9			346.1			440.7
Investing activities
Acquisitions, net of cash acquired	—			(7.2		)	—
Purchases of property, plant and equipment	(188.4		)	(100.7		)	(182.7		)
Investment in unconsolidated affiliates	(58.0		)	(12.4		)	(42.0		)
Capital distributions from unconsolidated affiliates	59.9			14.8			9.3
Net proceeds from sale of assets	225.2			972.7			2.7
Net cash provided by (used in) investing activities	38.7			867.2			(212.7		)

114

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (in millions)
	Year Ended December 31,
	2017			2016			2015
Financing activities
Proceeds from the issuance of long-term debt	2,838.6			1,565.3			4,261.8
Payments on long-term debt	(2,913.9		)	(2,536.3		)	(4,113.0		)
Payments on capital leases	(2.7		)	(1.9		)	(2.2		)
Payments for debt-related deferred costs	(1.0		)	(3.5		)	(17.3		)
Financing fees paid for early debt redemption	—			—			(13.6		)
Redemption of non-controlling interest	(202.7		)	—			—
Net proceeds from issuance of non-controlling interest	175.0			—			—
Distributions to partners	(167.6		)	(219.8		)	(171.5		)
Distributions paid to non-controlling partners	(15.2		)	(15.2		)	(234.2		)
Distribution to preferred unit holders	(15.0		)	—			—
Net proceeds from issuance of common units	15.2			—			—
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units	—			—			58.8
Taxes paid for unit-based compensation vesting	(5.5		)	(0.8		)	(3.8		)
Other	(0.1		)	—			(1.3		)
Net cash used in financing activities	(294.9		)	(1,212.2		)	(236.3		)
Net change in cash	(0.3		)	1.1			(8.3		)
Cash at beginning of period	1.6			0.5			8.8
Cash at end of period	$	1.3		$	1.6		$	0.5
Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	95.1		$	121.5		$	129.0
Cash paid during the period for income taxes	$	3.1		$	1.4		$	4.7
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(20.4	)	$	(10.5	)	$	(14.1	)

See accompanying notes.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Crestwood Equity GP LCC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Crestwood Midstream Partners (the Company) as of December 31, 2017 and 2016, and the related consolidated statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2017, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2017 and 2016, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2017, in conformity with U.S. generally accepted accounting principles.

Adoption of ASU No. 2017-04

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of measuring goodwill impairment charges as a result of adoption of the amendments to the FASB Accounting Standards Codification resulting from Accounting Standards No. 2017-04, “Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment”.

Basis for Opinion

These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2013.

Houston, Texas

February 23, 2018

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CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED BALANCE SHEETS (in millions)
	December 31,
	2017		2016
Assets
Current assets:
Cash	$	1.0	$	1.3
Accounts receivable, less allowance for doubtful accounts of $2.4 million and $1.9 million at December 31, 2017 and 2016	442.6		289.8
Inventory	68.4		66.0
Assets from price risk management activities	7.2		6.3
Prepaid expenses and other current assets	10.9		9.7
Total current assets	530.1		373.1
Property, plant and equipment	2,615.3		2,885.5
Less: accumulated depreciation and depletion	607.8		587.1
Property, plant and equipment, net	2,007.5		2,298.4
Intangible assets	773.3		883.1
Less: accumulated amortization	177.6		230.2
Intangible assets, net	595.7		652.9
Goodwill	147.6		199.0
Investments in unconsolidated affiliates	1,183.0		1,115.4
Other assets	2.4		1.8
Total assets	$	4,466.3	$	4,640.6
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	346.8	$	214.5
Accrued expenses and other liabilities	104.7		87.9
Liabilities from price risk management activities	48.9		28.6
Current portion of long-term debt	0.9		1.0
Total current liabilities	501.3		332.0
Long-term debt, less current portion	1,491.3		1,522.7
Other long-term liabilities	102.6		42.0
Deferred income taxes	0.7		0.7
Commitments and contingencies (Note 15)
Partners’ capital	2,195.4		2,550.7
Interest of non-controlling partners in subsidiary	175.0		192.5
Total partners’ capital	2,370.4		2,743.2
Total liabilities and partners’ capital	$	4,466.3	$	4,640.6

See accompanying notes.

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CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF OPERATIONS (in millions)
	Year Ended December 31,
	2017			2016			2015
Revenues:
Product revenues:
Gathering and processing	$	1,369.1		$	825.5		$	1,051.2
Marketing, supply and logistics	2,093.1			1,144.3			857.5
	3,462.2			1,969.8			1,908.7
Service revenues:
Gathering and processing	317.3			290.7			325.9
Storage and transportation	37.2			165.3			266.3
Marketing, supply and logistics	62.4			92.1			128.0
Related party (Note 16)	1.8			2.6			3.9
	418.7			550.7			724.1
Total revenues	3,880.9			2,520.5			2,632.8
Costs of product/services sold (exclusive of items shown separately below):
Product costs	3,309.5			1,851.9			1,780.0
Product costs - related party (Note 16)	15.3			17.7			28.9
Service costs	49.9			55.5			74.6
Total costs of products/services sold	3,374.7			1,925.1			1,883.5
Expenses:
Operations and maintenance	136.0			155.0			188.7
General and administrative	93.1			85.6			105.6
Depreciation, amortization and accretion	202.7			240.5			278.5
	431.8			481.1			572.8
Other operating expense:
Loss on long-lived assets, net	(65.6		)	(65.6		)	(227.8		)
Goodwill impairment	(38.8		)	(162.6		)	(1,149.1		)
Loss on contingent consideration	(57.0		)	—			—
Operating loss	(87.0		)	(113.9		)	(1,200.4		)
Earnings (loss) from unconsolidated affiliates, net	47.8			31.5			(60.8		)
Interest and debt expense, net	(99.4		)	(125.1		)	(130.5		)
Gain (loss) on modification/extinguishment of debt	(37.7		)	10.0			(18.9		)
Other income, net	0.8			—			—
Net loss	(175.5		)	(197.5		)	(1,410.6		)
Net income attributable to non-controlling partners	25.3			24.2			23.1
Net loss attributable to Crestwood Midstream Partners LP	(200.8		)	(221.7		)	(1,433.7		)
Net income attributable to Class A preferred units	—			—			23.1
Net loss attributable to partners	$	(200.8	)	$	(221.7	)	$	(1,456.8	)

See accompanying notes.

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CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (in millions)
	Class A Preferred Units			Partners			Non-controlling Partners			Total Partners’ Capital
Balance at December 31, 2014	$	447.7		$	4,701.0		$	171.7		$	5,320.4
Issuance of Class A preferred units	58.8			—			—			58.8
Exchange of CMLP Class A preferred units for CEQP preferred units	(529.6		)	529.6			—			—
Distributions to partners	—			(808.2		)	(11.3		)	(819.5		)
Unit-based compensation charges	—			18.1			—			18.1
Taxes paid for unit-based compensation vesting	—			(2.1		)	—			(2.1		)
Net income (loss)	23.1			(1,456.8		)	23.1			(1,410.6		)
Balance at December 31, 2015	—			2,981.6			183.5			3,165.1
Distributions to partners	—			(227.6		)	(15.2		)	(242.8		)
Unit-based compensation charges	—			19.2			—			19.2
Taxes paid for unit-based compensation vesting	—			(0.8		)	—			(0.8		)
Net income (loss)	—			(221.7		)	24.2			(197.5		)
Balance at December 31, 2016	—			2,550.7			192.5			2,743.2
Distributions to partners	—			(174.0		)	(15.2		)	(189.2		)
Unit-based compensation charges	—			25.5			—			25.5
Taxes paid for unit-based compensation vesting	—			(5.5		)	—			(5.5		)
Redemption of non-controlling interest	—			—			(202.7		)	(202.7		)
Issuance of non-controlling interest	—			—			175.0			175.0
Other	—			(0.5		)	0.1			(0.4		)
Net income (loss)	—			(200.8		)	25.3			(175.5		)
Balance at December 31, 2017	$	—		$	2,195.4		$	175.0		$	2,370.4

See accompanying notes.

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CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)
	Year Ended December 31,
	2017			2016			2015
Operating activities
Net loss	$	(175.5	)	$	(197.5	)	$	(1,410.6	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion	202.7			240.5			278.5
Amortization of debt-related deferred costs	7.2			6.9			8.1
Unit-based compensation charges	25.5			19.2			18.1
Loss on long-lived assets, net	65.6			65.6			227.8
Goodwill impairment	38.8			162.6			1,149.1
Loss on contingent consideration	57.0			—			—
(Gain) loss on modification/extinguishment of debt	37.7			(10.0		)	18.9
(Earnings) loss from unconsolidated affiliates, net, adjusted for cash distributions received	(0.1		)	7.6			73.6
Deferred income taxes	—			0.2			(0.3		)
Other	0.9			1.9			0.7
Changes in operating assets and liabilities:
Accounts receivable	(170.5		)	(76.9		)	119.4
Inventory	(9.9		)	(22.5		)	2.1
Prepaid expenses and other current assets	1.8			7.5			3.7
Accounts payable, accrued expenses and other liabilities	142.0			75.2			(119.8		)
Reimbursements of property, plant and equipment	19.6			26.0			73.3
Change in price risk management activities, net	19.4			47.5			29.2
Net cash provided by operating activities	262.2			353.8			471.8
Investing activities
Acquisitions, net of cash acquired	—			(7.2		)	—
Purchases of property, plant and equipment	(188.4		)	(100.7		)	(182.7		)
Investment in unconsolidated affiliates	(58.0		)	(12.4		)	(41.8		)
Capital distributions from unconsolidated affiliates	59.9			14.8			9.3
Net proceeds from sale of assets	225.2			972.7			2.7
Net cash provided by (used in) investing activities	38.7			867.2			(212.5		)

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CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (in millions)
	Year Ended December 31,
	2017			2016			2015
Financing activities
Proceeds from the issuance of long-term debt	2,838.6			1,565.3			3,490.1
Payments on long-term debt	(2,913.9		)	(2,536.1		)	(2,960.9		)
Payments on capital leases	(2.7		)	(1.9		)	(2.2		)
Payments for debt-related deferred costs	(1.0		)	(3.5		)	(17.3		)
Financing fees paid for early debt redemption	—			—			(13.6		)
Redemption of non-controlling interest	(202.7		)	—			—
Net proceeds from issuance of non-controlling interest	175.0			—			—
Distributions to partners	(189.2		)	(242.8		)	(819.5		)
Net proceeds from issuance of Class A preferred units	—			—			58.8
Taxes paid for unit-based compensation vesting	(5.5		)	(0.8		)	(2.1		)
Other	0.2			—			(0.1		)
Net cash used in financing activities	(301.2		)	(1,219.8		)	(266.8		)
Net change in cash	(0.3		)	1.2			(7.5		)
Cash at beginning of period	1.3			0.1			7.6
Cash at end of period	$	1.0		$	1.3		$	0.1
Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	95.1		$	121.5		$	118.2
Cash paid during the period for income taxes	$	0.6		$	0.7		$	0.6
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(20.4	)	$	(10.5	)	$	(14.1	)

See accompanying notes.

121

CRESTWOOD EQUITY PARTNERS LP

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Organization and Description of Business

The accompanying notes to the consolidated financial statements apply to Crestwood Equity Partners LP (the Company, Crestwood Equity or CEQP) and Crestwood Midstream Partners LP (Crestwood Midstream or CMLP) unless otherwise indicated.

Organization

Crestwood Equity Partners LP. CEQP is a publicly-traded (NYSE: CEQP) Delaware limited partnership formed in March 2001. Crestwood Equity GP LLC, which is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), owns our non-economic general partnership interest. Crestwood Holdings, which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve), also owns approximately 25% of Crestwood Equity’s common units and all of its subordinated units.

Crestwood Midstream Partners LP. Crestwood Equity owns a 99.9% limited partnership interest in Crestwood Midstream and Crestwood Gas Services GP LLC (CGS GP), a wholly-owned subsidiary of Crestwood Equity, owns a 0.1% limited partnership interest in Crestwood Midstream. Crestwood Midstream GP LLC, a wholly-owned subsidiary of Crestwood Equity, owns the non-economic general partnership interest of Crestwood Midstream.

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The diagram below reflects a simplified version of our ownership structure as of December 31, 2017:

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

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Description of Business

Crestwood Equity develops, acquires, owns or controls, and operates primarily fee-based assets and operations within the energy midstream sector. We provide broad-ranging infrastructure solutions across the value chain to service premier liquids-rich natural gas and crude oil shale plays across the United States. We own and operate a diversified portfolio of crude oil and natural gas gathering, processing, storage and transportation assets and connect fundamental energy supply with energy demand across North America. Crestwood Equity is a holding company and all of its consolidated assets are owned by or through its wholly-owned subsidiary, Crestwood Midstream.

Our financial statements reflect three operating and reporting segments described below.

• Gathering and Processing: our gathering and processing (G&P) operations provide gathering and transportation services (natural gas, crude oil and produced water) and processing, treating and compression services (natural gas) to producers in unconventional shale plays and tight-gas plays in North Dakota, West Virginia, Texas, New Mexico, Wyoming and Arkansas. This segment primarily includes (i) our operations that own crude oil, rich and dry gas gathering systems, produced water gathering systems and processing plants in the Bakken, Marcellus, Barnett and Fayetteville Shale plays; and (ii) joint ventures that own rich and dry gas gathering systems and processing plants in the Delaware Permian and Powder River Basin (PRB) Niobrara Shale plays.

• Storage and Transportation: our storage and transportation (S&T) operations provide crude oil and natural gas storage and transportation services to producers, utilities and other customers. This segment primarily includes (i) our integrated crude oil loading, storage and pipeline terminal located in the heart of the Bakken and Three Forks Shale oil-producing areas in Williams County, North Dakota (the COLT Hub); and (ii) joint ventures that own regulated natural gas storage and transportation facilities in New York and Pennsylvania, natural gas storage facilities in Texas and a crude-by-rail terminal in Wyoming.

• Marketing, Supply and Logistics: our marketing, supply and logistics (MS&L) operations provide NGL and crude oil storage, marketing and transportation services to producers, refiners, marketers and other customers. This segment primarily includes (i) our fleet of rail and rolling stock, which includes our rail-to-truck NGL terminals located in Florida, Nevada, New Jersey, New York, Rhode Island and Wyoming, our truck terminal located in Utah, and our truck maintenance facilities located in Indiana, Mississippi, New Jersey and Ohio; (ii) our West Coast processing and fractionation operations located in California; (iii) our Bath and Seymour NGL storage facilities located in New York and Indiana; and (iv) our crude oil and produced water transportation assets.

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

Basis of Presentation

Our consolidated financial statements are prepared in accordance with GAAP and include the accounts of all consolidated subsidiaries after the elimination of all intercompany accounts and transactions. Certain amounts in prior periods have been reclassified to conform to the current year presentation, none of which impacted our previously reported net income, earnings per unit or partners’ capital. 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.

In September 2015, Crestwood Midstream merged with a wholly-owned subsidiary of CEQP, with Crestwood Midstream surviving as a wholly-owned subsidiary of CEQP (the Simplification Merger), and CEQP contributed 100% of its interest in Crestwood Operations LLC (Crestwood Operations) to Crestwood Midstream. As a result of this transaction, Crestwood Midstream controls the operating and financial decisions of Crestwood Operations. Crestwood Midstream accounted for this transaction as a reorganization of entities under common control and the accounting standards related to such transactions requires Crestwood Midstream to record the assets and liabilities of Crestwood Operations at CEQP’s carrying value and retroactively adjust Crestwood Midstream’s historical results to reflect the operations of Crestwood Operations as being acquired on June 19, 2013, the date in which Crestwood Midstream and Crestwood Operations came under common control. Prior to the Simplification Merger, Crestwood Equity consolidated the results of Crestwood Operations in its financial statements and as such, this transaction had no impact on its historical financial statements.

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Significant Accounting Policies

Principles of Consolidation

We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination to consolidate or apply the equity method of accounting to an entity can also require us to evaluate whether that entity is considered a variable interest entity (VIE). This evaluation, along with the determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions or activities of an entity and in the case of a VIE, are not the primary beneficiary. We use the cost method of accounting where we are unable to exert significant influence over the entity.

All of our consolidated entities and equity method investments are not VIEs except for our investment in Crestwood Permian Basin Holdings LLC (Crestwood Permian). In October 2016, Crestwood Infrastructure Holdings LLC (Crestwood Infrastructure), our wholly-owned subsidiary, and an affiliate of First Reserve formed a joint venture, Crestwood Permian, to fund and own the Nautilus gathering system and other potential investments in the Delaware Permian. Crestwood Permian is a VIE because it did not have sufficient equity at risk to fund its activities at its inception (i.e., the construction of the Nautilus gathering system) without additional capital contributions from us and First Reserve, and CEQP has provided a guarantee to a third party that requires CEQP to fund 100% of the costs to build the Nautilus gathering system (which is currently estimated to cost approximately $180 million) if Crestwood Permian fails to do so. We account for our investment in Crestwood Permian as an equity method investment because we are not the primary beneficiary of the VIE as of December 31, 2017 and 2016. See Note 6 for a further discussion of our investment in Crestwood Permian.

On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico Pipeline LLC (Crestwood New Mexico), our wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New Mexico. This contribution was treated as a transaction between entities under common control (because of our relationship with First Reserve), and accordingly we deconsolidated Crestwood New Mexico and our investment in Crestwood Permian was increased by the historical book value of these assets of approximately $69.4 million. Crestwood New Mexico was previously included in our G&P segment. The deconsolidation of Crestwood New Mexico was not material to our consolidated financial statements as of and for the year ended December 31, 2017.

On June 3, 2016, our wholly-owned subsidiary, Crestwood Pipeline and Storage Northeast LLC (Crestwood Northeast) and Con Edison Gas Pipeline and Storage Northeast, LLC (CEGP), a wholly-owned subsidiary of Consolidated Edison, Inc. (Consolidated Edison), formed the Stagecoach Gas Services LLC (Stagecoach Gas) joint venture, to own and further develop our natural gas storage and transportation business located in the Northeast (the NE S&T assets). We contributed to the joint venture the entities owning the NE S&T assets, CEGP contributed $975 million in exchange for a 50% equity interest in Stagecoach Gas, and Stagecoach Gas distributed to us the net cash proceeds received from CEGP. The assets contributed to the joint venture were previously included in our S&T segment.

We deconsolidated the NE S&T assets as a result of the contribution of these assets to Stagecoach Gas and began accounting for our 50% equity interest in Stagecoach Gas under the equity method of accounting. The deconsolidation of our NE S&T assets resulted in a decrease of $1,127.6 million in property, plant and equipment, net, $8.5 million of intangible assets, net and $11.2 million of other assets and (liabilities), net. For a discussion of the decrease in goodwill associated with this joint venture transaction, see “Goodwill” below. See Note 6 for a further discussion of our investment in Stagecoach Gas.

Use of Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these consolidated financial statements. Actual results can differ from those estimates.

Cash

We consider all highly liquid investments with an original maturity of less than three months to be cash.

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Inventory

Inventory for our marketing, supply and logistics operations are stated at the lower of cost or market and cost is computed predominantly using the average cost method. Our inventory consists primarily of crude oil and NGLs of approximately $67.9 million and $56.7 million at December 31, 2017 and 2016.

Property, Plant and Equipment

Property, plant and equipment is recorded at is original cost of construction or, upon acquisition, at the fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and interest. We capitalize major units of property replacements or improvement and expense minor items. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Gathering systems and pipelines	15 - 20
Facilities and equipment	3 - 25
Buildings, rights-of-way and easements	1 - 40
Office furniture and fixtures	5 - 10
Vehicles	5

We depleted salt deposits included in our property, plant and equipment utilizing the unit of production method prior to their sale in December 2017.

We evaluate our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset, which is typically based on discounted cash flow projections using assumptions as to revenues, costs and discount rates typical of third party market participants, which is a Level 3 fair value measurement.

During 2017 and 2015, we recorded the following impairments of our property, plant and equipment and we reflected these impairments in loss on long-lived assets in our consolidated statements of operations. We did not record impairments of our property, plant and equipment during the year ended December 31, 2016.

• During 2017, we incurred $81.4 million of impairments of our property, plant and equipment related to our MS&L West Coast operations, which resulted from decreasing the forecasted cash flows to be generated by those operations. The fair value of our property, plant and equipment related to our West Coast operation was $66.4 million as of December 31, 2017. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future.

• During 2015, we incurred $8.5 million of impairments of our property, plant and equipment related to our Granite Wash gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our major customer of those assets declared bankruptcy and ceased substantial drilling in the Granite Wash in the near future given current and future anticipated market conditions related to natural gas and NGLs.

• During 2015, Crestwood Equity incurred a $354.4 million impairment of its property, plant and equipment related to its Barnett gathering and processing operations, which resulted from the actions of our primary customer in the Barnett Shale, Quicksilver Resources, Inc. (Quicksilver), related to its filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015. Crestwood Midstream did not record an impairment of its property, plant and equipment related to its gathering and processing assets in the Barnett Shale as the sum of the undiscounted cash flows expected to result from the use of the assets and their eventual disposition exceeded the carrying value of the property, plant and

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equipment by over 30%. As a result, Crestwood Midstream’s property, plant and equipment exceeds Crestwood Equity’s property, plant and equipment related to its gathering and processing assets in the Barnett Shale.

• During 2015, we incurred $61.9 million and $45.7 million of impairments of property, plant and equipment related to our Fayetteville and Haynesville gathering and processing operations, respectively, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas.

• During 2015, we incurred a $31.2 million impairment of our property, plant and equipment related to our Watkins Glen development project in our marketing, supply and logistics operations, which resulted from continued delays and uncertainties in the permitting of our proposed NGL storage facility.

At December 31, 2017, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 12% discount rate and projected cash flows, which is a Level 3 fair value measurement. At December 31, 2015, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 15% discount rate and projected cash flows, which is a Level 3 fair value measurement. Projected cash flows of our property, plant and equipment are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, constructions costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Identifiable Intangible Assets

Our identifiable intangible assets consist of customer accounts, covenants not to compete, trademarks and certain revenue contracts. Customer accounts, covenants not to compete, trademarks and certain of our revenue contracts have arisen from acquisitions. We amortize certain of our revenue contracts based on the projected cash flows associated with these contracts if the projected cash flows are readily determinable, otherwise we amortize our revenue contracts on a straight-line basis.  We recognize acquired intangible assets separately if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

During 2017, 2016 and 2015, we recorded the following impairments of our intangible assets and we reflected these impairments in loss on long-lived assets in our consolidated statements of operations:

• During 2017, we fully impaired $0.8 million of intangible assets related to our MS&L West Coast operations, which resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future.

• During 2016, we incurred a $31.4 million impairment of intangible assets related to our MS&L Trucking operations, which resulted from the impact of increased competition on our Trucking business and the loss of several key customer relationships that were acquired in 2013 to which the intangible assets related.

• During 2015, Crestwood Equity fully impaired $238.9 million of its intangible assets related to its Barnett gathering and processing operations, which resulted from the actions of our primary customer in the Barnett Shale, Quicksilver, related to filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015.

• During 2015, we fully impaired $70.9 million and $6.0 million of intangible assets related to our Fayetteville and Haynesville gathering and processing operations, respectively, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas.

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At December 31, 2016, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 19% discount rate and projected cash flows, which is a Level 3 fair value measurement. At December 31, 2015, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 15% discount rate and projected cash flows, which is a Level 3 fair value measurement. Projected cash flows of our intangible assets are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:

	Weighted-Average Life (years)
Customer accounts and revenue contracts	20
Trademarks	6 - 8

Assets Held for Sale

We classify assets (or groups of assets) to be disposed of as held for sale when specific criteria have been met. Assets classified as held for sale are recorded at the lower of the carrying value or the estimated fair value less cost to sell of those assets. The fair value is based on the consideration to be received, which is a Level 3 fair value measurement. We cease depreciation and amortization of the assets in the period they are considered held for sale. We classified approximately $3.0 million of property, plant and equipment related to our Marcellus gathering and processing assets as assets held for sale (which is included in prepaid expenses and other current assets) on our consolidated balance sheet at their fair value at December 31, 2017. In addition, we recorded a loss on long-lived assets of approximately $2.5 million during the year ended December 31, 2017 related to these assets. The sale is contingent upon customary approvals and satisfaction of certain other closing conditions, which we believe is probable at December 31, 2017.

Goodwill

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

We estimate the fair value of our reporting units based on a number of factors, including discount rates, projected cash flows and the potential value we would receive if we sold the reporting unit. We also compare the total fair value of our reporting units to our overall enterprise value, which considers the market value for our common and preferred units. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our reporting units (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our customers, such as their future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. If the assumptions embodied in the projections prove inaccurate, we could incur a future impairment charge. In addition, the use of the income approach to determine the fair value of our reporting units (see further discussion of the use of the income approach below) could result in a different fair value if we had utilized a market approach, or a combination thereof.

We acquired substantially all of our reporting units in 2013, 2012 and 2011, which required us to record the assets, liabilities and goodwill of each of those reporting units at fair value on the date they were acquired. As a result, any level of decrease in the forecasted cash flows of these businesses or increases in the discount rates utilized to value those businesses from their respective acquisition dates would likely result in the fair value of the reporting unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill is impaired.

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Current commodity prices are significantly lower compared to commodity prices during 2014, and that decrease has adversely impacted forecasted cash flows, discount rates and stock/unit prices for most companies in the midstream industry, including us. As a result, we recorded goodwill impairments on several of our reporting units during 2017, 2016 and 2015. At December 31, 2017, our accumulated goodwill impairments at CEQP and CMLP were approximately $1,656.5 million and $1,399.3 million, respectively. During 2017, we adopted the provisions of ASU 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which allows companies to apply a single test to determine if goodwill is impaired and the amount of any impairment, which is reflected in our 2017 goodwill impairments. The following table summarizes the goodwill of our various reporting units (in millions):

	Goodwill Impairments during the Year Ended December 31, 2015		Goodwill at January 1, 2016		Goodwill Impairments during the Year Ended December 31, 2016		Other				Goodwill at December 31, 2016		Impact of Sale of US Salt				Goodwill Impairments during the Year Ended December 31, 2017		Goodwill at December 31, 2017
G&P
Fayetteville	$	72.5	$	—	$	—	$	—			$	—	$	—			$	—	$	—
Marcellus	—		8.6		8.6		—				—		—				—		—
Arrow	—		45.9		—		—				45.9		—				—		45.9
S&T
Northeast Storage and Transportation	—		726.3		—		(726.3		)	(1)	—		—				—		—
COLT	623.4		44.9		44.9		—				—		—				—		—
MS&L																			—
West Coast	85.9		—		—		2.4			(2)	2.4		—				2.4		—
Supply and Logistics	99.0		167.2		65.5		—				101.7		—				—		101.7
Storage and Terminals	53.7		50.5		14.1		—				36.4		—				36.4		—
US Salt	—		12.6		—		—				12.6		(12.6		)	(3)	—		—
Trucking	148.4		29.5		29.5		—				—		—				—		—
Watkins Glen	66.2		—		—		—				—		—				—		—
Total CMLP	$	1,149.1	$	1,085.5	$	162.6	$	(723.9	)		$	199.0	$	(12.6	)		$	38.8	$	147.6
Barnett (G&P)	257.2		—		—		—				—		—				—		—
Total CEQP	$	1,406.3	$	1,085.5	$	162.6	$	(723.9	)		$	199.0	$	(12.6	)		$	38.8	$	147.6

(1) Reflects impact of the deconsolidation of our NE S&T assets in June 2016.

(2) In December 2016, we acquired four NGL terminals for our MS&L segment for approximately $7.2 million with total goodwill of approximately $2.4 million. This acquisition was not material to our consolidated financial statements as of and for the year ended December 31, 2016.

(3) In December 2017, we sold 100% of our equity interests in US Salt to an affiliate of Kissner Group Holdings LP.

The goodwill impairments recorded during 2017 related to our MS&L West Coast and Storage and Terminals operations. The goodwill impairment related to our MS&L West Coast operations resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for gathering, processing and logistics services from our West Coast operations to remain relatively flat over the past several years. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. The goodwill impairment related to our MS&L Storage and Terminals operations resulted from decreasing forecasted cash flows to be generated by those operations. During 2017, we experienced NGL market headwinds in the Northeast with NGL exports and other market dynamics causing price differentials to narrow between purchasing NGLs in the summer (which are then stored in our NGL facilities) and selling NGLs in the winter. These dynamics also caused the rates that we are able to charge for storing NGLs in our facilities to decline from their historical levels. Although our MS&L Storage and Terminals operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the decrease that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. We utilized the income approach to determine the fair value of our reporting units given the limited availability of comparable market-

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based transactions during 2017, and we utilized discount rates ranging from 10% to 12% in applying the income approach to determine the fair value of our reporting units with goodwill as of December 31, 2017, which is a Level 3 fair value measurement.

The goodwill impairments recorded during 2016 related to our G&P Marcellus operations, our MS&L Supply and Logistics and Storage and Terminals operations, our S&T COLT operations and our MS&L Trucking operations. The 2016 goodwill impairments on our Marcellus, Supply and Logistics, and Storage and Terminals operations primarily resulted from increasing the discount rates utilized in determining the fair value of those reporting units considering the significant decrease in the market price of our common units during the first quarter of 2016 and the continued decrease in commodity prices and its impact on the midstream industry and our customers. The 2016 goodwill impairments on our COLT and Trucking operations also resulted from those factors, but in addition they were impacted by (i) the expiration of two key crude-by-rail loading contracts during the fourth quarter of 2016, and the impact of those expirations on our projected future cash flows from our COLT operations; and (ii) the continued impact of increased competition on our Trucking business, a change in management in late 2016, and the planned downsizing of the excess capacity in our trucking fleet and operations and the impact that these had on our projected future cash flows from our Trucking operations. Although certain of these operations experienced increases in their operating results from 2013 to 2016, we decreased the cash flow forecasts for those businesses from the expectations when they were acquired in 2012 and 2013 based on our current assessment of the impact that the prolonged low commodity price environment is expected to have on demand for future services provided by those operations. We utilized the income approach to determine the fair value of our reporting units given the limited availability of comparable market-based transactions during 2016, and we utilized discount rates ranging from 10% to 19% in applying the income approach to determine the fair value of our reporting units with goodwill as of December 31, 2016, which is a Level 3 fair value measurement.

The goodwill impairments recorded during 2015 primarily resulted from decreasing forecasted cash flows and increasing the discount rates utilized in determining the fair value of the reporting units considering the continued decrease in commodity prices and its impact on the midstream industry and our customers. We utilized the income approach to determine the fair value of our reporting units given the limited availability of comparable market-based transactions during 2015, and we utilized discount rates ranging from 9% to 12% in 2015 in applying the income approach to determine the fair value of our reporting units with goodwill as of December 31, 2015.

In addition to the goodwill impairments recorded by Crestwood Midstream as reflected in the table above, Crestwood Equity recorded a goodwill impairment of its Barnett reporting unit of approximately $257.2 million in 2015. The impairment primarily resulted from increasing the discount rate utilized in determining the fair value of the reporting unit, considering the actions of its primary customer in the Barnett Shale during 2015, Quicksilver, related to its filing for protection under Chapter 11 of the U.S. Bankruptcy Code in March 2015.

Investment in Unconsolidated Affiliates

Equity method investments in which we exercise significant influence, but do not control and are not the primary beneficiary, are accounted for using the equity method of accounting. Differences in the basis of investments and the separate net asset values of the investees, if any, are amortized into net income or loss over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill. We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, or if we decide to sell an investment in unconsolidated affiliate, we adjust the carrying values of the asset downward, if necessary, to their estimated fair values.

During 2015, we recorded a $51.4 million and $23.4 million impairment of our Jackalope Gas Gathering Services, L.L.C. (Jackalope) and Powder River Basin Industrial Complex, LLC (PRBIC) equity method investments, respectively, as a result of decreasing forecasted cash flows and increasing the discount rates utilized in determining the fair value of the equity method investments considering the continued decrease in commodity prices and its impact on the midstream industry and our equity method investments’ customers, which is a Level 3 fair value measurement. We did not record impairments of our equity method investments during the years ended December 31, 2017 and 2016.

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We estimated the fair value of our equity method investments at December 31, 2015 based on projected cash flows, a 15.5% discount rate and the potential value we would receive if we sold the equity method investment. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our equity method investments (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our equity method investments’ customers, such as future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Asset Retirement Obligations

An asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. We record a liability for legal or contractual obligations to retire our long-lived assets associated with our facilities and right-of-way contracts we hold. We record a liability in the period the obligation is incurred and estimable. An ARO is initially recorded at its estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the fair value of the liability as a result of the passage of time, which we record as depreciation, amortization and accretion expense on our consolidated statements of operations. The fair value of certain AROs could not be determined as the settlement dates (or range of dates) associated with these assets were not estimable. At December 31, 2017 and 2016, our AROs were reflected in other long-term liabilities on our consolidated balance sheets. See Note 5 for a further discussion of our AROs.

Deferred Financing Costs

Deferred financing costs represent costs associated with obtaining long-term financing and are amortized over the term of the

related debt using a method which approximates the effective interest method and has a weighted average life of five years. At December 31, 2017 and 2016, our net deferred financing costs were reflected as a reduction of long-term debt on our consolidated balance sheets.

Revenue Recognition

We gather, process, treat, compress, store, transport and sell various commodities (including crude oil, natural gas, NGLs and water) pursuant to fixed-fee and percent-of-proceeds contracts. Under certain of those contracts in our G&P operations and our MS&L operations, we take title to the underlying commodity. We classify the revenues associated with the products to which we take title as product revenues and all other revenues as service revenues in our consolidated statement of operations.

We recognize revenues for these services and products when all of the following criteria are met:

• services have been rendered or products delivered or sold;

• persuasive evidence of an exchange arrangement exists;

• the price for services is fixed or determinable; and

• collectability is reasonably assured.

We record deferred revenue when we receive amounts from our customers but have not met the criteria listed above. We recognize deferred revenue in our consolidated statements of operations when the criteria has been met and all services have been rendered. At December 31, 2017 and 2016, we had deferred revenue of approximately $0.6 million and $7.5 million, which is reflected in accrued expenses and other liabilities on our consolidated balance sheets.

Credit Risk and Concentrations

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.

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Income Taxes

Crestwood Equity is a master limited partnership and Crestwood Midstream is a limited partnership. Partnerships are generally not subject to federal income tax, although publicly-traded partnerships are treated as corporations for federal income tax purposes and therefore are subject to federal income tax, unless the partnership generates at least 90% of its gross income from qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a partnership for federal income tax purposes. We satisfy the qualifying income requirement and are treated as a partnership for federal and state income tax purposes. Our consolidated earnings are included in the federal and state income tax returns of our partners. However, legislation in certain states allows for taxation of partnerships, and as such, certain state taxes have been included in our accompanying financial statements as income taxes due to the nature of the tax in those particular states as discussed below. In addition, federal and state income taxes are provided on the earnings of the subsidiaries incorporated as taxable entities. We are required to recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax basis of assets and liabilities using expected rates in effect for the year in which the differences are expected to reverse.

We are responsible for the Texas Margin tax computed on the Texas franchise tax returns. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Environmental Costs and Other Contingencies

We recognize liabilities for environmental and other contingencies when there is an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of range is accrued.

We record liabilities for environmental contingencies at their undiscounted amounts on our consolidated balance sheets as accrued expenses and other liabilities when environmental assessments indicate that remediation efforts are probable and costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors. These estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and recognize a current period charge in operations and maintenance expenses when clean-up efforts do not benefit future periods.

We evaluate potential recoveries of amounts from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet.

Price Risk Management Activities

We utilize certain derivative financial instruments to (i) manage our exposure to commodity price risk, specifically, the related change in the fair value of inventory, as well as the variability of cash flows related to forecasted transactions; (ii) ensure the availability of adequate physical supply of commodity; and (iii) manage our exposure to the interest rate risk associated with fixed and variable rate borrowings. We record all derivative instruments on the balance sheet at their fair values as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded through current earnings.

We did not have any derivatives identified as fair value hedges or cash flow hedges for accounting purposes during the years ended December 31, 2017, 2016 or 2015.

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Unit-Based Compensation

Long-term incentive awards are granted under the Crestwood Equity incentive plan. Unit-based compensation awards consist of restricted units that are valued at the closing market price of CEQP’s common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. We generally recognize the expense associated with the award over the vesting period on a straight line basis. Effective January 1, 2017, we adopted the provisions of ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of the accounting for share-based payment award transactions, including the classification of awards as either equity or liabilities and the presentation on the statement of cash flows. The adoption of this accounting standard did not have a material impact on our consolidated financial statements.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2017, the following accounting standards had not yet been adopted by us:

Revenue. In May 2014, the FASB issued ASU 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 utilized the modified retrospective method to adopt the provisions of this standard effective January 1, 2018. Upon adoption of the standard we began classifying certain capital expenditure reimbursements from our customers as deferred revenue rather than as reductions of property, plant and equipment in our consolidated financial statements.  We reclassified approximately $69.1 million of these net reimbursements to net deferred revenue on January 1, 2018, which primarily resulted in approximately $20.0 million cumulative effect of accounting change being recorded as an increase to partners' capital on January 1, 2018.  In addition, the standard requires us to begin classifying service revenues on certain of our gathering and processing contracts as reductions of costs of product sold prospectively beginning January 1, 2018.

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revises the accounting for leases by requiring certain leases to be recognized as assets and liabilities on the balance sheet, and requiring companies to disclose additional information about their leasing arrangements. We expect to adopt the provisions of this standard effective January 1, 2019 and are currently evaluating the impact that this standard will have on our consolidated financial statements.

Cash Flows. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain cash receipts and cash payments are presented and classified in the statement of cash flows. We adopted the provisions of this standard effective January 1, 2018, and the adoption of this standard did not have a material impact on our consolidated financial statements.

Note 3 – Divestiture

In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP, for net proceeds of approximately $223.6 million. The sale of US Salt resulted in a decrease of $157.4 million of property, plant and equipment, net, $12.6 million of goodwill, $5.8 million of intangible assets and $14.2 million of other assets and liabilities, net. During the year ended December 31, 2017, we recognized a gain of approximately $33.6 million from the sale, which was included in gain (loss) on long-lived assets in our consolidated statement of operations. As part of the US Salt divestiture, we retained all surface and sub-surface rights necessary to place the Watkins Glen NGL storage development project into service once we receive all required regulatory approvals. US Salt was previously included in our MS&L segment.

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Note 4 – Certain Balance Sheet Information

Property, Plant and Equipment

Property, plant and equipment of the following at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Gathering systems and pipelines and related assets	$	678.0	$	639.4	$	820.9	$	782.3
Facilities and equipment	1,141.4		1,328.3		1,326.5		1,513.4
Buildings, land, rights-of-way, storage rights and easements	319.1		315.4		322.8		319.1
Vehicles	37.3		45.7		35.5		44.0
Construction in process	87.5		85.9		87.5		85.9
Salt deposits	—		120.5		—		120.5
Office furniture and fixtures	21.9		20.2		22.1		20.3
	2,285.2		2,555.4		2,615.3		2,885.5
Less: accumulated depreciation and depletion	464.4		457.8		607.8		587.1
Total property, plant and equipment, net	$	1,820.8	$	2,097.6	$	2,007.5	$	2,298.4

Depreciation. CEQP’s depreciation expense totaled $135.9 million, $154.8 million and $195.1 million for the years ended December 31, 2017, 2016 and 2015. CMLP’s depreciation expense totaled $150.0 million, $168.9 million and $186.7 million for the years ended December 31, 2017, 2016 and 2015. Depletion expense at both CEQP and CMLP totaled $0.7 million for each of the years ended December 31, 2017, 2016 and 2015.

Capitalized Interest. During the years ended December 31, 2017, 2016 and 2015, CEQP and CMLP capitalized interest of $2.9 million, $0.7 million and $2.5 million related to certain expansion projects.

Gain (Loss) on Long-Lived Assets. During the year ended December 31, 2017, we recorded a gain of approximately $33.6 million on the sale of our 100% interest in US Salt. In addition, we recorded a loss of approximately $14.4 million during the year ended December 31, 2017, related to the retirement and/or disposition of certain of our Marcellus and Arrow gathering and processing assets.

Intangible Assets

Intangible assets consisted of the following at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Customer accounts	$	438.9	$	541.9	$	438.9	$	541.9
Covenants not to compete	—		1.0		—		1.0
Gas gathering, compression and processing contracts	325.2		325.2		325.2		325.2
Trademarks	24.7		30.5		9.2		15.0
	788.8		898.6		773.3		883.1
Less: accumulated amortization	191.6		241.2		177.6		230.2
Total intangible assets, net	$	597.2	$	657.4	$	595.7	$	652.9

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The following table summarizes total accumulated amortization of our intangible assets at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Customer accounts	$	89.8	$	162.4	$	89.8	$	162.4
Gas gathering, compression and processing contracts	82.0		63.2		82.0		63.2
Trademarks	19.8		15.6		5.8		4.6
Total accumulated amortization	$	191.6	$	241.2	$	177.6	$	230.2

Crestwood Equity’s amortization expense related to its intangible assets for the years ended December 31, 2017, 2016 and 2015, was approximately $53.7 million, $72.5 million and $102.8 million. Crestwood Midstream’s amortization expense related to its intangible assets for the years ended December 31, 2017, 2016 and 2015 was approximately $50.6 million, $69.3 million and $89.6 million.

Estimated amortization of our intangible assets for the next five years is as follows (in millions):

	CEQP		CMLP
Year Ending December 31,
2018	$	43.4	$	42.0
2019	41.7		41.7
2020	41.7		41.7
2021	41.7		41.7
2022	41.7		41.7

Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Accrued expenses	$	56.6	$	46.5	$	55.5	$	45.1
Accrued property taxes	4.8		4.2		4.8		4.2
Accrued natural gas purchases	—		4.9		—		4.9
Income tax payable	0.3		1.6		0.3		0.4
Interest payable	20.3		22.8		20.3		22.8
Accrued additions to property, plant and equipment	22.3		1.7		22.2		1.7
Capital leases	1.0		1.3		1.0		1.3
Deferred revenue	0.6		7.5		0.6		7.5
Total accrued expenses and other liabilities	$	105.9	$	90.5	$	104.7	$	87.9

Note 5 - Asset Retirement Obligations

We have legal obligations associated with our facilities and right-of-way contracts we hold. Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations.

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The following table presents the changes in the net asset retirement obligations for the years ended December 31, 2017 and 2016 (in millions):

	December 31,
	2017			2016
Net asset retirement obligation at January 1	$	27.8		$	26.4
Liabilities incurred	—			1.0
Liabilities settled	(1.2		)	(1.2		)
Accretion expense	1.4			1.6
Change in estimate	(0.5		)	—
Net asset retirement obligation at December 31	$	27.5		$	27.8

We did not have any material assets that were legally restricted for use in settling asset retirement obligations as of December 31, 2017 and 2016.

Note 6 - Investments in Unconsolidated Affiliates

Net Investments and Earnings (Loss)

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

	Ownership Percentage			Investment					Earnings (Loss) from Unconsolidated Affiliates
	December 31,			December 31,					Year Ended December 31,
	2017			2017		2016			2017		2016				2015
Stagecoach Gas Services LLC	50.00	%		$	849.8	$	871.0		$	25.3	$	15.9			$	—
Jackalope Gas Gathering Services, L.L.C.	50.00	%	(1)	184.9		197.2			10.5		20.8				(43.4		)	(3)
Crestwood Permian Basin Holdings LLC	50.00	%		102.0		(0.5		)	8.4		(0.5		)		—
Tres Palacios Holdings LLC	50.01	%		37.8		39.0			2.2		(0.3		)		2.5
Powder River Basin Industrial Complex, LLC(2)	50.01	%		8.5		8.7			1.4		(4.4		)	(3)	(19.9		)	(3)
Total				$	1,183.0	$	1,115.4		$	47.8	$	31.5			$	(60.8	)

(1) Excludes non-controlling interest related to our investment in Jackalope. See Note 12 for a further discussion of our non-controlling interest related to our investment in Jackalope.

(2) During the year ended December 31, 2015, we recorded additional equity earnings of approximately $3.2 million related to a gain associated with the adjustment of our member’s capital account by our equity investee.

(3) During the year ended December 31, 2016, we recorded a reduction of our equity earnings from PRBIC of approximately $5.8 million related to impairments recorded by our equity investee. During the year ended December 31, 2015, we recorded impairments of our PRBIC and Jackalope equity investments of approximately $23.4 million and $51.4 million. For a further discussion of these impairments, see Note 2.

Description of Investments

Crestwood Permian Basin Holdings LLC

In October 2016, Crestwood Infrastructure, our wholly-owned subsidiary, and an affiliate of First Reserve formed a joint venture, Crestwood Permian, to fund and own the Nautilus gathering system (described below) and other potential investments in the Delaware Permian. As part of this transaction, we transferred to the Crestwood Permian joint venture 100% of the equity interest of Crestwood Permian Basin LLC (Crestwood Permian Basin), which owns the Nautilus gathering system. We manage and account for our 50% ownership interest in Crestwood Permian, which is a VIE, under the equity method of accounting as we exercise significant influence, but do not control Crestwood Permian and we are not its primary beneficiary due to First Reserve’s rights to exercise control over the entity.

Crestwood Permian Basin has a long-term agreement with SWEPI LP (SWEPI), a subsidiary of Royal Dutch Shell plc, to construct, own and operate a natural gas gathering system (the Nautilus gathering system) in SWEPI’s operated position in the

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Delaware Permian. SWEPI has dedicated to Crestwood Permian Basin approximately 100,000 acres and gathering rights for SWEPI’s gas production across a large acreage position in Loving, Reeves and Ward Counties, Texas. Crestwood Permian Basin provides gathering, dehydration, compression and liquids handling services to SWEPI on a fixed-fee basis. In conjunction with the Crestwood Permian Basin’s agreement with SWEPI, Crestwood Permian granted Shell Midstream Partners L.P. (Shell Midstream), a subsidiary of Royal Dutch Shell plc, an option to purchase up to 50% equity interest in Crestwood Permian Basin. In October 2017, Shell Midstream exercised its option and purchased a 50% equity interest in Crestwood Permian Basin from Crestwood Permian for approximately $37.9 million in cash. Crestwood Permian distributed to us approximately $18.9 million of the cash proceeds received.

CEQP issued a guarantee in conjunction with the Crestwood Permian Basin gas gathering agreement with SWEPI described above, under which CEQP has agreed to fund 100% of the costs to build the Nautilus gathering system (which is currently estimated to cost $180 million, of which approximately $84.3 million has been spent through December 31, 2017) if Crestwood Permian fails to do so. We do not believe this guarantee is probable of resulting in future losses based on our assessment of the nature of the guarantee, the financial condition of the guaranteed party and the period of time that the guarantee has been outstanding, and as a result, we have not recorded a liability on our balance sheet at December 31, 2017 and 2016.

On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico, our wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New Mexico. This contribution was treated as a transaction between entities under common control (because of our relationship with First Reserve), and accordingly we deconsolidated Crestwood New Mexico and our investment in Crestwood Permian was increased by the historical book value of these assets of approximately $69.4 million. In conjunction with this contribution, First Reserve has agreed to contribute to Crestwood Permian the first $151 million of capital costs required to fund the expansion of the Delaware Basin assets, which includes a new processing plant located in Orla, Texas and associated pipelines (Orla processing plant).

Stagecoach Gas Services LLC

On June 3, 2016, Crestwood Northeast and CEGP formed Stagecoach Gas to own and further develop our NE S&T assets. During 2016, we contributed to Stagecoach Gas the entities owning the NE S&T assets. Additionally, CEGP contributed $975 million to Stagecoach Gas in exchange for a 50% equity interest in Stagecoach Gas, and Stagecoach Gas distributed to us the cash proceeds received (net of approximately $3 million of cash transferred to the joint venture) from CEGP. We deconsolidated the NE S&T assets as a result of this transaction discussed above and began accounting for our 50% equity interest in Stagecoach Gas under the equity method of accounting. We recognized a loss of approximately $32.4 million on the deconsolidation of the NE S&T assets.

Pursuant to the Stagecoach Gas limited liability company agreement, we may be required to make payments of up to $57 million to CEGP after December 31, 2020 if certain criteria are not met by Stagecoach Gas by December 31, 2020, including achieving certain performance targets on growth capital projects. These growth capital projects depend on the construction of other third-party expansion projects, and during 2017, those third-party projects experienced regulatory and other delays that caused Stagecoach Gas to delay its growth capital projects. Although Stagecoach Gas anticipates that these growth capital projects will be constructed in the future, it does not expect that these projects will produce meaningful operating results prior to December 31, 2020. As a result, at December 31, 2017, we recorded a liability of $57 million for this obligation, which is reflected in other long-term liabilities on our consolidated balance sheet and in loss on contingent consideration in our consolidated income statement for the year ended December 31, 2017.

Jackalope Gas Gathering Services, L.L.C.

Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, owns a 50% ownership interest in Jackalope which we account for under the equity method of accounting. Williams Partners LP operates and owns the remaining 50% interest in Jackalope. Crestwood Niobrara manages the commercial operations of the Jackalope system.

Tres Palacios Holdings LLC

Crestwood Midstream owns a 50.01% ownership interest in Tres Palacios Holdings LLC (Tres Holdings) and is the operator of Tres Palacios Gas Storage LLC (Tres Palacios) and its assets. Brookfield Infrastructure Group owns the remaining 49.99% ownership interest in Tres Holdings. We account for our investment in Tres Holdings under the equity method of accounting.

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Powder River Basin Industrial Complex, LLC

Crestwood Crude Logistics LLC (Crude Logistics), our consolidated subsidiary, owns a 50% ownership interest in PRBIC which we account for under the equity method of accounting. Twin Eagle Powder River Basin, LLC owns the remaining 50% ownership interest in PRBIC.

Summarized Financial Information of Unconsolidated Affiliates

Below is summarized financial information for our significant unconsolidated affiliates (in millions; amounts represent 100% of unconsolidated affiliate information):

Financial Position Data

	December 31,
	2017										2016
	Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity		Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity
Stagecoach(1)	$	55.1	$	1,765.4	$	7.0	$	1.4	$	1,812.1	$	57.0	$	1,807.6	$	6.0	$	4.1	$	1,854.5
Other(2)(3)	81.3		801.1		53.4		93.6		735.4		50.4		708.5		23.2		74.4		661.3
Total	$	136.4	$	2,566.5	$	60.4	$	95.0	$	2,547.5	$	107.4	$	2,516.1	$	29.2	$	78.5	$	2,515.8

(1) As of December 31, 2017, our equity in the underlying net assets of Stagecoach Gas exceeded our investment balance by approximately $51.4 million. This excess amount is entirely attributable to goodwill and, as such, is not subject to amortization. Our Stagecoach Gas investment is included in our storage and transportation segment.

(2) Includes our Jackalope, Tres Holdings, PRBIC and Crestwood Permian investments. As of December 31, 2017, our equity in the underlying net assets of Jackalope, Tres Holdings, PRBIC and Crestwood Permian exceeded our investment balance by approximately $0.7 million, $26.5 million, $6.4 million and $11.6 million, respectively. Our Tres Holdings and PRBIC investments are included in our storage and transportation segment and our Jackalope and Crestwood Permian investments are included in our gathering and processing segment.

(3) On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico. This contribution was treated as a transaction between entities under common control (because of our relationship with First Reserve) and the accounting standards related to such transactions requires Crestwood Permian to record the assets and liabilities of Crestwood New Mexico at our historical book value. The difference between our equity in Crestwood New Mexico’s net assets and our investment balance is not subject to amortization.

Operating Results Data

	Year Ended December 31,
	2017						2016						2015
	Operating Revenues		Operating Expenses		Net  Income		Operating Revenues		Operating Expenses		Net  Income		Operating Revenues		Operating Expenses		Net  Income
Stagecoach	$	168.6	$	77.7	$	91.1	$	99.3	$	44.1	$	55.3	$	—	$	—	$	—
Other(1)	181.8		143.6		38.9		127.6		113.9		13.5		104.7		79.5		24.9
Total	$	350.4	$	221.3	$	130.0	$	226.9	$	158.0	$	68.8	$	104.7	$	79.5	$	24.9

(1) Includes our Jackalope, Tres Holdings, PRBIC and Crestwood Permian equity investments. We amortize the excess basis in certain of our equity investments as an increase in our earnings from unconsolidated affiliates. We recorded amortization of the excess basis in our Jackalope equity investment of less than $0.1 million for both the years ended December 31, 2017 and 2016, and $3.0 million for the year ended December 31, 2015, which we amortize over the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake). We recorded amortization of the excess basis in our Tres Holdings equity investment of approximately $1.3 million for each of the years ended December 31, 2017, 2016 and 2015, which we amortize over the life of Tres Palacios’ sublease agreement. We recorded amortization of the excess basis in our PRBIC equity investment of approximately $0.6 million and $1.6 million for the years ended December 31, 2017 and 2016, which we amortize over the life of PRBIC’s property, plant and equipment and its agreement with Chesapeake.

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Distributions and Contributions

	Distributions						Contributions
	Year Ended December 31,						Year Ended December 31,
	2017		2016		2015		2017		2016		2015
Stagecoach Gas	$	47.3	$	16.0	$	—	$	0.8	$	—	$	—
Jackalope(1)	26.3		27.4		12.5		3.5		1.4		25.4
Tres Holdings(2)	9.0		8.5		7.4		5.6		11.0		5.7
PRBIC(1)	1.6		2.0		1.9		—		—		10.7
Crestwood Permian(3)	23.4		—		—		117.5		—		—
Total	$	107.6	$	53.9	$	21.8	$	127.4	$	12.4	$	41.8

(1) Jackalope and PRBIC are required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. We

received a cash distribution of $7.4 million from Jackalope in January 2018, and we received a cash distribution of $0.3 million from PRBIC in February

2018.

(2) 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.

(3) On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico at our historical book value of

approximately $69.4 million. This contribution was treated as a non-cash transaction between entities under common control.

Stagecoach Gas. Stagecoach Gas is required, within 30 days following the end of each quarter, to distribute 65% and 35% of its available cash (as defined in its limited liability company agreement) to CEGP and us, respectively. Because our ownership and distribution percentages differ, we determine the equity earnings from Stagecoach Gas using the Hypothetical Liquidation at Book Value (HLBV) method. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that we would receive if Stagecoach Gas were to liquidate all of its assets, as valued in accordance with GAAP, and distribute that cash to the members. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is our share of the earnings or losses from the equity investment for the period, which approximates how earnings are allocated under the terms of the limited liability company agreement. In January 2018, we received a cash distribution from Stagecoach Gas of approximately $11.3 million.

Crestwood Permian. Crestwood Permian is required, within 30 days following the end of each quarter to distribute 100% of its available cash (as defined in its limited liability company agreement) to its members based on their respective ownership percentages. Pursuant to Crestwood Permian's limited liability company agreement, we will receive 100% of Crestwood New Mexico's available cash (as defined in the limited liability company agreement) until the earlier of the Orla processing plant in-service date or June 30, 2018, at which time the distributions will be based on the members respective ownership percentages. Because our ownership and distribution percentages will differ during this period, equity earnings from Crestwood Permian is determined using the HLBV method. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that we would receive if Crestwood Permian were to liquidate all of its assets, as valued in accordance with GAAP, and distribute that cash to the members. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is our share of the earnings or losses from the equity investment for the period, which approximates how earnings are allocated under the terms of the limited liability company agreement. In January 2018, we received a cash distribution from Crestwood Permian of approximately $4.3 million.

Note 7 – Risk Management

We are exposed to certain market risks related to our ongoing business operations. These risks include exposure to changing commodity prices. We utilize derivative instruments to manage our exposure to fluctuations in commodity prices, which is discussed below. Additional information related to our derivatives is discussed in Note 2 and Note 8.

Commodity Derivative Instruments and Price Risk Management

Risk Management Activities

We sell NGLs and crude oil 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 periodically enter into offsetting positions

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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 years ended December 31, 2017, 2016 and 2015, the impact to our consolidated statements of operations related to our commodity-based derivatives reflected in costs of product/services sold was a loss of $31.2 million, a loss of $7.8 million and a gain of $18.9 million, respectively. 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:

	December 31, 2017		December 31, 2016
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (MMBbls)	15.3	17.5	13.1	15.1
Natural gas (MMcf)	780	660	—	—

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 34 months or less; however, 88% of the contracted volumes will be delivered or settled 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 our price risk management activities are 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 credit-risk-related contingent features that were in a liability position at December 31, 2017 and 2016, was $28.9 million and $13.9 million. At December 31, 2017 and 2016, we posted less than $0.1 million of collateral for our commodity derivative instruments with credit-risk-related contingent features. In addition, at December 31, 2017 and 2016, we had a New York Mercantile Exchange (NYMEX) related net derivative asset position of $27.2 million and $14.3 million, for which we posted $5.6 million and $4.2 million of cash collateral in the normal course of business. At December 31, 2017 and 2016, we also received collateral of $3.7 million and $4.3 million in the normal course of business. All collateral amounts have been netted against the asset or liability with the respective counterparty and are reflected in our consolidated balance sheets as assets and liabilities from price risk management activities.

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Note 8 – 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, Accounts Receivable and Accounts Payable

As of December 31, 2017 and 2016, the carrying amounts of cash, accounts receivable and accounts payable approximate fair value based on the short-term nature of these instruments.

Credit Facility

The fair value of the amounts outstanding under our CMLP credit facility approximates the carrying amounts as of December 31, 2017 and 2016, due primarily to the variable nature of the interest rate of the instrument, 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 (reduced for deferred financing costs associated with the respective notes) and fair value of our senior notes (in millions):

	December 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2020 Senior Notes	$	—	$	—	$	340.6	$	350.2
2022 Senior Notes	$	—	$	—	$	429.3	$	447.3
2023 Senior Notes	$	692.1	$	728.8	$	690.6	$	722.6
2025 Senior Notes	$	492.3	$	517.9	$	—	$	—

Financial Assets and Liabilities

As of December 31, 2017 and 2016, 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, and NGLs. Our derivative instruments consist of forwards, swaps, futures, physical exchanges and options.

Our derivative instruments that are traded on the NYMEX have been categorized as Level 1.

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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 financial instruments that were accounted for at fair value on a recurring basis at December 31, 2017 and 2016 (in millions):

	December 31, 2017
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Recorded in Balance Sheet
Assets
Assets from price risk management	$	1.1	$	102.2	$	—	$	103.3	$	(74.6	)	$	(21.5	)	$	7.2
Suburban Propane Partners, L.P. units(2)	3.5		—		—		3.5		—			—			3.5
Total assets at fair value	$	4.6	$	102.2	$	—	$	106.8	$	(74.6	)	$	(21.5	)	$	10.7
Liabilities
Liabilities from price risk management	$	1.4	$	118.2	$	—	$	119.6	$	(74.6	)	$	3.9		$	48.9
Total liabilities at fair value	$	1.4	$	118.2	$	—	$	119.6	$	(74.6	)	$	3.9		$	48.9
	December 31, 2016
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Recorded in Balance Sheet
Assets
Assets from price risk management	$	0.6	$	84.4	$	—	$	85.0	$	(67.8	)	$	(10.9	)	$	6.3
Suburban Propane Partners, L.P. units(2)	4.3		—		—		4.3		—			—			4.3
Total assets at fair value	$	4.9	$	84.4	$	—	$	89.3	$	(67.8	)	$	(10.9	)	$	10.6
Liabilities
Liabilities from price risk management	$	2.7	$	90.2	$	—	$	92.9	$	(67.8	)	$	3.5		$	28.6
Total liabilities at fair value	$	2.7	$	90.2	$	—	$	92.9	$	(67.8	)	$	3.5		$	28.6

(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) Amount is reflected in other assets on CEQP’s consolidated balance sheets.

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Note 9 – Long-Term Debt

Long-term debt consisted of the following at December 31, 2017 and 2016, (in millions):

	December 31,
	2017		2016
Credit Facility	$	318.2	$	77.0
2020 Senior Notes	—		338.8
Fair value adjustment of 2020 Senior Notes	—		1.8
2022 Senior Notes	—		436.4
2023 Senior Notes	700.0		700.0
2025 Senior Notes	500.0		—
Other	2.4		3.7
Less: deferred financing costs, net	28.4		34.0
Total debt	1,492.2		1,523.7
Less: current portion	0.9		1.0
Total long-term debt, less current portion	$	1,491.3	$	1,522.7

Credit Facility

Crestwood Midstream’s amended and restated senior secured credit agreement (the CMLP Credit Agreement) provides for a five-year $1.5 billion revolving credit facility (the CMLP Credit Facility), which expires in September 2020 and is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The CMLP Credit Facility allows Crestwood Midstream to increase its available borrowings under the facility by $350.0 million, subject to lender approval and the satisfaction of certain other conditions, as described in the CMLP Credit Agreement. The CMLP Credit Facility also includes a sub-limit of up to $25.0 million for same-day swing line advances and a sub-limit up to $350.0 million for letters of credit. Subject to limited exception, the CMLP Credit Facility is guaranteed and secured by substantially all of the equity interests and assets of Crestwood Midstream’s subsidiaries, except for Crestwood Niobrara, Crestwood Infrastructure, PRBIC, Crestwood Northeast and Tres Holdings and their respective subsidiaries. The Company also guarantees Crestwood Midstream’s payment obligations under its $1.5 billion credit agreement.

Prior to amending and restating its credit agreement in September 2015, Crestwood Midstream had a five-year $1.0 billion senior secured revolving credit facility, which would have expired October 2018. In conjunction with the closing of the Simplification Merger, Crestwood Midstream borrowed approximately $720.0 million under the CMLP Credit Facility on September 30, 2015 to (i) repay all borrowings outstanding under the $1.0 billion credit facility; (ii) fund a distribution to the Company of approximately $378.3 million for purposes of repaying (or, if applicable, satisfying and discharging) substantially all of the Company’s outstanding indebtedness as discussed above; and (iii) pay merger-related fees and expenses. We recognized a loss on extinguishment of debt of approximately $1.8 million for the year ended December 31, 2015 in conjunction with amending and restating the CMLP Credit Agreement.

Borrowings under the CMLP Credit Facility (other than the swing line loans) bear interest at either:

• the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) Wells Fargo Bank’s prime rate; or (iii) the Eurodollar Rate adjusted for certain reserve requirements plus 1%; plus a margin varying from 0.75% to 1.75% depending on Crestwood Midstream’s most recent consolidated total leverage ratio; or

• the Eurodollar Rate, adjusted for certain reserve requirements plus a margin varying from 1.75% to 2.75% depending on Crestwood Midstream’s most recent consolidated total leverage ratio.

Swing line loans bear interest at the Alternate Base Rate as described above. The unused portion of the CMLP Credit Facility is subject to a commitment fee ranging from 0.30% to 0.50% according to its most recent consolidated total leverage ratio. Interest on the Alternate Base Rate loans is payable quarterly, or if the adjusted Eurodollar Rate applies, interest is payable at certain intervals selected by Crestwood Midstream.

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At December 31, 2017, Crestwood Midstream had $499.3 million of available capacity under its credit facility considering the most restrictive covenants in its credit agreement. At December 31, 2017 and 2016, Crestwood Midstream’s outstanding standby letters of credit were $52.2 million and $64.0 million. Interest rates under the CMLP Credit Facility were between 3.94% and 6.00% at December 31, 2017 and 3.21% and 5.25% at December 31, 2016. The weighted-average interest rate on outstanding borrowings as of December 31, 2017 and 2016 was 4.11% and 3.23%.

The CMLP Credit Facility contains various covenants and restrictive provisions that limit our ability to, among other things, (i) incur additional debt; (ii) make distributions on or redeem or repurchase units; (iii) make certain investments and acquisitions; (iv) incur or permit certain liens to exist; (v) merge, consolidate or amalgamate with another company; (vi) transfer or dispose of assets; and (vii) incur a change in control at either Crestwood Equity or Crestwood Midstream, including an acquisition of Crestwood Holdings’ ownership of Crestwood Equity’s general partner by any third party, including Crestwood Holdings’ debtors under an event of default of their debt since Crestwood Equity’s non-economic general partner interest is pledged as collateral under that debt.

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 5.50 to 1.0, a consolidated EBITDA to consolidated interest expense ratio (as defined in its credit agreement) of not less than 2.50 to 1.0, and a senior secured leverage ratio (as defined in its credit agreement) of not more than 3.75 to 1.0. At December 31, 2017, the net debt to consolidated EBITDA was approximately 4.14 to 1.0, the consolidated EBITDA to consolidated interest expense was approximately 4.14 to 1.0, and the senior secured leverage ratio was 0.86 to 1.0.

If Crestwood Midstream fails to perform its obligations under these and other covenants, the lenders’ credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the CMLP Credit Facility could be declared immediately due and payable. The CMLP Credit Facility also has cross default provisions that apply to any of its other material indebtedness.

Senior Notes

2020 Senior Notes. The 6.0% Senior Notes due 2020 (the 2020 Senior Notes) were scheduled to mature on December 15, 2020, and interest was payable semi-annually in arrears on June 15 and December 15 of each year. The fair value adjustment was being amortized over the remaining life of the 2020 Senior Notes.

2022 Senior Notes. The 6.125% Senior Notes due 2022 (the 2022 Senior Notes) were scheduled to mature on March 1, 2022, and interest was payable semi-annually on March 1 and September 1 of each year.

2023 Senior Notes. The 6.25% Senior Notes due 2023 (the 2023 Senior Notes) mature on April 1, 2023, and interest is payable semi-annually in arrears on April 1 and October 1 of each year.

In March 2016, Crestwood Midstream filed a registration statement with the SEC under which it offered to exchange the 2023 Senior Notes for any and all outstanding 2023 Senior Notes. Crestwood Midstream completed the exchange offer in July 2016. The terms of the exchange notes are substantially identical to the terms of the 2023 Senior Notes, except that the exchange notes are freely tradable.

2025 Senior Notes. In March 2017, Crestwood Midstream issued $500 million of 5.75% unsecured senior notes due 2025 (the 2025 Senior Notes) in a private offering. The 2025 Senior Notes will mature on April 1, 2025, and interest is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2017. The net proceeds from this offering of approximately $492 million were used to repay amounts outstanding under the 2020 Senior Notes and the 2022 Senior Notes as discussed below.

In May 2017, Crestwood Midstream filed a registration statement with the SEC under which is offered to exchange new senior notes for any and all outstanding 2025 Senior Notes. Crestwood Midstream completed the exchange offer in July 2017. The terms of the exchange notes are substantially identical to the terms of the 2025 Senior Notes, except that the exchange noted are freely tradable.

In general, each series of Crestwood Midstream’s senior notes are fully and unconditionally guaranteed, joint and severally, on a senior unsecured basis by Crestwood Midstream’s domestic restricted subsidiaries (other than Finance Corp., which has no assets). The indentures contain customary release provisions, such as (i) disposition of all or substantially all the assets of, or the capital stock of, a guarantor subsidiary to a third person if the disposition complies with the indentures; (ii) designation of a

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guarantor subsidiary as an unrestricted subsidiary in accordance with its indentures; (iii) legal or covenant defeasance of a series of senior notes, or satisfaction and discharge of the related indenture; and (iv) guarantor subsidiary ceases to guarantee any other indebtedness of Crestwood Midstream or any other guarantor subsidiary, provided it no longer guarantees indebtedness under the CMLP Credit Facility.

The indentures restricts the ability of Crestwood Midstream and its restricted subsidiaries to, among other things, sell assets; redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; create or incur certain liens; enter into agreements that restrict distributions or other payments to Crestwood Midstream from its restricted subsidiaries; consolidate, merge or transfer all or substantially all of their assets; engage in affiliate transactions; create unrestricted subsidiaries; and incur a change in control at either Crestwood Equity or Crestwood Midstream, including an acquisition of Crestwood Holdings’ ownership of Crestwood Equity’s general partner by any third party including Crestwood Holdings’ debtors under an event of default of their debt since Crestwood Equity’s non-economic general partner interest is pledged as collateral under that debt. These restrictions are subject to a number of exceptions and qualifications, and many of these restrictions will terminate when the senior notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Rating Services and no default or event of default (each as defined in the respective indentures) under the indentures has occurred and is continuing.

At December 31, 2017, Crestwood Midstream was in compliance with the debt covenants and restrictions in each of its credit agreements discussed above.

Crestwood Midstream’s Credit Facility and its respective senior notes are secured by its assets and liabilities of the guarantor subsidiaries. Accordingly, such assets are only available to the creditors of Crestwood Midstream. Crestwood Equity had restricted net assets of approximately $2,195.4 million as of December 31, 2017.

Repayments.During the year ended December 31, 2017, Crestwood Midstream paid approximately $349.9 million and $457.8 million to purchase, redeem and/or cancel all of the principal amount outstanding under the 2020 Senior Notes and 2022 Senior Notes, respectively. Crestwood Midstream funded the repayments with a combination of net proceeds from the issuance of the 2025 Senior Notes described above and borrowings under the credit facility. In conjunction with these note repayments, Crestwood Midstream (i) recognized a loss on extinguishment of debt of approximately $37.7 million during the year ended December 31, 2017 (including the write off of approximately $6.8 million of deferred financing costs associated with the 2022 Senior Notes); and (ii) paid $5.1 million and $1.0 million of accrued interest on the 2020 Senior Notes and 2022 Senior Notes, respectively, on the date they were tendered.

In June 2016, Crestwood Midstream paid approximately $312.9 million to purchase and cancel approximately $161.2 million and $163.6 million of the principal amount outstanding under the 2020 Senior Notes and 2022 Senior Notes, respectively, utilizing a portion of the proceeds received from Stagecoach Gas, as further discussed in Notes 2 and 6. During the year ended December 31, 2016, Crestwood Midstream recognized a gain on extinguishment of debt of approximately $10.0 million in conjunction with the early tender of these notes. Crestwood Midstream also paid $4.5 million and $2.6 million of accrued interest on the 2020 Senior Notes and 2022 Senior Notes, respectively, on the date they were tendered.

In April 2015, we retired our $350 million7.75% Senior Notes due 2019 for approximately $364.1 million, including accrued interest of $0.5 million and a call premium of $13.6 million. In conjunction with the redemption of these notes, we recorded a loss on extinguishment of debt of approximately $17.1 million during the year ended December 31, 2015.

Other Obligations

Our non-interest bearing obligations due under noncompetition agreements consist of agreements between Crestwood Midstream and sellers of certain companies acquired in 2014 with payments due through 2022 and imputed interest ranging from 5.02% to 6.75%. Non-interest bearing obligations consisted of $2.7 million and $4.2 million in total payments due under agreements, less unamortized discount based on imputed interest of $0.3 million and $0.5 million at December 31, 2017 and 2016, respectively.

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Maturities

The aggregate maturities of principal amounts on our outstanding long-term debt and other notes payable as of December 31, 2017 for the next five years and in total thereafter are as follows (in millions):

2018	$	0.9
2019	0.9
2020	318.4
2021	0.2
2022	0.2
Thereafter	1,200.0
Total debt	$	1,520.6

Residual Value Guarantee

In 2012, Crestwood Equity entered into a support agreement with Suburban Propane Partners, L.P. (SPH) pursuant to which Crestwood Equity is obligated to provide contingent, residual support of approximately $497 million of aggregate principal amount of the 7.5% senior unsecured notes due 2018 of SPH and Suburban Energy Finance Corp. (collectively, the SPH Issuers) or any permitted refinancing thereof. Under the support agreement, in the event the SPH Issuers fail to pay any principal amount of the supported debt when due, Crestwood Equity will pay the holders of the supported debt, or the SPH Issuers for the benefit of the holders of the supported debt, an amount up to the principal amount of the supported debt that the SPH Issuers have failed to pay. Crestwood Equity has no obligation to make a payment under the support agreement with respect to any accrued and unpaid interest or any redemption premium or other costs, fees, expenses, penalties, charges or other amounts of any kind that shall be due to the noteholders by the SPH Issuers, whether on or related to the supported debt or otherwise. The support agreement terminates on the earlier of the date the supported debt is extinguished or on the maturity date of supported debt or any permitted refinancing thereof. We believe the probability of any future payment on this residual value guarantee is remote.

Note 10 - Earnings Per Limited Partner Unit

Our net income (loss) attributable to Crestwood Equity is allocated to the subordinated and limited partner unitholders based on their ownership percentage after giving effect to net income attributable to the preferred units. We calculate basic net income per limited partner unit using the two-class method. Diluted net income per limited partner unit is computed using the treasury stock method, which considers the impact to net income attributable to Crestwood Equity and limited partner units from the potential issuance of limited partner units.

We exclude potentially dilutive securities from the determination of diluted earnings per unit (as well as their related income statement impacts) when their impact on net income attributable to Crestwood Equity per limited partner unit is anti-dilutive. During the years ended December 31, 2017, 2016 and 2015, we excluded a weighted-average of 7,007,917, 6,433,127 and 1,547,060 common units (representing preferred units), a weighted-average of 438,789 common units in all periods (representing subordinated units), and a weighted-average of 7,146,663, 7,548,624 and 2,760,794 common units (representing Crestwood Niobrara’s preferred units). See Note 12 for additional information regarding the potential conversion of our preferred units and Crestwood Niobrara’s preferred units to common units.

CEQP Reverse Split. On October 22, 2015, the board of directors of CEQP’s general partner approved a 1-for-10 reverse split on our common units, effective after the market closed on November 23, 2015. The units began trading on a split-adjusted basis on November 24, 2015. Pursuant to the reverse split, common unit holders received one common unit for every 10 common units owned with substantially the same terms and conditions of the common units prior to the reverse split.

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Note 11 - Income Taxes

The (provision) benefit for income taxes for the years ended December 31, 2017, 2016, and 2015 consisted of the following (in millions):

	CEQP									CMLP
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017 (1)		2016			2015
Current:
Federal	$	(1.1	)	$	(3.2	)	$	(1.6	)	$	—	$	—		$	—
State	(0.2		)	(0.2		)	(0.6		)	—		0.2			(0.3		)
Total current	(1.3		)	(3.4		)	(2.2		)	—		0.2			(0.3		)
Deferred:
Federal	2.1			3.0			2.9			—		—			—
State	—			0.1			0.7			—		(0.2		)	0.3
Total deferred	2.1			3.1			3.6			—		(0.2		)	0.3
(Provision) benefit for income taxes	$	0.8		$	(0.3	)	$	1.4		$	—	$	—		$	—

(1) For the year ended December 31, 2017, our benefit for income taxes was not material to CMLP’s consolidated statement of operations.

The effective rate differs from the statutory rate for the years ended December 31, 2017, 2016 and 2015, primarily due to the partnerships not being treated as a corporation for federal income tax purposes as discussed in Note 2.

Deferred income taxes related to CEQP’s wholly owned subsidiaries, IPCH Acquisition Corp., and Crestwood Gas Services GP LLC and our Texas Margin tax reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. For the year ended December 31, 2017, we decreased our net deferred tax liability by $1.3 million to reflect the reduction of corporate tax rates under the Tax Cuts and Jobs Act.

Components of our deferred income taxes at December 31, 2017 and 2016 are as follows (in millions).

	CEQP						CMLP
	December 31,						December 31,
	2017			2016			2017			2016
Deferred tax asset:
Basis difference in stock of company	$	0.2		$	0.2		$	—		$	—
Total deferred tax asset	0.2			0.2			—			—
Deferred tax liability:
Basis difference in stock of acquired company	(3.5		)	(5.5		)	(0.7		)	(0.7		)
Total deferred tax liability	(3.5		)	(5.5		)	(0.7		)	(0.7		)
Net deferred tax liability	$	(3.3	)	$	(5.3	)	$	(0.7	)	$	(0.7	)

Uncertain Tax Positions. We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Such tax positions, if any, would be recorded as a tax benefit or expense in the current year. We believe that there were no uncertain tax positions that would impact our results of operations for the years ended December 31, 2017, 2016 and 2015 and that no provision for income tax was required for these consolidated financial statements. However, our conclusions regarding the evaluation of uncertain tax positions are subject to review and may change based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof.

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Note 12 – Partners’ Capital

Simplification Merger. As discussed in Note 1, on September 30, 2015, we completed the Simplification Merger. As part of the merger consideration, Crestwood Midstream’s common and preferred unitholders (other than Crestwood Equity and its subsidiaries) received 2.75 common or preferred units of CEQP for each common or preferred unit of CMLP held upon completion of the merger.

Prior to the Simplification Merger, CEQP indirectly owned a non-economic general partnership interest in Crestwood Midstream and 100% of its IDRs. Crestwood Midstream was also a publicly-traded limited partnership with common units listed on the NYSE. However, as a result of our completion of the Simplification Merger on September 30, 2015, Crestwood Midstream’s common units ceased to be listed on the NYSE, its IDRs were eliminated and Crestwood Midstream became a wholly-owned subsidiary of CEQP.

Preferred Units

Pursuant to Crestwood Midstream’s agreements with a group of investors, including Magnetar Financial, affiliates of GSO Capital Partners LP and GE Energy Financial Services (the Class A Purchasers), Crestwood Midstream agreed to sell to the Class A Purchasers and the Class A Purchasers agreed to purchase from Crestwood Midstream up to $500 million of Class A Preferred Units (CMLP Preferred Units) at a fixed price of $25.10 per unit on or before September 30, 2015. In August 2015, the Class A Purchasers acquired from Crestwood Midstream the remaining $60.0 million of CMLP Preferred Units for net proceeds of approximately $58.8 million after deducting transaction fees and offering expenses.

As discussed above, in conjunction with the closing of the Simplification Merger, 21,580,244 of CMLP Preferred Units were exchanged for 59,345,672 new preferred units of CEQP (the Preferred Units) with substantially similar terms and conditions to those of the CMLP Preferred Units and as a result, Crestwood Equity classified the new preferred units as a component of partners’ capital as of December 31, 2015. Because the fair value of the preferred units was materially equivalent immediately before and after the exchange, Crestwood Equity recorded CEQP’s preferred units at Crestwood Midstream’s historical book value.

Subject to certain conditions, the holders of the Preferred Units will have the right to convert Preferred Units into (i) common units on a 1-for-10 basis, or (ii) a number of common units determined pursuant to a conversion ratio set forth in our partnership agreement upon the occurrence of certain events, such as a change in control. The Preferred Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each Preferred Units entitled to one vote for each common unit into which such Preferred Unit is convertible, except that the Preferred Units are entitled to vote as a separate class on any matter on which all unit holders are entitled to vote that adversely affects the rights, powers, privileges or preferences of the Preferred Units in relation to CEQP’s other securities outstanding.

Common Units

On August 4, 2017, we entered into an equity distribution agreement with certain financial institutions (each, a Manager), under which we may offer and sell from time to time through one or more of the Managers, common units having an aggregate offering price of up to $250 million. Common units sold pursuant to this at-the-market (ATM) equity distribution program are issued under a registration statement that became effective on April 12, 2017. We will pay the Managers an aggregate fee of up to 2.0% (which totaled $0.3 million during the year ended December 31, 2017) of the gross sales price per common unit sold under our ATM equity distribution program. The table below shows the units issued and the net proceeds from the issuances:

Issuance Dates	Common Units	Net Proceeds(1) (in millions)
Third Quarter 2017	437,518	$	10.6
Fourth Quarter 2017	195,753	4.6
Total 2017	633,271	$	15.2

(1) The net proceeds from sales under the ATM program are used for general partnership purposes, which may include debt repayments and capital expenditures.

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Distributions

Crestwood Equity

Description. Crestwood Equity makes quarterly distributions to its partners within approximately 45 days after the end of each quarter in an aggregate amount equal to its available cash for such quarter. Available cash generally means, with respect to each quarter, all cash on hand at the end of the quarter less the amount of cash that the general partner determines in its reasonable discretion is necessary or appropriate to:

• provide for the proper conduct of its business;

• comply with applicable law, any of its debt instruments, or other agreements; or

• provide funds for distributions to unitholders for any one or more of the next four quarters;

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. The amount of cash CEQP has available for distribution depends primarily upon its cash flow (which consists of the cash distributions it receives in connection with its ownership of Crestwood Midstream).

Limited Partners. A summary of CEQP’s limited partner quarterly cash distributions for the years ended December 31, 2017, 2016 and 2015 is presented below:

Record Date	Payment Date	Per Unit Rate		Cash Distributions  (in millions)
2017
February 7, 2017	February 14, 2017	$	0.60	$	41.8
May 8, 2017	May 15, 2017	$	0.60	41.8
August 7, 2017	August 14, 2017	$	0.60	41.8
November 7, 2017	November 14, 2017	$	0.60	42.2
				$	167.6
2016
February 5, 2016	February 12, 2016	$	1.375	$	95.6
May 6, 2016	May 13, 2016	$	0.60	41.4
August 5, 2016	August 12, 2016	$	0.60	41.4
November 7, 2016	November 14, 2016	$	0.60	41.4
				$	219.8
2015
February 6, 2015	February 13, 2015	$	1.375	$	25.8
May 8, 2015	May 15, 2015	$	1.375	25.7
August 7, 2015	August 14, 2015	$	1.375	25.7
November 6, 2015	November 13, 2015	$	1.375	94.3
				$	171.5

On February 14, 2018, we paid a distribution of $0.60 per limited partner unit to unitholders of record on February 7, 2018 with respect to the fourth quarter of 2017.

Preferred Unit Holders. The holders of our Preferred Units are entitled to receive fixed quarterly distributions of $0.2111 per unit. Through the quarters ending September 30, 2017 (the Initial Distribution Period), distributions on the Preferred Units could be made in additional Preferred Units, cash, or a combination thereof, at our election. Through and for the quarter ended June 30, 2017, we paid distributions on our Preferred Units through the issuance of additional Preferred Units. The number of units distributed was calculated as the fixed quarterly distribution of $0.2111 per unit divided by the cash purchase price of $9.13 per unit. We accrued the fair value of such distribution at the end of the quarterly period and adjusted the fair value of the distribution on the date the additional Preferred Units were distributed. Distributions on the Preferred Units following the Initial Distribution Period will be paid in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units; and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to

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our Preferred Unit holders. If we fail to pay the full amount payable to our Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.2567 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if we fail to pay in full any Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

During the year ended December 31, 2017, 2016 and 2015, we issued 4,724,030, 5,815,170 and 1,372,573 Preferred Units to our preferred unit holders in lieu of paying quarterly cash distributions of $43.1 million, $53.0 million and $12.5 million. In November 2017, we made a cash distribution to our preferred unit holders of approximately $15.0 million for the quarter ended September 30, 2017. On February 14, 2018, we made a cash distribution of approximately $15.0 million to our preferred unit holders for the quarter ended December 31, 2017.

On June 9, 2016, Crestwood Equity filed a shelf registration statement with the SEC under which holders of the Preferred Units may sell the common units into which the Preferred Units are convertible. The registration statement became effective on June 15, 2016. Crestwood Equity registered 7,290,552 common units under the registration statement.

Crestwood Midstream

Description. Prior to the completion of the Simplification Merger, Crestwood Midstream’s partnership agreement required the partnership 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 applicable record date. The general partner was not entitled to distributions on its non-economic general partner interest.

In conjunction with the Simplification Merger, Crestwood Midstream amended and restated its partnership agreement. In accordance with the partnership agreement, Crestwood Midstream’s general partner may, from time to time, cause Crestwood Midstream to make cash distributions at the sole discretion of the general partner.

General Partner. During the year ended December 31, 2015, Crestwood Midstream paid cash distributions to its general partner (representing IDRs and distributions related to common units held by the general partner) of approximately $31.4 million.

On September 30, 2015, Crestwood Midstream made a distribution of approximately $378.3 million to CEQP for purposes of repaying substantially all of its outstanding indebtedness. The distribution was funded with borrowings under the CMLP Credit Facility. In addition, during the years ended December 31, 2017, 2016 and 2015, Crestwood Midstream made distributions of $174.0 million, $227.6 million and $175.6 million, which represented net amounts due to Crestwood Midstream related to cash advances to CEQP for its general corporate activities.

Limited Partners. The following table presents quarterly cash distributions paid to Crestwood Midstream’s limited partners (excluding distributions paid to its general partner on its common units held) during the year ended December 31, 2015.

Record Date	Payment Date	Per Unit Rate		Cash Distributions (in millions)
2015
February 6, 2015	February 13, 2015	$	0.41	$	74.3
May 8, 2015	May 15, 2015	$	0.41	74.3
August 7, 2015	August 14, 2015	$	0.41	74.3
				$	222.9

Class A Preferred Unit Holders. Prior to the Simplification Merger, Crestwood Midstream’s partnership agreement required Crestwood Midstream to make quarterly distributions to its Class A Preferred Unit holders. The holders of the Preferred Units were entitled to receive fixed quarterly distributions of $0.5804 per unit. For the 12 quarters following the quarter ended June 30, 2014 (the Initial Distribution Period), distributions on our Preferred Units could be made in additional Preferred Units, cash, or a combination thereof, at our election. If Crestwood Midstream elected to pay the quarterly distribution through the issuance of additional Preferred Units, the number of units to be distributed were calculated as the fixed quarterly distribution of $0.5804 per unit divided by the cash purchase price of $25.10 per unit. Crestwood Midstream accrued the fair value of such

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distribution at the end of the quarterly period and adjusted the fair value of the distribution on the date the additional Preferred Units are distributed.

Non-Controlling Partners

Crestwood Midstream Class A Preferred Units

As discussed above, prior to the Simplification Merger, Crestwood Equity classified the Crestwood Midstream Class A Preferred Units as a component of Interest of Non-Controlling Partners in its consolidated financial statements.

Crestwood Niobrara Preferred Interest

Crestwood Niobrara issued a preferred interest (Series A Preferred Units) 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. In December 2017, Crestwood Niobrara redeemed 100% of the outstanding Series A Preferred Units from GE for an aggregate purchase price of approximately $202.7 million and issued $175 million in new preferred interests (Series A-2 Preferred Units) to CN Jackalope Holdings LLC (Jackalope Holdings). In conjunction with the issuance of the Series A-2 Preferred Units, we entered into a Second Amended and Restated Limited Liability Company Agreement (Crestwood Niobrara Amended Agreement) with Crestwood Niobrara. Pursuant to the Crestwood Niobrara Amended Agreement, we serve as the managing member of Crestwood Niobrara and, subject to certain restrictions, we have the ability to redeem the Series A-2 Preferred Units for an amount in cash or CEQP common units equal to an amount necessary for Jackalope Holdings to achieve a certain rate of return. Also in conjunction with the Crestwood Niobrara Amended Agreement, we entered into a registration rights agreement with Jackalope Holdings. Pursuant to the registration rights agreement, we granted Jackalope Holdings certain rights with respect to CEQP’s common units issuable to Jackalope Holdings in certain circumstances as set forth in the Crestwood Niobrara Amended Agreement.

Net Income (Loss) Attributable to Non-Controlling Partners

The components of net income (loss) attributable to non-controlling partners for the years ended December 31, 2017, 2016 and 2015 are as follows (in millions):

	Year Ended December 31,
	2017		2016		2015
Crestwood Niobrara preferred interests	$	25.3	$	24.2	$	23.1
CMLP net income attributable to non-controlling partners	25.3		24.2		23.1
Crestwood Midstream limited partner interests	—		—		(683.0		)
Crestwood Midstream Class A preferred units	—		—		23.1
CEQP net income (loss) attributable to non-controlling partners	$	25.3	$	24.2	$	(636.8	)

Distributions to Non-Controlling Partners

Crestwood Midstream Limited Partners. Prior to the completion of the Simplification Merger, the Crestwood Midstream partnership agreement required it 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 applicable record date. Crestwood Equity was not entitled to distributions on its non-economic general partner interest in Crestwood Midstream. Crestwood Midstream paid cash distributions to its limited partners (excluding distributions to its general partner) of $222.9 million during the year ended December 31, 2015.

Crestwood Midstream Class A Preferred Unitholders. During the year ended December 31, 2015, Crestwood Midstream issued 1,271,935 Preferred Units to its preferred unitholders in lieu of paying a cash distribution of approximately $31.9 million.

Crestwood Niobrara Preferred Unitholders. Crestwood Niobrara is required to make quarterly distributions to GE within 30 days after the end of each quarter. Beginning with the distribution for 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 January 30, 2015, Crestwood Niobrara issued 3,680,570 preferred units to GE in lieu of paying a cash distribution for the quarter ended

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December 31, 2014. During the years ended December 31, 2017, 2016 and 2015, Crestwood Niobrara paid cash distributions of $15.2 million, $15.2 million and $11.3 million to GE.

Other Partners’ Capital Transactions

Subordinated Units

In conjunction with Crestwood Holdings’ acquisition of Crestwood Equity’s general partner, Crestwood Equity issued 438,789 subordinated units, which are considered limited partnership interests, and have the same rights and obligations as its common units, except that the subordinated units are entitled to receive distributions of available cash for a particular quarter only after each of our common units has received a distribution of at least $1.30 for that quarter.  The subordinated units convert to common units after (i) CEQP’s common units have received a cumulative distribution in excess of $5.20 during a consecutive four quarter period; and (ii) its Adjusted Operating Surplus (as defined in the agreement) exceeds the distribution on a fully dilutive basis.

Note 13 - Equity Plans

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

The following table summarizes information regarding restricted and phantom unit activity during the years ended December 31, 2017, 2016 and 2015.

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2015	131,588		$	132.10
Vested - restricted units	(91,798	)	$	121.13
Vested - phantom units	(4,856	)	$	67.10
Granted - restricted units	142,255		$	55.25
Granted - phantom units	42,349		$	62.31
Modification - restricted units	226,401		$	68.85
Modification - phantom units	41,269		$	58.36
Forfeited (1)	(20,994	)	$	89.97
Unvested - December 31, 2015	466,214		$	69.80
Vested - restricted units	(193,295	)	$	76.82
Granted - restricted units	1,067,535		$	14.58
Granted - phantom units	17,467		$	15.54
Forfeited	(65,591	)	$	25.13
Unvested - December 31, 2016	1,292,330		$	24.67
Vested - restricted units	(607,115	)	$	28.00
Vested - performance units	(31,106	)	$	30.27
Granted - restricted units	919,411		$	25.69
Granted - phantom units	15,849		$	25.02
Granted - performance units	405,620		$	30.21
Forfeited - restricted units	(140,137	)	$	23.73
Forfeited - performance units	(24,756	)	$	30.45
Unvested - December 31, 2017	1,830,096		$	25.21

(1) We implemented a company-wide initiative to reduce operating costs in 2015 and beyond, which included a reduction in workforce. As a result, 7,263 restricted units were forfeited during the year ended December 31, 2015.

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As of December 31, 2017 and 2016, we had total unamortized compensation expense of approximately $23.7 million and $14.9 million related to restricted, phantom, and performance units, which 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 $22.4 million, $16.0 million and $11.5 million under the Crestwood LTIP during the years ended December 31, 2017, 2016 and 2015, which is included in general and administrative expenses on our consolidated statements of operations.  As of February 12, 2018, we had 3,428,811 units available for issuance under the Crestwood LTIP.

Restricted Units. Under the Crestwood LTIP, participants who have been granted restricted units may elect to have 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 years ended December 31, 2017, 2016, and 2015 we withheld 206,600, 57,508 and 26,095 common units to satisfy employee tax withholding obligations.

Phantom Units. The Crestwood LTIP permits, grants of phantom units that entitle the holder thereof to receive upon vesting one CEQP common unit 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.

Performance Units. The Crestwood LTIP permits grants of performance units that are designed to provide an incentive for continuous employment to certain key employees. Performance units vest over a three-year performance period and the number of units issued are based on a performance multiplier ranging between 50% and 200%, determined based on the actual performance in the third year of the performance period compared to pre-established performance goals. The performance goals are based on achieving a specified level of distributable cash flow per unit, Adjusted EBITDA, return on capital invested, and three-year relative total shareholder return. The vesting of performance units is subject to the attainment of certain performance and market goals over a three year period and entitle a participant to receive common units of Crestwood Equity without payment of an exercise price upon vesting.

Note 14 - Employee Benefit Plan

A 401(k) plan is available to all of our employees after meeting certain requirements. The plan permits employees to make contributions up to 90% of their salary, up to statutory limits, which was $18,000 in 2017, 2016 and 2015. We match 100% of participants basic contribution up to 6% of eligible compensation. Employees may participate in the plans immediately and certain employees are not eligible for matching contributions until after a 90-day waiting period. Aggregate matching contributions made by us were $4.0 million, $3.8 million and $4.0 million during the years ended December 31, 2017, 2016 and 2015.

Note 15 – Commitments and Contingencies

Legal Proceedings

California Trucking Lawsuit. On March 13, 2017, a former Crestwood truck driver filed a lawsuit in the Superior Court for Kern County, California on behalf of all Crestwood Transportation LLC’s California drivers alleging that Crestwood Equity and its officers, directors and employees violated the California wage and hour laws by failing to comply with certain requirements of the laws. The plaintiffs currently include a total of 13 former and current Company drivers, however they are seeking to certify this lawsuit as a class action, which could potentially include approximately 150 drivers. Although our insurance policies would not cover this action, we believe we have meritorious defenses to this lawsuit and will vigorously defend ourselves. We are unable to predict the outcome or to estimate a reasonably possible loss or range of loss for this matter.

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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 December 31, 2017 and 2016, both CEQP and CMLP had approximately $2.1 million and less than $0.1 million accrued for outstanding legal matters. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures for which we can estimate will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.

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

Regulatory Compliance

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

Environmental Compliance

Our operations are subject to stringent and complex laws and regulations pertaining to worker health, safety, and the environment. We are subject to laws and regulations at the federal, state, regional 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 worker safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures.

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. Thereafter, we contained and cleaned up the releases, and placed the impacted segments of these water lines back into service. In May 2015, we experienced a release of approximately 5,200 barrels of produced water on our Arrow water gathering system, immediately notified numerous regulatory authorities and other third parties, and thereafter contained and cleaned up the releases. 

In October 2014, we received data requests from the EPA related to the 2014 water releases and we responded to the requests during the first half of 2015.  In April 2015, the EPA issued a Notice of Potential Violation (NOPV) under the Clean Water Act relating to the 2014 water releases. We responded to the NOPV in May 2015 and in April 2017, we entered into an Administrative Order on Consent (the Order) with the EPA. The Order requires us to continue to remediate and monitor the impacted area for no less than four years unless all goals of the Order are satisfied earlier. On December 13, 2017, the EPA and Crestwood signed a Combined Complaint and Consent Agreement (CCCA) whereby we agreed to pay a civil penalty of $49,000 to the EPA and purchase emergency response equipment at an estimated cost of approximately $173,000 for the Three Affiliated Tribes as a Supplemental Environmental Project (SEP). The CCCA and SEP concludes the EPA’s penalty phase related to this matter.

On March 3, 2015, we received a grand jury subpoena from the United States Attorney’s Office in Bismarck, North Dakota, seeking documents and information relating to the largest of the three 2014 water releases. We provided the requested information during the second quarter of 2015 and key employees were interviewed by the United States’ Attorney in December

2015. On September 13, 2017, we received a notice from the United States Department of Justice that it completed the

investigation with no charges being filed against us.

In August 2015, we received a notice of violation from the Three Affiliated Tribes’ Environmental Division related to our 2014 produced water releases on the Fort Berthold Indian Reservation. The notice of violation imposes fines and requests reimbursements exceeding $1.1 million; however, the notice of violation was stayed on September 15, 2015, upon our posting

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of a performance bond for the amount contemplated by the notice, and pending the outcome of settlement discussions with the EPA related to the NOPV. Our discussions regarding the notice of violation continue with the Three Affiliated Tribes.

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 December 31, 2017.

At December 31, 2017 and 2016, our accrual of approximately $1.9 million and $2.1 million is based on our undiscounted estimate of amounts we will spend on compliance with environmental and other regulations, and any associated fines or penalties. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures (including the Arrow water releases described above) could range from approximately $1.9 million to $3.1 million at December 31, 2017.

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. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Our self insurance reserves could be affected if future claim developments differ from the historical trends. We believe changes in health care costs, trends in health care claims of our employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. We continually monitor changes in employee demographics, incident and claim type and evaluate our insurance accruals and adjust our accruals based on our evaluation of these qualitative data points. We are liable for the development of claims for our disposed retail propane operations, provided they were reported prior to August 1, 2012. At December 31, 2017 and 2016, CEQP’s self-insurance reserves were $13.6 million and $15.6 million. We estimate that $9.1 million of this balance will be paid subsequent to December 31, 2018. As such, CEQP has classified $9.1 million in other long-term liabilities on its consolidated balance sheet at December 31, 2017. At December 31, 2017 and 2016, CMLP’s self-insurance reserves were $11.6 million and $12.2 million. CMLP estimates that $7.6 million of this balance will be paid subsequent to December 31, 2018. As such, CMLP has classified $7.6 million in other long-term liabilities on its consolidated balance sheet at December 31, 2017.

Commitments and Purchase Obligations

Operating Leases.We also maintain operating leases in the ordinary course of our business activities. These leases include those for office buildings, crude oil railroad cars and other operating facilities and equipment. The terms of the agreements vary from 2018 until 2032.

Future minimum lease payments under our noncancelable operating leases for the next five years ending December 31 and in total thereafter consist of the following (in millions):

Year Ending December 31,
2018	$	35.2
2019	30.1
2020	23.2
2021	11.5
2022	7.7
Thereafter	18.8
Total minimum lease payments	$	126.5

Our rent expense for operating leases for the years ended December 31, 2017, 2016 and 2015, totaled $34.2 million, $25.5 million and $37.4 million.

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Purchase Commitments. We periodically enter into agreements with suppliers to purchase fixed quantities of NGLs, distillates, crude oil and natural gas at fixed prices. At December 31, 2017, the total of these firm purchase commitments was $479.3 million, substantially all of which will occur over the course of the next twelve months. We also enter into non-binding agreements with suppliers to purchase quantities of NGLs, distillates and natural gas at variable prices at future dates at the then prevailing market prices.

We have entered into certain purchase commitments primarily related to our G&P segment. At December 31, 2017, our total purchase commitments were approximately $63.9 million, which primarily relate to future growth projects and maintenance obligations in our G&P segment. The purchases associated with these commitments are expected to occur over the next twelve months.

Guarantees and Indemnifications. We are involved in various joint ventures that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. For a further description of our guarantees associated with our joint ventures, see Note 6, and for a further description of our guarantees associated with our assets or businesses we have sold, see Note 9.

Our potential exposure under guarantee and indemnification arrangements can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim, specificity as to duration, and the particular transaction. As of December 31, 2017, we have no amounts accrued for these guarantees.

Note 16 – Related Party Transactions

Crestwood Holdings indirectly owns both CEQP’s and CMLP’s general partner. The affiliates of Crestwood Holdings and its owners are considered CEQP’s and CMLP’s related parties. 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. Below is a discussion of certain of our related party agreements.

Shared Services. CMLP shares common management, general and administrative and overhead costs with CEQP. CEQP grants long-term incentive awards under the Crestwood LTIP as discussed in Note 13. CEQP allocates a portion of its unit-based compensation costs to CMLP.

Stagecoach Gas Management Agreement. In May 2016, Crestwood Midstream Operations, LLC (Crestwood Midstream Operations), our wholly-owned subsidiary and Stagecoach Gas entered into a management agreement under which Crestwood Midstream Operations provides the management and operating services required by Stagecoach Gas’ facilities. The initial term of the agreement will expire in May 2021, and is automatically extended for three-year periods unless otherwise terminated pursuant to the terms of the agreement. Reimbursements charged to Stagecoach Gas under this agreement are reflected as operations and maintenance expenses charged by CEQP and CMLP in the table below.

Tres Palacios Operating Agreement. A consolidated subsidiary of Crestwood Midstream entered into an operating agreement with Tres Palacios, pursuant to which we assumed the responsibility of operating and maintaining the facilities as well as certain administrative and other general services identified in the agreement. Under the operating agreement, Tres Palacios reimburses us for all cost incurred on its behalf. These reimbursements are reflected as operations and maintenance expense charged by CEQP and CMLP in the table below.

Crestwood Permian Operating Agreement. In October 2016, Crestwood Midstream Operations entered into an operating agreement with Crestwood Permian, pursuant to which we provide operating services of Crestwood Permian’s facilities, as well as certain administrative and other general services identified in the agreement. Under this operating agreement, Crestwood Permian reimburses us for all costs incurred on its behalf. These reimbursements are reflected as operations and maintenance expense charged by CEQP and CMLP in the table below.

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The following table shows revenues, costs of product/services sold, general and administrative expenses and reimbursement of expenses from our affiliates for the years December 31, 2017, 2016 and 2015 (in millions):

	Year Ended December 31,
	2017			2016			2015
Gathering and processing revenues at CEQP and CMLP	$	1.8		$	2.6		$	3.9
Gathering and processing costs of product sold at CEQP and CMLP(1)	$	15.3		$	17.7		$	28.9
Operations and maintenance expenses charged at CEQP and CMLP(2)	$	22.3		$	8.1		$	3.3
General and administrative expenses charged by CEQP to CMLP, net(3)	$	19.4		$	13.0		$	49.5
General and administrative expenses at CEQP charged to (from) Crestwood Holdings, net(4)	$	(1.7	)	$	(2.2	)	$	0.4

(1)    Represents natural gas purchases from Sabine Oil and Gas, an affiliate of Crestwood Holdings.

(2) We have operating agreements with certain of our unconsolidated affiliates pursuant to which we charge them operations and maintenance expenses in accordance with their respective agreements. During the year ended December 31, 2017, we charged $8.4 million to Stagecoach Gas, $3.5 million to Tres Palacios, $10.0 million to Crestwood Permian and $0.4 million to Jackalope. During the year ended December 31, 2016, we charged $5.0 million to Stagecoach Gas, $2.7 million to Tres Palacios, and $0.4 million to Jackalope. During the year ended December 31, 2015, we charged $2.8 million to Tres Palacios and $0.5 million to Jackalope.

(3) Includes $22.4 million, $16.0 million and $10.0 million of net unit-based compensation charges allocated from CEQP to CMLP for the years ended December 31, 2017, 2016 and 2015. In addition, includes $3.0 million, $3.0 million and $0.8 million of CMLP’s general and administrative costs allocated to CEQP during the years ended December 31, 2017, 2016 and 2015.

(4) Includes $3.1 million, $3.2 million and $0.1 million unit-based compensation charges allocated from Crestwood Holdings to CEQP and CMLP during the years ended December 31, 2017, 2016 and 2015.

The following table shows accounts receivable and accounts payable from our affiliates as of December 31, 2017 and 2016 (in millions):

	December 31,
	2017		2016
Accounts receivable at CEQP and CMLP	$	7.1	$	5.6
Accounts payable at CEQP	$	7.4	$	2.5
Accounts payable at CMLP	$	5.0	$	—

Note 17 – Segments

Financial Information

We have three operating and reportable segments: (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) marketing, supply and logistics operations. Our corporate operations include all general and administrative expenses that are not allocated to our reportable segments. For a further description of our operating and reporting segments, see Note 1. We assess the performance of our operating segments based on EBITDA, which is defined as income before income taxes, plus debt-related costs (net interest and debt expense and gain or loss on modification/extinguishment of debt) and depreciation, amortization and accretion expense.

Below is a reconciliation of CEQP’s net loss to EBITDA (in millions):

	Year Ended December 31,
	2017			2016			2015
Net loss	$	(166.6	)	$	(192.1	)	$	(2,303.7	)
Add:
Interest and debt expense, net	99.4			125.1			140.1
(Gain) loss on modification/extinguishment of debt	37.7			(10.0		)	20.0
Provision (benefit) for income taxes	(0.8		)	0.3			(1.4		)
Depreciation, amortization and accretion	191.7			229.6			300.1
EBITDA	$	161.4		$	152.9		$	(1,844.9	)

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Below is a reconciliation of CMLP’s net loss to EBITDA (in millions):

	Year Ended December 31,
	2017			2016			2015
Net loss	$	(175.5	)	$	(197.5	)	$	(1,410.6	)
Add:
Interest and debt expense, net	99.4			125.1			130.5
(Gain) loss on modification/extinguishment of debt	37.7			(10.0		)	18.9
Depreciation, amortization and accretion	202.7			240.5			278.5
EBITDA	$	164.3		$	158.1		$	(982.7	)

The following tables summarize CEQP’s and CMLP’s reportable segment data for the years ended December 31, 2017, 2016 and 2015 (in millions). Intersegment revenues included in the following tables are accounted for as arms-length transactions that apply our revenue recognition policies described in Note 2. Included in earnings (loss) from unconsolidated affiliates below was approximately $32.5 million, $29.6 million and $86.1 million of depreciation and amortization expense and gains (losses) on long-lived assets, net related to our equity investments for the years ended December 31, 2017, 2016 and 2015, respectively.

Crestwood Equity

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			96.5			96.5
Loss on long-lived assets, net	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			0.5			1.3
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(99.0	)	$	161.4
Goodwill	$	45.9		$	—		$	101.7		$	—		$	147.6
Total assets	$	2,474.1		$	1,040.6		$	757.1		$	13.1		$	4,284.9
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

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	Year Ended December 31, 2016
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,118.8		$	165.3		$	1,236.4		$	—		$	2,520.5
Intersegment revenues	108.6			4.2			(112.8		)	—			—
Costs of product/services sold	917.0			5.1			1,003.0			—			1,925.1
Operations and maintenance expense	77.0			21.4			59.7			—			158.1
General and administrative expense	—			—			—			88.2			88.2
Loss on long-lived assets, net	(2.0		)	(32.2		)	(31.4		)	—			(65.6		)
Goodwill impairment	(8.6		)	(44.9		)	(109.1		)	—			(162.6		)
Earnings from unconsolidated affiliates, net	20.3			11.2			—			—			31.5
Other income, net	—			—			—			0.5			0.5
EBITDA	$	243.1		$	77.1		$	(79.6	)	$	(87.7	)	$	152.9
Goodwill	$	45.9		$	—		$	153.1		$	—		$	199.0
Total assets	$	2,359.7		$	1,094.6		$	972.2		$	22.4		$	4,448.9
Purchases of property, plant and equipment	$	76.6		$	3.3		$	19.1		$	1.7		$	100.7

	Year Ended December 31, 2015
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,381.0		$	266.3		$	985.5		$	—		$	2,632.8
Intersegment revenues	66.7			—			(66.7		)	—			—
Costs of product/services sold	1,103.9			20.1			759.5			—			1,883.5
Operations and maintenance expense	89.0			31.7			69.5			—			190.2
General and administrative expense	—			—			—			116.3			116.3
Loss on long-lived assets	(787.3		)	(1.6		)	(32.3		)	—			(821.2		)
Goodwill impairment	(329.7		)	(623.4		)	(453.2		)	—			(1,406.3		)
Loss from unconsolidated affiliates, net	(43.4		)	(17.4		)	—			—			(60.8		)
Other income, net	—			—			—			0.6			0.6
EBITDA	$	(905.6	)	$	(427.9	)	$	(395.7	)	$	(115.7	)	$	(1,844.9	)
Purchases of property, plant and equipment	$	132.7		$	26.4		$	22.8		$	0.8		$	182.7

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Crestwood Midstream

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			93.1			93.1
Loss on long-lived assets, net	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			—			0.8
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(96.1	)	$	164.3
Goodwill	$	45.9		$	—		$	101.7		$	—		$	147.6
Total assets	$	2,662.0		$	1,040.6		$	757.1		$	6.6		$	4,466.3
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

	Year Ended December 31, 2016
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,118.8		$	165.3		$	1,236.4		$	—		$	2,520.5
Intersegment revenues	108.6			4.2			(112.8		)	—			—
Costs of product/services sold	917.0			5.1			1,003.0			—			1,925.1
Operations and maintenance expense	77.0			18.3			59.7			—			155.0
General and administrative expense	—			—			—			85.6			85.6
Loss on long-lived assets, net	(2.0		)	(32.2		)	(31.4		)	—			(65.6		)
Goodwill impairment	(8.6		)	(44.9		)	(109.1		)	—			(162.6		)
Earnings from unconsolidated affiliates, net	20.3			11.2			—			—			31.5
EBITDA	$	243.1		$	80.2		$	(79.6	)	$	(85.6	)	$	158.1
Goodwill	$	45.9		$	—		$	153.1		$	—		$	199.0
Total assets	$	2,561.9		$	1,094.6		$	972.2		$	11.9		$	4,640.6
Purchases of property, plant and equipment	$	76.6		$	3.3		$	19.1		$	1.7		$	100.7

160

	Year Ended December 31, 2015
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,381.0		$	266.3		$	985.5		$	—		$	2,632.8
Intersegment revenues	66.7			—			(66.7		)	—			—
Costs of product/services sold	1,103.9			20.1			759.5			—			1,883.5
Operations and maintenance expense	89.0			30.2			69.5			—			188.7
General and administrative expense	—			—			—			105.6			105.6
Loss on long-lived assets, net	(194.1		)	(1.4		)	(32.3		)	—			(227.8		)
Goodwill impairment	(72.5		)	(623.4		)	(453.2		)	—			(1,149.1		)
Loss from unconsolidated affiliates, net	(43.4		)	(17.4		)	—			—			(60.8		)
EBITDA	$	(55.2	)	$	(426.2	)	$	(395.7	)	$	(105.6	)	$	(982.7	)
Purchases of property, plant and equipment	$	132.7		$	26.4		$	22.8		$	0.8		$	182.7

Major Customers

No customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2017, 2016 or 2015 at CEQP or CMLP.

Note 18 – Crestwood Midstream Condensed Consolidating Financial Information

Crestwood Midstream is a holding company (Parent) and owns no operating assets and has no significant operations independent of its subsidiaries. Obligations under Crestwood Midstream’s senior notes and its credit facility are jointly and severally guaranteed by substantially all of its subsidiaries, except for Crestwood Infrastructure, Crestwood Niobrara, Crestwood Northeast, PRBIC and Tres Holdings and their respective subsidiaries (collectively, Non-Guarantor Subsidiaries). Crestwood Midstream Finance Corp., the co-issuer of its senior notes, is Crestwood Midstream’s 100% owned subsidiary and has no material assets, operations, revenues or cash flows other than those related to its service as co-issuer of the Crestwood Midstream senior notes.

The tables below present condensed consolidating financial statements for Crestwood Midstream as Parent on a stand-alone, unconsolidated basis, and Crestwood Midstream’s combined guarantor and combined non-guarantor subsidiaries as of and for the years ended December 31, 2017, 2016 and 2015. 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.

161

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2017
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	1.0	$	—	$	—	$	—		$	1.0
Accounts receivable	—		439.7		2.9		—			442.6
Inventory	—		68.4		—		—			68.4
Other current assets	—		18.1		—		—			18.1
Total current assets	1.0		526.2		2.9		—			530.1
Property, plant and equipment, net	—		2,007.5		—		—			2,007.5
Goodwill and intangible assets, net	—		743.3		—		—			743.3
Investments in consolidated affiliates	3,705.4		—		—		(3,705.4		)	—
Investments in unconsolidated affiliates	—		—		1,183.0		—			1,183.0
Other assets	—		2.4		—		—			2.4
Total assets	$	3,706.4	$	3,279.4	$	1,185.9	$	(3,705.4	)	$	4,466.3
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	—	$	346.8	$	—	$	—		$	346.8
Other current liabilities	20.5		134.0		—		—			154.5
Total current liabilities	20.5		480.8		—		—			501.3
Long-term liabilities:
Long-term debt, less current portion	1,490.5		0.8		—		—			1,491.3
Other long-term liabilities	—		45.6		57.0		—			102.6
Deferred income taxes	—		0.7		—		—			0.7
Partners’ capital	2,195.4		2,751.5		953.9		(3,705.4		)	2,195.4
Interest of non-controlling partners in subsidiary	—		—		175.0		—			175.0
Total partners’ capital	2,195.4		2,751.5		1,128.9		(3,705.4		)	2,370.4
Total liabilities and partners’ capital	$	3,706.4	$	3,279.4	$	1,185.9	$	(3,705.4	)	$	4,466.3

162

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2016
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	1.3	$	—	$	—	$	—		$	1.3
Accounts receivable	—		289.3		0.5		—			289.8
Inventory	—		66.0		—		—			66.0
Other current assets	—		16.0		—		—			16.0
Total current assets	1.3		371.3		0.5		—			373.1
Property, plant and equipment, net	—		2,298.4		—		—			2,298.4
Goodwill and intangible assets, net	—		851.9		—		—			851.9
Investments in consolidated affiliates	4,093.7		—		—		(4,093.7		)	—
Investments in unconsolidated affiliates	—		—		1,115.4		—			1,115.4
Other assets	—		1.8		—		—			1.8
Total assets	$	4,095.0	$	3,523.4	$	1,115.9	$	(4,093.7	)	$	4,640.6
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	—	$	214.5	$	—	$	—		$	214.5
Other current liabilities	23.1		94.4		—		—			117.5
Total current liabilities	23.1		308.9		—		—			332.0
Long-term liabilities:
Long-term debt, less current portion	1,521.2		1.5		—		—			1,522.7
Other long-term liabilities	—		42.0		—		—			42.0
Deferred income taxes	—		0.7		—		—			0.7
Partners’ capital	2,550.7		3,170.3		923.4		(4,093.7		)	2,550.7
Interest of non-controlling partners in subsidiary	—		—		192.5		—			192.5
Total partners’ capital	2,550.7		3,170.3		1,115.9		(4,093.7		)	2,743.2
Total liabilities and partners’ capital	$	4,095.0	$	3,523.4	$	1,115.9	$	(4,093.7	)	$	4,640.6

163

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,880.9		$	—		$	—		$	3,880.9
Costs of product/services sold	—			3,374.7			—			—			3,374.7
Expenses:
Operations and maintenance	—			136.0			—			—			136.0
General and administrative	67.6			25.5			—			—			93.1
Depreciation, amortization and accretion	—			202.7			—			—			202.7
	67.6			364.2			—			—			431.8
Other operating expenses:
Gain on long-lived assets, net	—			(65.6		)	—			—			(65.6		)
Goodwill impairment	—			(38.8		)	—			—			(38.8		)
Loss on contingent consideration	—			—			(57.0		)	—			(57.0		)
Operating income (loss)	(67.6		)	37.6			(57.0		)	—			(87.0		)
Earnings from unconsolidated affiliates, net	—			—			47.8			—			47.8
Interest and debt expense, net	(99.4		)	—			—			—			(99.4		)
Loss on modification/extinguishment of debt	(37.7		)	—			—			—			(37.7		)
Other income, net	—			0.8			—			—			0.8
Equity in net income (loss) of subsidiaries	3.9			—			—			(3.9		)	—
Net income (loss)	(200.8		)	38.4			(9.2		)	(3.9		)	(175.5		)
Net income attributable to non-controlling partners	—			—			25.3			—			25.3
Net income (loss) attributable to Crestwood Midstream Partners LP	$	(200.8	)	$	38.4		$	(34.5	)	$	(3.9	)	$	(200.8	)

164

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2016
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations		Consolidated
Revenues	$	—		$	2,520.5		$	—	$	—	$	2,520.5
Costs of product/services sold	—			1,925.1			—		—		1,925.1
Expenses:
Operations and maintenance	—			155.0			—		—		155.0
General and administrative	66.4			19.2			—		—		85.6
Depreciation, amortization and accretion	—			240.5			—		—		240.5
	66.4			414.7			—		—		481.1
Other operating expenses:
Loss on long-lived assets, net	—			(65.6		)	—		—		(65.6		)
Goodwill impairment	—			(162.6		)	—		—		(162.6		)
Operating loss	(66.4		)	(47.5		)	—		—		(113.9		)
Earnings from unconsolidated affiliates, net	—			—			31.5		—		31.5
Interest and debt expense, net	(125.1		)	—			—		—		(125.1		)
Gain on modification/extinguishment of debt	10.0			—			—		—		10.0
Equity in net income (loss) of subsidiaries	(40.2		)	—			—		40.2		—
Net income (loss)	(221.7		)	(47.5		)	31.5		40.2		(197.5		)
Net income attributable to non-controlling partners	—			—			24.2		—		24.2
Net income (loss) attributable to Crestwood Midstream Partners LP	$	(221.7	)	$	(47.5	)	$	7.3	$	40.2	$	(221.7	)

165

Crestwood Midstream Partners
Condensed Consolidating Statements of Operations
Year Ended December 31, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Revenues	$	—		$	2,632.8		$	—		$	—	$	2,632.8
Costs of product/services sold	—			1,883.5			—			—		1,883.5
Expenses:
Operations and maintenance	—			188.7			—			—		188.7
General and administrative	65.3			40.3			—			—		105.6
Depreciation, amortization and accretion	—			278.5			—			—		278.5
	65.3			507.5			—			—		572.8
Other operating expenses:
Loss on long-lived assets, net	—			(227.8		)	—			—		(227.8		)
Goodwill impairment	—			(1,149.1		)	—			—		(1,149.1		)
Operating loss	(65.3		)	(1,135.1		)	—			—		(1,200.4		)
Loss from unconsolidated affiliates, net	—			—			(60.8		)	—		(60.8		)
Interest and debt expense, net	(130.5		)	—			—			—		(130.5		)
Loss on modification/extinguishment of debt	(18.9		)	—			—			—		(18.9		)
Equity in net income (loss) of subsidiaries	(1,219.0		)	—			—			1,219.0		—
Net income (loss)	(1,433.7		)	(1,135.1		)	(60.8		)	1,219.0		(1,410.6		)
Net income attributable to non-controlling partners	—			—			23.1			—		23.1
Net income (loss) attributable to Crestwood Midstream Partners LP	(1,433.7		)	(1,135.1		)	(83.9		)	1,219.0		(1,433.7		)
Net income attributable to Class A preferred units	23.1			—			—			—		23.1
Net income (loss) attributable to partners	$	(1,456.8	)	$	(1,135.1	)	$	(83.9	)	$	1,219.0	$	(1,456.8	)

166

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(162.3	)	$	379.2		$	45.3		$	—		$	262.2
Cash flows from investing activities:
Purchases of property, plant and equipment	(6.7		)	(181.7		)	—			—			(188.4		)
Investment in unconsolidated affiliates	—			—			(58.0		)	—			(58.0		)
Capital distributions from unconsolidated affiliates	—			—			59.9			—			59.9
Net proceeds from sale of assets	—			225.2			—			—			225.2
Capital distributions from consolidated affiliates	4.3			—			—			(4.3		)	—
Net cash provided by (used in) investing activities	(2.4		)	43.5			1.9			(4.3		)	38.7
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,838.6			—			—			—			2,838.6
Payments on long-term debt	(2,912.6		)	(1.3		)	—			—			(2,913.9		)
Payments on capital leases	—			(2.7		)	—			—			(2.7		)
Payments for debt-related deferred costs	(1.0		)	—			—			—			(1.0		)
Redemption of non-controlling interest	—			—			(202.7		)	—			(202.7		)
Net proceeds from issuance of non-controlling interest	—			—			175.0			—			175.0
Distributions to partners	(174.0		)	—			(15.2		)	—			(189.2		)
Distributions to parent	—			—			(4.3		)	4.3			—
Taxes paid for unit-based compensation vesting	—			(5.5		)	—			—			(5.5		)
Change in intercompany balances	413.4			(413.4		)	—			—			—
Other	—			0.2			—			—			0.2
Net cash provided by (used in) financing activities	164.4			(422.7		)	(47.2		)	4.3			(301.2		)
Net change in cash	(0.3		)	—			—			—			(0.3		)
Cash at beginning of period	1.3			—			—			—			1.3
Cash at end of period	$	1.0		$	—		$	—		$	—		$	1.0

167

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2016
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(188.0	)	$	502.8		$	39.0		$	—		$	353.8
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(7.2		)	—			—			(7.2		)
Purchases of property, plant and equipment	(1.7		)	(99.0		)	—			—			(100.7		)
Investment in unconsolidated affiliates	—			—			(12.4		)	—			(12.4		)
Capital distributions from unconsolidated affiliates	—			—			14.8			—			14.8
Net proceeds from sale of assets	—			972.7			—			—			972.7
Capital distributions from consolidated affiliates	26.2			—			—			(26.2		)	—
Net cash provided by (used in) investing activities	24.5			866.5			2.4			(26.2		)	867.2
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	1,565.3			—			—			—			1,565.3
Payments on long-term debt	(2,535.3		)	(0.8		)	—			—			(2,536.1		)
Payments on capital leases	—			(1.9		)	—			—			(1.9		)
Payments for debt-related deferred costs	(3.5		)	—			—			—			(3.5		)
Distributions to partners	(227.6		)	—			(15.2		)	—			(242.8		)
Distributions to parent	—			—			(26.2		)	26.2			—
Taxes paid for unit-based compensation vesting	—			(0.8		)	—			—			(0.8		)
Change in intercompany balances	1,365.8			(1,365.8		)	—			—			—
Net cash provided by (used in) financing activities	164.7			(1,369.3		)	(41.4		)	26.2			(1,219.8		)
Net change in cash	1.2			—			—			—			1.2
Cash at beginning of period	0.1			—			—			—			0.1
Cash at end of period	$	1.3		$	—		$	—		$	—		$	1.3

168

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(190.8	)	$	650.0		$	12.6		$	—		$	471.8
Cash flows from investing activities:
Purchases of property, plant and equipment	(0.8		)	(181.9		)	—			—			(182.7		)
Investment in unconsolidated affiliates	—			—			(41.8		)	—			(41.8		)
Capital distributions from unconsolidated affiliates	—			—			9.3			—			9.3
Net proceeds from sale of assets	—			2.7			—			—			2.7
Capital contributions to consolidated affiliates	(31.2		)	—			—			31.2			—
Net cash provided by (used in) investing activities	(32.0		)	(179.2		)	(32.5		)	31.2			(212.5		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	3,490.1			—			—			—			3,490.1
Payments on long-term debt	(2,960.9		)	—			—			—			(2,960.9		)
Payments on capital leases	—			(2.2		)	—			—			(2.2		)
Payments for debt-related deferred costs	(17.3		)	—			—			—			(17.3		)
Financing fees paid for early debt redemption	(13.6		)	—			—			—			(13.6		)
Distributions to partners	(808.2		)	—			(11.3		)	—			(819.5		)
Contributions from parent	—			—			31.2			(31.2		)	—
Net proceeds from issuance of preferred units	58.8			—			—			—			58.8
Taxes paid for unit-based compensation vesting	—			(2.1		)	—			—			(2.1		)
Change in intercompany balances	474.1			(474.1		)	—			—			—
Other	(0.1		)	—			—			—			(0.1		)
Net cash provided by (used in) financing activities	222.9			(478.4		)	19.9			(31.2		)	(266.8		)
Net change in cash	0.1			(7.6		)	—			—			(7.5		)
Cash at beginning of period	—			7.6			—			—			7.6
Cash at end of period	$	0.1		$	—		$	—		$	—		$	0.1

169

Supplemental Selected Quarterly Financial Information (Unaudited)

Summarized unaudited quarterly financial data is presented below (in millions, except per unit information):

Crestwood Equity	Quarter Ended
	March 31			June 30			September 30			December 31
2017
Revenues	$	828.1		$	850.3		$	955.6		$	1,246.9
Operating income (loss) (1)	36.1			15.1			(15.3		)	(115.3		)
Earnings from unconsolidated affiliates, net	8.1			9.6			11.5			18.6
Loss on modification/extinguishment of debt	(37.3		)	(0.4		)	—			—
Net income (loss)	(19.4		)	0.3			(27.9		)	(119.6		)
Net loss attributable to partners	(43.3		)	(19.5		)	(50.5		)	(141.1		)
Net loss per limited partner unit:
Basic	$	(0.62	)	$	(0.28	)	$	(0.72	)	$	(2.01	)
Diluted	$	(0.62	)	$	(0.28	)	$	(0.72	)	$	(2.01	)
2016
Revenues	$	536.0		$	601.9		$	587.6		$	795.0
Operating income (loss) (1)	(64.2		)	(19.1		)	17.1			(42.5		)
Earnings from unconsolidated affiliates, net	6.5			6.2			13.4			5.4
Gain on modification/extinguishment of debt	—			10.0			—			—
Net income (loss)	(93.7		)	(37.1		)	3.0			(64.3		)
Net loss attributable to partners	(101.2		)	(51.2		)	(10.0		)	(82.6		)
Net loss per limited partner unit:
Basic	$	(1.47	)	$	(0.74	)	$	(0.14	)	$	(1.20	)
Diluted	$	(1.47	)	$	(0.74	)	$	(0.14	)	$	(1.20	)

Crestwood Midstream	Quarter Ended
	March 31			June 30			September 30			December 31
2017
Revenues	$	828.1		$	850.3		$	955.6		$	1,246.9
Operating income (loss) (1)	34.2			13.0			(17.0		)	(117.2		)
Loss on modification/extinguishment of debt	(37.3		)	(0.4		)	—			—
Earnings from unconsolidated affiliates, net	8.1			9.6			11.5			18.6
Net loss	(21.4		)	(1.9		)	(29.8		)	(122.4		)
Net loss attributable to partners	(27.5		)	(8.2		)	(36.2		)	(128.9		)
2016
Revenues	$	536.0		$	601.9		$	587.6		$	795.0
Operating income (loss) (1)	(65.9		)	(17.3		)	14.7			(45.4		)
Earnings from unconsolidated affiliates, net	6.5			6.2			13.4			5.4
Gain on modification/extinguishment of debt	—			10.0			—			—
Net income (loss)	(95.3		)	(35.6		)	0.6			(67.2		)
Net loss attributable to partners	(101.2		)	(41.6		)	(5.5		)	(73.4		)

(1) Amount includes goodwill, property, plant and equipment and intangible asset impairments of $121.0 million during the three months ended December 31, 2017. Amount includes goodwill and intangible asset impairments of $109.7 million and $84.3 million during the three months ended March 31, 2016 and December 31, 2016, respectively. See Note 2 for a further discussion of our impairments recorded during 2016. During the three months ended December 31, 2017, we recorded a $57 million loss on contingent consideration related to our Stagecoach Gas equity investment. See Note 6 for a further discussion of the loss on contingent consideration.

170

SIGNATURES

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

		CRESTWOOD EQUITY PARTNERS LP
		By Crestwood Equity GP, LLC
		(its general partner)
		CRESTWOOD MIDSTREAM PARTNERS LP
		By Crestwood Midstream GP LLC
		(its general partner)
Dated:	February 23, 2018	By	/s/    ROBERT G. PHILLIPS
			Robert G. Phillips
			President, Chief Executive Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following officers of Crestwood Equity GP, LLC, as general partner of Crestwood Equity Partners LP, and Crestwood Midstream GP LLC, as general partner of Crestwood Midstream Partners LP, and the following directors of Crestwood Equity GP LLC in the capacities and on the dates indicated.

Date	Signature and Title
February 23, 2018	/s/    ROBERT G. PHILLIPS Robert G. Phillips, President, Chief Executive Officer and Director (Principal Executive Officer)
February 23, 2018	/s/    ROBERT T. HALPIN Robert T. Halpin, Executive Vice President and Chief Financial Officer (Principal Financial Officer)
February 23, 2018	/s/    STEVEN M. DOUGHERTY Steven M. Dougherty, Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)
February 23, 2018	/s/    ALVIN BLEDSOE Alvin Bledsoe, Director
February 23, 2018	/s/    MICHAEL G. FRANCE Michael G. France, Director
February 23, 2018	/s/    WARREN H. GFELLER Warren H. Gfeller, Director
February 23, 2018	/s/    DAVID LUMPKINS David Lumpkins, Director
February 23, 2018	/s/    JOHN J. SHERMAN John J. Sherman, Director
February 23, 2018	/s/    JOHN W. SOMERHALDER II John W. Somerhalder II, Director

171

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Balance Sheets

(in millions)

	December 31,
	2017		2016
Assets
Current assets:
Cash	$	0.3	$	0.3
Total current assets	0.3		0.3
Property, plant and equipment, net	1.2		1.4
Intangible assets, net	1.4		4.5
Investments in subsidiaries	2,005.1		2,342.7
Other assets	3.5		4.3
Total assets	$	2,011.5	$	2,353.2
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	2.7	$	2.7
Accrued expenses	1.2		1.4
Total current liabilities	3.9		4.1
Other long-term liabilities	2.1		2.6
Total partners’ capital	2,005.5		2,346.5
Total liabilities and partners’ capital	$	2,011.5	$	2,353.2

See accompanying notes.

172

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Operations

(in millions)

	Year Ended December 31,
	2017			2016			2015
Revenues	$	—		$	—		$	—
Expenses	6.7			6.0			14.5
Operating loss	(6.7		)	(6.0		)	(14.5		)
Interest and debt expense, net	—			—			(9.6		)
Equity in net loss of subsidiaries	(160.4		)	(186.6		)	(2,279.1		)
Loss on modification/extinguishment of debt	—			—			(1.1		)
Other income, net	0.5			0.5			0.6
Net loss	(166.6		)	(192.1		)	(2,303.7		)
Net income (loss) attributable to non-controlling partners	25.3			24.2			(636.8		)
Net income loss attributable to Crestwood Equity Partners LP	$	(191.9	)	$	(216.3	)	$	(1,666.9	)

See accompanying notes.

173

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Comprehensive Income

(in millions)

	Year Ended December 31,
	2017			2016			2015
Net loss	$	(166.6	)	$	(192.1	)	$	(2,303.7	)
Change in fair value of Suburban Propane Partners, LP units	(0.8		)	0.8			(2.7		)
Comprehensive loss	(167.4		)	(191.3		)	(2,306.4		)
Comprehensive income (loss) attributable to non-controlling interest	25.3			24.2			(636.8		)
Comprehensive loss attributable to Crestwood Equity Partners LP	$	(192.7	)	$	(215.5	)	$	(1,669.6	)

See accompanying notes.

174

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Cash Flows

(in millions)

	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities	$	(3.6	)	$	(3.5	)	$	(14.7	)
Cash flows from investing activities	174.0			227.6			593.8
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	—			—			771.7
Principal payments on long-term debt	—			(0.2		)	(1,152.1		)
Distributions paid to partners	(182.6		)	(219.8		)	(171.5		)
Proceeds from issuance of common units	15.2			—			—
Change in intercompany balances	(3.0		)	(4.2		)	(30.5		)
Net cash used in financing activities	(170.4		)	(224.2		)	(582.4		)
Net change in cash	—			(0.1		)	(3.3		)
Cash at beginning of period	0.3			0.4			3.7
Cash at end of period	$	0.3		$	0.3		$	0.4

See accompanying notes.

175

Schedule I

Crestwood Equity Partners LP

Parent Only

Notes to Condensed Financial Statements

Note 1. Basis of Presentation

In the parent-only financial statements, our investment in subsidiaries is stated at cost plus equity in undistributed earnings of subsidiaries since the date of acquisition.  Our share of net income of our unconsolidated subsidiaries is included in consolidated income using the equity method.  The parent-only financial statements should be read in conjunction with our consolidated financial statements. 

Note 2.Distributions    

During the years ended December 31, 2017, 2016 and 2015, we received cash distributions from Crestwood Midstream Partners LP of approximately $174.0 million, $227.6 million and $31.4 million.

176

Schedule II

Crestwood Equity Partners LP

Crestwood Midstream Partners LP

Valuation and Qualifying Accounts

For the Years Ended December 31, 2017, 2016 and 2015

(in millions)

	Balance at beginning of period		Charged to costs and expenses		Other Additions		Deductions (write-offs)			Balance at end of period
Allowance for doubtful accounts
2017	$	1.9	$	1.5	$	—	$	(1.0	)	$	2.4
2016	0.4		1.9		—		(0.4		)	1.9
2015	0.1		—		0.4		(0.1		)	0.4

177

EX-4.4

Exhibit 4.4

SUPPLEMENTAL INDENTURE

THIS SUPPLEMENTAL INDENTURE (this “Supplemental Indenture”), is dated as of December 1, 2017, among Crestwood Midstream Partners LP, a Delaware limited partnership (the “Company”), Crestwood Midstream Finance Corporation, a Delaware corporation (the “Co-Issuer” and, together, with the Company, the “Issuers”), each existing Guarantor under each of the Indentures referred to below and U.S. Bank National Association, as trustee under each of the Indentures referred to below (the “Trustee”).

WITNESSETH:

WHEREAS, the Issuers and the existing Guarantors have heretofore executed and delivered to the Trustee (i) an indenture (as it may have been heretofore amended or supplemented, the “2015 Indenture”), dated as of March 23, 2015, providing for the issuance of the Issuers’ 6.25% Senior Notes due 2023 (the “2023Notes”) and (ii) an indenture (as it may have been heretofore amended or supplemented, the “2017 Indenture” and, together with the 2015 Indenture, the “Indentures”), dated as of March 14, 2017, providing for the issuance of the Issuers’ 5.75% Senior Notes due 2025 (the “2025Notes” and, together with the 2023 Notes, the “Notes”);

WHEREAS, Section 10.05 of each of the Indentures provides that the Note Guarantee of a Guarantor will be automatically released in connection with any sale, disposition or transfer of Capital Stock of a Guarantor after which such Guarantor is no longer a Restricted Subsidiary of the Company, if the sale, disposition or transfer does not violate Section 4.10 of such Indenture;

WHEREAS, pursuant to the transactions contemplated by that certain Membership Interest Purchase Agreement by and between Crestwood Midstream Operations LLC and US Salt Investors, LLC, dated October 27, 2017, the Capital Stock of US Salt, LLC, a Delaware limited liability company (“US Salt”) was sold in a manner that did not violate Section 4.10 of each of the Indentures, and after which US Salt was no longer a Restricted Subsidiary of the Company;

WHEREAS, pursuant to Section 9.01(8) of the 2015 Indenture and Section 9.01(9) of the 2017 Indenture, the Trustee, the Issuers and the existing Guarantors are authorized to execute and deliver this Supplemental Indenture, without the consent on any Holder of any of the Notes, to acknowledge the release of any Guarantor from its Note Guarantee.

NOW, THEREFORE, in consideration of the foregoing and for other good and valuable consideration, the receipt of which is hereby acknowledged, the Issuers, the Guarantors and the Trustee mutually covenant and agree for the equal and ratable benefit of the Holders as follows:

1.    DEFINED TERMS. Defined terms used herein without definition shall have the meanings assigned to them in the Indenture.

2.    RELEASE OF NOTE GUARANTEES. In sole reliance on the Officer’s Certificate and the Opinion of Counsel delivered to the Trustee on the date hereof, the Trustee acknowledges

that US Salt is unconditionally released from its Note Guarantee, and accordingly, that US Salt is no longer a party to the Indentures.

3.    RATIFICATION OF EACH INDENTURE; SUPPLEMENTAL INDENTURE PART OF EACH INDENTURE. Except as expressly amended hereby, each Indenture is in all respects ratified and confirmed and all the terms, conditions and provisions thereof shall remain in full force and effect. This Supplemental Indenture shall form a part of each Indenture for all purposes, and every holder of Notes heretofore or hereafter authenticated and delivered shall be bound hereby.

4.    GOVERNING LAW. THIS SUPPLEMENTAL INDENTURE SHALL BE GOVERNED BY, AND CONSTRUED IN ACCORDANCE WITH, THE LAWS OF THE STATE OF NEW YORK.

5.    COUNTERPARTS. The parties may sign any number of copies of this Supplemental Indenture. Each signed copy shall be an original, but all of them together represent the same agreement. The exchange of copies of this Supplemental Indenture and of signature pages by facsimile or PDF transmission shall constitute effective execution and delivery of this Supplemental Indenture as to the parties hereto and may be used in lieu of the original Supplemental Indenture for all purposes. Signatures of the parties hereto transmitted by facsimile or PDF shall be deemed to be their original signatures for all purposes.

6.    EFFECT OF HEADINGS. The Section headings of this Supplemental Indenture have been inserted for convenience of reference only and are not to be considered part of this Supplemental Indenture or the Indenture and will in no way modify or restrict any of the terms or provisions hereof or thereof.

7.    TRUSTEE MAKES NO REPRESENTATION. The Trustee makes no representation as to the validity or sufficiency of this Supplemental Indenture. The recitals and statements herein are deemed to be those of the Issuers and the Guarantors and not those of the Trustee, and the Trustee assumes no responsibility for their correctness.    

IN WITNESS WHEREOF, the parties hereto have caused this Supplemental Indenture to be duly executed and attested, all as of the date first above written.

CRESTWOOD MIDSTREAM PARTNERS LP

By: Crestwood Midstream GP LLC, its general partner

/s/ Steven M. Dougherty_____ _____________

Name:    Steven M. Dougherty

Title: Senior Vice President and Chief Accounting Officer

CRESTWOOD MIDSTREAM FINANCE CORP.

/s/ Steven M. Dougherty_____ _____________

Name:    Steven M. Dougherty

Title: Senior Vice President and Chief Accounting Officer

GUARANTORS:

ARROW FIELD SERVICES, LLC

ARROW MIDSTREAM HOLDINGS, LLC

ARROW PIPELINE, LLC

ARROW WATER, LLC

CMLP TRES MANAGER LLC

CMLP TRES OPERATOR LLC

/s/ Steven M. Dougherty_____ _____________

Name:    Steven M. Dougherty

Title: Senior Vice President and Chief Accounting Officer

COWTOWN GAS PROCESSING PARTNERS L.P.

By: Crestwood Gas Services Operating GP LLC,

its general partner

COWTOWN PIPELINE PARTNERS L.P.

By: Crestwood Gas Services Operating GP LLC,

its general partner

/s/ Steven M. Dougherty_____ _____________

Name:    Steven M. Dougherty

Title: Senior Vice President and Chief Accounting Officer

Signature Page to Supplemental Indenture

CRESTWOOD APPALACHIA PIPELINE LLC

CRESTWOOD ARKANSAS PIPELINE LLC

CRESTWOOD CRUDE LOGISTICS LLC

CRESTWOOD CRUDE SERVICES LLC

CRESTWOOD CRUDE TERMINALS LLC

CRESTWOOD CRUDE TRANSPORTATION LLC

CRESTWOOD DAKOTA PIPELINES LLC

CRESTWOOD GAS SERVICES OPERATING GP LLC

CRESTWOOD GAS SERVICES OPERATING LLC

CRESTWOOD MARCELLUS MIDSTREAM LLC

CRESTWOOD MARCELLUS PIPELINE LLC

CRESTWOOD MIDSTREAM OPERATIONS LLC

CRESTWOOD OHIO MIDSTREAM PIPELINE LLC

CRESTWOOD OPERATIONS LLC

CRESTWOOD PANHANDLE PIPELINE LLC

CRESTWOOD PIPELINE LLC

CRESTWOOD SALES & SERVICE INC.

CRESTWOOD SERVICES LLC

CRESTWOOD TRANSPORTATION LLC

CRESTWOOD WEST COAST LLC

E. MARCELLUS ASSET COMPANY, LLC

FINGER LAKES LPG STORAGE, LLC

STELLAR PROPANE SERVICE LLC

US SALT, LLC

/s/ Steven M. Dougherty_____ _____________

Name:    Steven M. Dougherty

Title: Senior Vice President and Chief Accounting Officer

Signature Page to Supplemental Indenture

U.S. BANK NATIONAL ASSOCIATION, as Trustee

By:    /s/ Raymond S. Haverstock___________________

Name:    Raymond S. Haverstock

    Title:    Vice President

Signature Page to Supplemental Indenture

EX-4.9

Exhibit 4.9

Execution Version

SECOND AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

CRESTWOOD NIOBRARA LLC

a Delaware Limited Liability Company

Dated as of December 28, 2017

Limited liability company interests in Crestwood Niobrara LLC, a Delaware limited liability company, have not been registered with or qualified by the Securities and Exchange Commission or any securities regulatory authority of any state. The interests are being sold in reliance upon exemptions from such registration or qualification requirements. The interests cannot be sold, transferred, assigned or otherwise disposed of except in compliance with the restrictions on transferability contained in the Second Amended and Restated Limited Liability Company Agreement of Crestwood Niobrara LLC, as such may be amended or restated from time to time, and applicable federal and state securities laws.

TABLE OF CONTENTS

Page

ARTICLE I
DEFINITIONS

1.01Certain Definitions    1

1.02Construction.    17

ARTICLE II
ORGANIZATION

2.01Continuation of the Company    17

2.02Name    18

2.03Registered Office; Registered Agent    18

2.04Principal Office    18

2.05Purpose; Powers    18

2.06Fiscal Year; Tax Year    18

2.07Foreign Qualification Governmental Filings    18

2.08Term    18

ARTICLE III
MEMBERS; TRANSFERS OF INTERESTS

3.01Members    19

3.02Restrictions on the Transfer of Interests    19

3.03Right of First Offer on Transfer of Units.    19

3.04Right of First Offer on Indirect Holdings Member Transfer.    20

3.05Requirements Applicable to All Transfers    22

3.06Additional Members    22

3.07Representations and Warranties    23

3.08Liability to Third Parties    23

3.09Representations and Warranties Made by Crestwood Member    23

3.10Tag-Along Right    23

ARTICLE IV
CAPITAL CONTRIBUTIONS; REDEMPTIONS OF PREFERRED UNITS

4.01Interests    24

4.02Capital Contributions.    25

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4.03Funding Defaults    27

4.04Withdrawal or Return of Capital    29

4.05Further Contributions    29

4.06Redemption of Preferred Units    30

4.07Conversion of Preferred Units.    36

ARTICLE V
DISTRIBUTIONS AND ALLOCATIONS

5.01Distributions    38

5.02Allocations    40

ARTICLE VI
MANAGEMENT

6.01Authority of the Managing Member    44

6.02Actions Requiring Holdings Member Consent    44

6.03Opportunities; Midstream Project Opportunities    49

6.04Indemnification; Limitation of Liability    52

6.05No Recourse Against Nonparty Affiliates    53

6.06Initial Budget and Annual Budgets    54

ARTICLE VII
RIGHTS OF MEMBERS; CONFIDENTIALITY

7.01Access to Information    54

7.02Financial Reports    55

7.03Audits    56

7.04Confidentiality    56

7.05Press Releases    57

ARTICLE VIII
TAXES

8.01Tax Returns    57

8.02Tax Elections    57

8.03Tax Audits    57

ARTICLE IX
BOOKS, RECORDS, REPORTS, AND BANK ACCOUNTS

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9.01Maintenance of Books and Records    58

9.02Reports    58

9.03Bank Accounts    59

ARTICLE X
DISSOLUTION, LIQUIDATION AND TERMINATION

10.01Dissolution    59

10.02Liquidation and Termination    59

10.03Cancellation of Filing    60

ARTICLE XI
GENERAL PROVISIONS

11.01Notices    61

11.02Entire Agreement; Third Party Beneficiaries    61

11.03Effect of Waiver or Consent    61

11.04Amendment or Modification    61

11.05Survivability of Terms    61

11.06Binding Effect    62

11.07Governing Law; Severability    62

11.08Consent to Jurisdiction; Waiver of Jury Trial    62

11.09Further Assurances    62

11.10Title to Company Property    62

11.11Counterparts    62

11.12Electronic Transmissions    63

11.13Equitable Relief    63

Schedule I – Existing Agreements within the Area of Interest

Exhibit A – Members, Classes, Capital Contributions and Units

Exhibit B – Form of Pre-Distribution Certification

Exhibit C – Sample Calculation of IRR

Exhibit D – Initial Budget

-iii-

SECOND AMENDED AND RESTATED

LIMITED LIABILITY COMPANY AGREEMENT

OF

CRESTWOOD NIOBRARA LLC

This SECOND AMENDED AND RESTATED LIMITED LIABILITY COMPANY AGREEMENT (the “Agreement”) of Crestwood Niobrara LLC, a Delaware limited liability company (the “Company”), is made and entered into by and between CN Jackalope Holdings, LLC, a Delaware limited liability company, Crestwood Midstream Partners LP, a Delaware limited partnership, and, solely for the purposes of the provisions set forth on its signature page to this Agreement, Crestwood Equity Partners LP, a Delaware limited partnership (“CEQP”), effective as of December 28, 2017 (the “Effective Date”). Capitalized terms used herein without definition have the meanings set forth in Section 1.01.

Article IDEFINITIONS

1.01Certain Definitions. As used in this Agreement, the following terms have the following meanings:

“Accordion Capital Contribution” has the meaning set forth in Section 4.02(b)(i).

“Act” means the Delaware Limited Liability Company Act and any successor statute, each as amended from time to time.

“Adjusted Available Cash” means, with respect to any Fiscal Quarter ending prior to the Liquidation Date, (a) the sum of all cash and cash equivalents on-hand at the end of a Fiscal Quarter, excluding, however, any Special Proceeds, less (b) an amount of cash reserves established by the Managing Member to cover the reasonably anticipated working capital needs of the Company in the then-current Fiscal Quarter, which amount shall not exceed $500,000. Notwithstanding the foregoing, “Adjusted Available Cash” with respect to the Fiscal Quarter in which the Liquidation Date occurs and any subsequent Fiscal Quarter shall equal zero.

“Adjusted Capex Amount” means, as of any date of determination, and subject to Section 4.05(a), an amount equal to the product of (a) the product of (i) 0.4999 multiplied by (ii) a fraction, the numerator of which is the number of Series A-2 Preferred Units held by the Holdings Member at the time of Conversion and the denominator of which is the total number of Series A-2 Preferred Units then outstanding multiplied by (b) sum of the following: (i) the aggregate amount of Capital Contributions made by the Crestwood Member after the Effective Date in respect of its Common Units, less (ii) the aggregate amount of distributions paid to the Crestwood Member after the Effective Date in respect of its Common Units, plus (iii) the aggregate distributions paid to the Holdings Member and the Crestwood Member in respect of Series A-2 Preferred Units and the aggregate amount of Special Proceeds paid pursuant to Section 5.01(c)(i) in respect of Series A-2 Preferred Units, less (iv) the aggregate amount of Accordion Capital Contributions made by the Holdings Member and the Crestwood Member; provided, that in no event shall the Adjusted Capex Amount be less than zero.

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“Adjusted Capital Account” means, with respect to any Member, the balance, if any, in such Member’s Capital Account as of the end of the relevant Tax Year or other period, after giving effect to the following adjustments:

(a)    adding to such Capital Account any amounts which such Member is obligated to restore pursuant to this Agreement or is deemed to be obligated to restore to the Company pursuant to Treasury Regulations Section 1.704-1(b)(2)(ii)(c) or the penultimate sentence of each of Treasury Regulations Sections 1.704-2(g)(1) and 1.704-2(i)(5); and

(b)    subtracting from such Capital Account such Member’s share of the items described in Treasury Regulations Sections 1.704-1(b)(2)(ii)(d)(4), (5) and (6).

The foregoing definition is intended to comply with the provisions of Treasury Regulations Section 1.704-1(b)(2)(ii)(d) and will be interpreted consistently therewith.

“Affiliate” means, with respect to a Person, any other Person directly or indirectly controlling or controlled by or under direct or indirect common control with the first Person. For purposes of this definition, “control” means possession, directly or indirectly, of the power to direct or cause the direction of the management or policies of a Person, whether through ownership of voting securities, by agreement or otherwise.

“Agreed Midstream Project” has the meaning set forth in Section 6.03(d)(i).

“Agreed Midstream Services” means the development and operation of any Agreed Midstream Project.

“Agreement” has the meaning set forth in the introductory paragraph hereof.

“Annual Budget” means the Initial Budget and each subsequent annual operating budget of the Company, as each such subsequent annual operating budget is approved (a) prior to a Conversion, by the Managing Member and (b) following a Conversion, pursuant to Section 6.02(b)(xv) or as otherwise in effect pursuant to Section 6.06.

“Area of Interest” means Converse County and Campbell County, each in the State of Wyoming.

“Available Cash” means, with respect to any Fiscal Quarter ending prior to the Liquidation Date:

(a)    the sum of all cash and cash equivalents of the Company on hand at the end of such Fiscal Quarter, excluding, however, any Special Proceeds; less

(b)    the amount of any cash reserves established by the Managing Member to (i) provide for the proper conduct of the business of the Company (including reserves for future capital expenditures and for anticipated future

credit needs of the Company) subsequent to such Fiscal Quarter or (ii) comply with applicable law or any loan agreement, security agreement, mortgage, debt instrument or other

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agreement or obligation to which the Company is a party or by which it is bound or its assets are subject;

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

provided, however, that disbursements made by the Company or cash reserves established, increased or reduced after the end of such Fiscal Quarter, but on or before the date of determination of Available Cash with respect to such Fiscal Quarter, shall be deemed to have been made, established, increased or reduced, for purposes of determining Available Cash, within such Fiscal Quarter if the Managing Member so determines.

Notwithstanding the foregoing, “Available Cash” with respect to the Fiscal Quarter in which the Liquidation Date occurs and any subsequent Fiscal Quarter shall equal zero.

“Big Four Firm” means Deloitte, Ernst & Young, KPMG or PricewaterhouseCoopers.

“Book Value” means, with respect to any asset, the asset’s adjusted basis for federal income tax purposes, except as follows:

(a)    the Book Value of any asset contributed by a Member to the Company is the gross Fair Market Value of such asset as jointly determined by the Members at the time of contribution;

(b)    the Book Value of all Company assets shall be adjusted to equal their respective gross Fair Market Values, as jointly determined by the Members taking into account the provisions of Treasury Regulations Section 1.704-1(b)(2)(iv)(h)(2), as of the following times: (i) immediately before the acquisition of any interest in the Company by any new or existing Member in exchange for more than a de minimis capital contribution to the Company; (ii) immediately before the distribution by the Company to the Member of more than a de minimis amount of property as consideration for an interest in the Company; and (iii) immediately before the liquidation of the Company within the meaning of Treasury Regulations Section 1.704-1(b)(2)(ii)(g); provided, however, that the adjustments pursuant to clauses (i) and (ii) shall be made only if the Managing Member reasonably determines that such adjustments are necessary or appropriate to reflect the relative economic interests of the Members in the Company;

(c)    the Book Value of any Company asset distributed to any Member shall be adjusted to equal the gross Fair Market Value of such asset on the date of distribution as determined jointly by the Members; and

(d)    the Book Values of Company assets shall be increased (or decreased) to reflect any adjustments to the adjusted basis of such assets pursuant to Section 734(b) or Section 743(b) of the Code, but only to the extent that such adjustments are taken into account in determining Capital Accounts pursuant to Treasury Regulations Section 1.704-1(b)(2)(iv)(m); provided, however, that Book Values shall not be adjusted pursuant to this clause (d) to the extent the Managing Member determines that an adjustment pursuant to clause (b) above is necessary or

-3-

appropriate in connection with a transaction that would otherwise result in an adjustment pursuant to this clause (d).

If the Book Value of a Company asset has been determined or adjusted pursuant to clause (a), (b) or (d) above, such Book Value shall thereafter be adjusted by the depreciation, amortization or other cost recovery deductions taken into account with respect to such asset for purposes of maintaining Capital Accounts.

“Business” means (a) gathering, treatment or processing of natural gas or gathering of crude oil or (b) owning an equity interest in any Person engaged in any of the activities referenced in clause (a) if at the time of the initial acquisition of such equity interest the activities referenced in clause (a) generated more than 25% of the revenues of such Person for the most recently completed fiscal year of such Person.

“Business Day” means any day other than a Saturday, Sunday or legal holiday on which banks in New York City, New York, are authorized or obligated by law to close.

“Capital” means the amount of cash and the Fair Market Value, as jointly determined by the Members, of any property (net of any liabilities assumed by the Company or which are secured by any property contributed by such Member to the Company) contributed to the Company by the Members pursuant to the terms of this Agreement.

“Capital Account” means the Capital Account maintained for each Member on the Company’s books and records in accordance with the following provisions:

(a)    To each Member’s Capital Account there will be added (i) the amount of cash and the Fair Market Value of any other asset contributed by such Member to the Company pursuant to any provision of this Agreement, (ii) such Member’s allocable share of any items of Company income or gain, and (iii) the amount of any Company liabilities assumed by such Member or which are secured by any property distributed to such Member.

(b)    From each Member’s Capital Account there will be subtracted (i) the amount of cash and the Fair Market Value of any other Company assets distributed to such Member pursuant to any provision of this Agreement, (ii) such Member’s allocable share of any items of Company deduction or loss, and (iii) liabilities of such Member assumed by the Company or which are secured by any property contributed by such Member to the Company.

Notwithstanding the foregoing, adjustments to the foregoing may be made in the discretion of the Managing Member, with the consent of the Holdings Member, in order to comply with the Treasury Regulations promulgated under Section 704 of the Code, adjustments shall be made to the Members’ Capital Accounts in accordance with the provisions of Treasury Regulations Section 1.704-1(b)(2)(iv)(s)(3). In the event any Interest is Transferred (other than by pledge of, or grant of a security interest in, such Interest) in accordance with the terms of this Agreement, the transferee will succeed to the Capital Account of the transferor to the extent it relates to the Interest that is Transferred.

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“Capital Contribution” means, subject to Section 4.05, any amount of Capital contributed to the Company by a Member pursuant to the terms of this Agreement. Any reference to the Capital Contributions of a Member will include the Capital Contributions made by a predecessor holder of the Units of such Member.

“CEQP” has the meaning set forth in the preamble.

“CEQP Guaranty” has the meaning set forth in Section 4.06(g).

“CEQP Partnership Agreement” means the Fifth Amended and Restated Agreement of Limited Partnership of CEQP, dated as of April 11, 2014, as amended or restated prior to the Effective Date and as further amended or restated from time to time.

“CEQP Unit” has the meaning given to the term “Common Unit” in the CEQP Partnership Agreement, provided that such security is newly issued and is listed or admitted to trading on a National Securities Exchange. For all purposes hereunder, references to CEQP Units shall also be deemed to be references to any security into which “Common Units” (or any successor securities) are converted or exchanged (whether as a result of a recapitalization, reclassification, merger or otherwise), provided that any such security is newly issued and is listed or admitted to trading on a National Securities Exchange.

“CEQP Unit Price” means, as of any determination date, an amount equal to (a) ***, times (b) the volume-weighted average trading price of a CEQP Unit for the *** trading days immediately preceding such determination date.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

“Certificate” has the meaning set forth in Section 2.01.

“Change of Control Redemption Notice” has the meaning set forth in Section 4.06(b).

“Change of Control Redemption Price” means, as applicable, with respect to each Series A-2 Preferred Unit and each Series B Preferred Unit:

(a) solely in the circumstance of a Crestwood Change of Control, an amount per Series A-2 Preferred Unit equal to *** of the Series A-2 Liquidation Amount and an amount per Series B Preferred Unit equal to *** of the Series B Liquidation Amount, respectively;

(b) solely in the circumstance of a Company Change of Control, an amount determined as follows:

(i)if the Company Change of Control occurs on or prior to the first anniversary of the Effective Date, an amount per Series A-2 Preferred Unit equal to *** of the Series A-2 Liquidation Amount and an amount per Series B Preferred Unit equal to *** of the Series B Liquidation Amount, respectively;

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(ii)if the Company Change of Control occurs following the first anniversary of the Effective Date but on or prior to the second anniversary of the Effective Date, an amount per Series A-2 Preferred Unit equal to *** of the Series A-2 Liquidation Amount and an amount per Series B Preferred Unit equal to *** of the Series B Liquidation Amount, respectively;

(iii)if the Company Change of Control occurs following the second anniversary of the Effective Date but on or prior to the third anniversary of the Effective Date, an amount per Series A-2 Preferred Unit equal to *** of the Series A-2 Liquidation Amount and an amount per Series B Preferred Unit equal to *** of the Series B Liquidation Amount, respectively;

(iv)if the Company Change of Control occurs following the third anniversary of the Effective Date but on or prior to the fourth anniversary of the Effective Date, an amount per Series A-2 Preferred Unit equal to *** of the Series A-2 Liquidation Amount and an amount per Series B Preferred Unit equal to *** of the Series B Liquidation Amount, respectively; or

(v)if the Company Change of Control occurs following the fourth anniversary of the Effective Date, an amount per Series A-2 Preferred Unit equal to the Series A-2 Liquidation Amount and an amount per Series B Preferred Unit equal to the Series B Liquidation Amount, respectively.

“Code” means the Internal Revenue Code of 1986 and any successor statute, as amended from time to time.

“Collection Costs” means any costs and expenses, including, without limitation, attorney’s fees and costs, incurred by the Company or a non-defaulting Member in connection with collecting all or any portion of a Post-Conversion Default.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

“Common Member” means any Member holding Common Units.

“Common Unit Price” means $1.00 per Common Unit.

“Common Units” means the Common Units issued to the Crestwood Member as set forth on Exhibit A as of the Effective Date and any other Units issued after the date hereof and designated as Common Units.

“Company” has the meaning set forth in the introductory paragraph hereof.

“Company Change of Control” means any event or transaction, or series of related events or transactions, the result of which is that neither the Crestwood Member as of the Effective Date nor the Holdings Member (or any investor therein) is, or directly or indirectly Controls, the Managing

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Member; provided, that any event or transaction, or series of related events or transactions, that constitute a Crestwood Change of Control pursuant to clause (a), (c) or (d) of that definition shall not be considered a Company Change of Control.

“Company Minimum Gain” has the meaning set forth in Treasury Regulations Sections 1.704-2(b)(2) and 1.704-2(d)(1) for the phrase “partnership minimum gain.”

“Competitor” means, as of any date of determination, any Person that is engaged in the Business in the Area of Interest as of such date; provided, however, that (x) “Access” (as such term is defined in the Jackalope LLC Agreement) or its successor under the Jackalope LLC Agreement shall not be a Competitor if it were to become a Member or a direct or indirect owner of a Member pursuant to Section 4.2 of the Jackalope LLC Agreement and (y) a private equity fund, infrastructure fund or other financial investor shall not be a Competitor unless it has an Affiliate that would satisfy the foregoing definition of Competitor.

“Consideration Election Notice” has the meaning set forth in Section 4.06(b).

“Control”, “Controlling” or “Controlled” as to any Entity means (a) the possession, directly or indirectly, through one or more intermediaries, of the right to more than 50% of the distributions therefrom (including liquidating distributions); or (b) the power or authority, through ownership of voting securities, by contract or otherwise, to direct the management, activities or policies of such Entity by contract or otherwise.

“Conversion” has the meaning set forth in Section 4.07(a).

“Conversion Notice” has the meaning set forth in Section 4.07(a).

“Conversion Notice Deadline” has the meaning set forth in Section 4.07(a).

“Crestwood Additional Capital Contribution” has the meaning set forth in Section 4.02(b)(i).

“Crestwood Change of Control” means the occurrence of any of the following: (a) any circumstance after which both (I) First Reserve Fund XI, L.P. or an Affiliate of First Reserve Fund XI, L.P. has ceased to be the general partner of CEQP (or the controlling equityholder or general partner of any successor to CEQP) and (II) Robert Phillips has ceased to be the Chief Executive Officer of CEQP, (b) any circumstance pursuant to which the CEQP Units are no longer listed or admitted to trading on a National Securities Exchange, (c) any direct or indirect sale, lease, transfer, conveyance or other disposition, in one or more series of related transactions, of all or substantially all of the properties and assets of CEQP to a Person other than any of its Affiliates or (d) any dissolution or liquidation of CEQP (other than in connection with a bankruptcy proceeding or a statutory winding up).

“Crestwood Member” means Crestwood Midstream Partners LP, a Delaware limited partnership, or, as applicable, any transferee of Crestwood Midstream Partners LP that has become a Member in accordance with this Agreement following the Transfer of all of the Crestwood

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Member’s Units to such transferee. For the purpose of calculating the amount of contributions or distributions made with respect to any Unit held at various times by more than one Crestwood Member, the Crestwood Member will mean the current Crestwood Member and all prior Crestwood Members that previously held such Unit.

“Cure Period” has the meaning set forth in Section 4.03(c)(ii).

“CWN EBITDA” means the sum of (a) with respect to Jackalope LLC, the product of the following with respect to Jackalope LLC multiplied by the Company’s percentage ownership of Jackalope LLC plus (b)  with respect to any other assets owned by the Company, the product of the following with respect to such assets multiplied by the Company’s percentage ownership thereof, in each case for the relevant period:

(a) net income (or loss);

(b) increased (without duplication) by the following items to the extent deducted in calculating such net income:

(i) interest expense, plus

(ii) income taxes; plus

(iii) depreciation expense; plus

(iv) amortization expense; plus

(v) non-cash expenses, charges, and losses, including (A) non-cash compensation charges or expenses, (B) non-cash losses incurred on hedging agreements, (C) non-cash foreign currency losses and (D) non-cash lease accretion expenses; plus

(vi) any other extraordinary or non-recurring charges, expenses, and losses (including arising on account of changes in accounting principles); and

(c) decreased (without duplication) by the following items to the extent included in calculating such net income:

(i) non-cash income and gains, including (A) non-cash compensation gains, (B) non-cash gains incurred on hedging agreements, and (C) non-cash foreign currency gains; plus

(ii) any other extraordinary or non-recurring income and gains (including arising on account of changes in accounting principles).

“CWN TTM EBITDA Condition” means, as of any date of determination, the circumstance in which CWN EBITDA attributable to the immediately preceding 12 completed calendar months is greater than ***.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY

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SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

“De Minimis Midstream Project Opportunity” means an opportunity or project for engaging in the Business in the Area of Interest that would constitute a Midstream Project Opportunity but for the provisions of clause (b) of the definition of Midstream Project Opportunity. For the avoidance of doubt, if an opportunity or project for engaging in the Business in the Area of Interest constitutes a De Minimis Midstream Project Opportunity but thereafter aggregate anticipated expenditures exceed the specified thresholds in the aforementioned clause (b), then such opportunity or project shall cease to be a De Minimis Midstream Project Opportunity and would become a Midstream Project Opportunity and would be subject to the other applicable provisions of this Agreement.

“Default Contribution” has the meaning set forth in Section 4.03(b).

“Deficiency Contribution” has the meaning set forth in Section 4.03(a).

“Deficiency Event” has the meaning set forth in Section 4.03(a).

“Deficiency Preferred Units” means the Series B Preferred Units and the Series C Preferred Units, collectively.

“Dispute” means any dispute, controversy or claim, of any and every kind or type, whether based on contract, tort, statute, regulations, or otherwise, between the Parties, arising out of, connected with, or relating in any way to the Company or its business or to this Agreement or the obligations of the Parties, including any dispute as to the existence, validity, construction, interpretation, negotiation, performance, non-performance, breach, termination or enforceability of this Agreement.    

“Effective Date” has the meaning set forth in the introductory paragraph hereof.

*** means any Entity Controlled, directly or indirectly, by ***.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

“Entity” means any corporation, limited liability company, general partnership, limited partnership, venture, trust, business trust, unincorporated association, estate or other entity.

“Evaluation Material” has the meaning set forth in Section 6.03(c)(ii).

“Excluded Indirect Crestwood Transfer” means any (i) transaction, or series of related transactions, pursuant to which an equity interest in the Crestwood Member, or in any of its direct or indirect owners, is transferred as part of a larger transaction involving a sale or transfer of additional assets in which the Fair Market Value of the Units being indirectly transferred in such transaction represents less than 25% of the Fair Market Value of all assets being sold or transferred in such transaction, or series of related transactions, (ii) any change in the ownership of CEQP or any of its successors whether through a sale, issuance, merger, consolidation, exchange,

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recapitalization, reorganization, conversion, cancellation, redemption or repurchase transaction or otherwise or (iii) any issuance of equity securities in the Crestwood Member so long as the proceeds received by the Crestwood Member in such issuance are used to make a Capital Contribution to the Company.

“Excluded Indirect Holdings Member Transfer” means any transaction, or series of related transactions, (i) pursuant to which an equity interest in the Holdings Member, or in any of its direct or indirect owners, is transferred as part of a larger transaction involving a sale or transfer of additional assets in which the Fair Market Value of the Units being indirectly transferred in such transaction represents less than 25% of the Fair Market Value of all assets being sold or transferred in such transaction, or series of related transactions or (ii) following which both (A) *** and *** collectively still own, directly or indirectly (and in each case together with their respective Affiliates), at least 50% of the equity interests in the Holdings Member and (B) either *** or ***, or one of their respective Affiliates, serves as the owner in the Holdings Member that represents the Holdings Member with respect to matters arising under this Agreement.

“Excluded Opportunity” means, as of any date of determination, (a) any Business in the Area of Interest acquired by the Crestwood Member, CEQP or any of their controlled Affiliates in a transaction, or series of related transactions, in which the value of the Business in the Area of Interest is less than 25% of the value of all of the assets being acquired in such transaction, or series of related transactions, and expansion of such Business or (b) any Business in the Area of Interest for which the assets in the Area of Interest are also used, or intended to be used, to provide services primarily to customers located outside of the Area of Interest or are directly connected to assets outside of the Area of Interest that are used, or intended to be used, to provide services primarily to customers outside of the Area of Interest; provided, however, that, in the case of clause (b), any such Business in the Area of Interest shall not be an “Excluded Opportunity” if the Business referenced therein competes with any Business conducted by the Company unless the Holdings Member has provided prior written consent thereto, which shall not be unreasonably withheld, but which may be conditioned upon the parties agreeing to satisfactory arrangements to address competitive impacts.

“Exit Event” means the consummation of any of the following: (i) the sale of all or substantially all of the assets or equity interests of Jackalope LLC, (ii) the sale of all or substantially all of the assets or equity interests of the Company or (iii) a Public Offering.

“Fair Market Value” means, as to any Units, assets or other property, the fair market value, as determined in good faith by the Holdings Member and the Crestwood Member as of such time. If the Holdings Member and the Crestwood Member are unable to agree upon such determination of the Fair Market Value within 30 days after the event triggering such determination, the Holdings Member and the Crestwood Member will select an independent nationally recognized investment banking firm to determine the Fair Market Value, which determination shall be binding on the Members and the Company.

“Final Coupon Period” means the period from and after the Second Coupon Period.

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“First Coupon Period” means the period commencing on the Effective Date and ending on March 31, 2019.

“Fiscal Quarter” means each three-calendar-month period ending on March 31, June 30, September 30 or December 31 of any calendar year.

“Fiscal Year” has the meaning set forth in Section 2.06.

“Funding Member” has the meaning set forth in Section 4.03(c)(i).

“***” means any Entity Controlled, directly or indirectly, by ***.

“Holdings Member” means CN Jackalope Holdings, LLC or, as applicable, any Transferee of CN Jackalope Holdings, LLC that has become a Member in accordance with this Agreement following the direct Transfer of all of the Holding Member’s Units to such Transferee. For the purpose of calculating the amount of contributions or distributions made with respect to any Unit held at various times by more than one Holdings Member, the Holdings Member will mean the current Holdings Member and all prior Holdings Members that previously held such Unit.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

“Holdings Member Default” has the meaning set forth in Section 4.03(b).

“Holdings Member Default Period” means the period of time commencing upon the Company’s receipt of a Default Contribution pursuant to Section 4.03(b) and ending upon the redemption in full of all Series C Preferred Units pursuant to Section 4.06(a).

“Holdings Member Option Period” has the meaning set forth in Section 4.06(d).

“HSR Approval” has the meaning set forth in Section 4.07(a).

“Indemnified Losses” has the meaning set forth in Section 6.04(c).

“Indemnitee” has the meaning set forth in Section 6.04(c).

“Indirect Holdings Member Transfer” has the meaning set forth in Section 3.04(a).

“Indirect Transfer Offered Units” has the meaning set forth in Section 3.04(a).

“Indirect Transfer Offering Notice” has the meaning set forth in Section 3.04(a).

“Indirect Transfer ROFO Offer” has the meaning set forth in Section 3.04(b).

“Initial Budget” means the initial annual operating budget of the Company that is as set forth on Exhibit D.

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“Interest” means the limited liability company interest of a Member in the Company at any particular time, as evidenced initially by the Units.

“IRR” means, with respect to a Member, and subject to Section 4.05(a), the aggregate internal rate of return, calculated on a per-Unit basis, to such Member computed using the “xIRR” function of Microsoft Excel 2007 or any successor function thereto of equal effect (which for the avoidance of doubt, will take into account all contributions and distributions (including distributions and contributions with respect to Series A-2 PIK Distributions as set forth in the final sentence of Section 5.01(a)) and payments made with respect to such Units); provided, however, that, if the Crestwood Member purchases any Series A-2 Preferred Units pursuant Section 3.04, then the portion of any prior Capital Contributions or distributions attributable to such Units shall be counted as if made by and to the Crestwood Member for all purposes hereunder. A sample calculation of IRR is attached hereto as Exhibit C.

“Jackalope Interest PSA” means that certain Purchase and Sale Agreement by and between RKI Exploration & Production, LLC, the Company and the Crestwood Member, dated as of June 21, 2013.

“Jackalope LLC” means Jackalope Gas Gathering Services, L.L.C., an Oklahoma limited liability company.

“Jackalope LLC Agreement” means that certain Second Amended and Restated Limited Liability Company Agreement of Jackalope LLC, dated as of July 19, 2013, as amended or restated prior to the Effective Date and as further amended or restated from time to time.

“Jackalope LLC Interest” means any Units (as defined in the Jackalope LLC Agreement) or other equity interest in Jackalope LLC.

“Liquidation Date” means the date that the Company is dissolved and its liquidation commences in accordance with Sections 10.01 and 10.02.

“Managing Member” means the Crestwood Member.

“Marketing Agreement” means that certain Marketing Services Agreement by and between Jackalope LLC and the Company dated as of June 21, 2013.

“Material Adverse Change” means any circumstance, change or effect that, individually or taken together with other circumstances, changes or effects, is, or within the immediately following two Fiscal Quarters would be reasonably likely to be, materially adverse to the business, operations, assets, liabilities, properties, financial condition or results of operations of the Company, Jackalope LLC and their respective subsidiaries, taken as a whole.

“Maximum Holdings Member Accordion Amount” means an amount equal to $200,000,000, subject to adjustment pursuant to Section 4.02(b)(iii) if the Crestwood Member acquires Series A‑2 Preferred Units pursuant to Section 3.04.

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“Maximum Redemption Units” means a number of CEQP Units equal to ***; provided, however, that, in the event of any unit split, unit distribution, merger, spinoff, combination, exchange or conversion of units or any similar transaction or event affecting the CEQP Units, the number of Maximum Redemption Units shall be increased or reduced accordingly to account for the effect of such transaction or event.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

“Member” means any Person executing this Agreement as a Member, but does not include CEQP (unless subsequently admitted as a Member in accordance with this Agreement) or any Person who has ceased to hold any Interest in the Company or a direct or indirect transferee of Units from a Member unless and until admitted as a Member in accordance with the provisions of this Agreement.

“Member Minimum Gain” means an amount, with respect to each Member Nonrecourse Debt, equal to the Company Minimum Gain that would result if such Member Nonrecourse Debt were treated as a Nonrecourse Liability, determined in accordance with Treasury Regulations Section 1.704-2(i) with respect to “partner minimum gain.”

“Member Nonrecourse Debt” has the meaning set forth in Treasury Regulations Section 1.704-2(b)(4) for the phrase “partner nonrecourse debt.”

“Member Nonrecourse Deductions” has the meaning set forth in Treasury Regulations Section 1.704-2(i) for the phrase “partner nonrecourse deductions.”

“Midstream Project Opportunity” means an opportunity or project (a) that is either (i) a commercial proposal, prospect, solicitation, deal, transaction or opportunity relating to the Business, whether within or outside of the Area of Interest, or (ii) a capital enhancement or capital expansion, or series of related capital enhancements or capital expansions, of any existing assets of the Company or any of its Subsidiaries (including Jackalope LLC or its Subsidiaries) and (b) that involves aggregate anticipated expenditures which, when adjusted to account for the proportion thereof attributable to the Company (based on the Company’s direct or indirect ownership thereof), equal to *** or more for the Company or its Subsidiaries unless such project is to be undertaken by Jackalope LLC or its Subsidiaries prior to a Conversion, in which case it must involve aggregate anticipated expenditures which, when adjusted to account for the proportion thereof attributable to the Company (based on the Company’s direct or indirect ownership thereof), equal to *** or more.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

“MLP” has the meaning set forth in the definition of “Public Offering.”

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“National Securities Exchange” means an exchange registered with the United States Securities and Exchange Commission under Section 6(a) of the Securities Exchange Act of 1934, or any successor statute.

“Non-Funding Member” has the meaning set forth in Section 4.03(c)(i).

“Nonparty Affiliates” has the meaning set forth in Section 6.05.

“Nonrecourse Deductions” has the meaning set forth in Treasury Regulations Sections 1.704-2(b)(1) and 1.704-2(c).

“Nonrecourse Liability” has the meaning set forth in Treasury Regulations Sections 1.704-2(b)(3) and 1.752-1(a)(2).

“Offered Units” has the meaning set forth in Section 3.03(a).

“Offering Notice” has the meaning set forth in Section 3.03(b).

“Partial Redemption” means any circumstance pursuant to which the Holdings Member has exercised its right under Section 4.06(d)(ii) to cause the Crestwood Member to acquire fewer than all of the then-outstanding Series A-2 Preferred Units and Series B Preferred Units.

“Parties” means, collectively, the Members and CEQP, together with the successors and assigns of such Persons.

“Payment Cure” has the meaning set forth in Section 4.03(c)(ii).

“Permitted Affiliate” has the meaning set forth in Section 7.04.

“Permitted Transferee” means (a) with respect to a Member, any wholly owned Subsidiary of such Member or any Entity that Controls or is under common Control with such Member; (b) with respect to the Holdings Member, any proposed transferee consented to in writing by the Crestwood Member; or (c) with respect to the Crestwood Member, any proposed transferee consented to in writing by the Holdings Member.

“Permitted Utilization Arrangement” has the meaning set forth in Section 6.03(d)(ii)(B).

“Person” means any individual or Entity.

“Post-Conversion Default” has the meaning set forth in Section 4.03(c)(i).

“Post-Conversion Default Contribution” has the meaning set forth in Section 4.03(c)(i).

“Preferred Units” means the Series A-2 Preferred Units, the Series B Preferred Units, and the Series C Preferred Units, collectively.

“Prior Aggregate Accordion Amount” has the meaning set forth in Section 4.02(b)(ii).

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“Prior LLC Agreement” means that certain Amended and Restated Limited Liability Company Agreement of the Company effective as of July 19, 2013.

“Project Request” has the meaning set forth in Section 6.03(c)(i).

“Public Offering” means either (a) an initial public offering of equity securities of any of the Company, Jackalope LLC or any of their respective Subsidiaries or (b) a contribution by the Company or any of its Subsidiaries of all or substantially all of its assets, or a contribution by the Members of all or substantially all of the Interests, to a limited partnership or other entity in a master limited partnership or other structure (“MLP”), or the restructuring of the Company as an MLP, in connection with an underwritten public offering of securities of such MLP.

“Redemption Effective Date” has the meaning set forth in Section 4.06(c).

“Registration Rights Agreement” means that certain Registration Rights Agreement dated as of the Effective Date by and between CEQP and the Holdings Member.

“Rejection” has the meaning set forth in Section 6.03(d)(ii).

“Representative” has the meaning set forth in Section 7.04.

“Required Jackalope Contribution” means any Subsequent Capital Contribution or Additional Capital Contribution (each as defined in the Jackalope LLC Agreement).

“Right to Compete” has the meaning set forth in Section 6.03(a).

“ROFO Offer” has the meaning set forth in Section 3.03(c).

“RRA Suspension Right” means any applicable right of CEQP to suspend the Holdings Member’s use of a prospectus that is part of a registration statement pursuant to Section 2.03 of the Registration Rights Agreement.

“Sale Option Notice” has the meaning set forth in Section 4.06(d)(iii).

“Sale Proceeds” has the meaning set forth in Section 4.06(d)(iii).

“Sale Transaction” has the meaning set forth in Section 4.06(d)(iii).

“Second Coupon Period” means the period commencing on the first day following the First Coupon Period and ending on the last day of the eighth Fiscal Quarter thereafter.

“Secretary of State” means the Secretary of State of the State of Delaware.

“Securities Act” means the Securities Act of 1933, as amended.

“Series A-2 Coupon Amount” means (a) with respect to each Fiscal Quarter in the First Coupon Period, the product of (i) the aggregate number of Series A-2 Preferred Units outstanding as of the end of such Fiscal Quarter, and (ii) ***, (b) with respect to each Fiscal Quarter in the

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Second Coupon Period, the product of (i) the aggregate number of Series A-2 Preferred Units outstanding as of the end of such Fiscal Quarter and (ii) $*** and (c) with respect to each Fiscal Quarter in the Final Coupon Period, the product of (i) the aggregate number of Series A-2 Preferred Units outstanding as of the end of such Fiscal Quarter and (ii) ***.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

“Series A-2 Liquidation Amount” means, as of any date of determination with respect to a Series A-2 Preferred Unit, the sum of (a) the Series A-2 Preferred Unit Price and (b) an amount sufficient to provide the Holdings Member an IRR equal to *** with respect to such Series A-2 Preferred Unit as of such date of determination, taking into account all Series A-2 Quarterly Distributions (including any Series A-2 PIK Distributions and, without duplication, any distributions in respect of the Series A-2 Preferred Units pursuant to Section 5.01(b)(ii)) paid by the Company as of such date of determination.

“Series A-2 PIK Distribution” has the meaning set forth in Section 5.01(a).

“Series A-2 Preferred Unit Price” means $1.00 per Series A-2 Preferred Unit.

“Series A-2 Preferred Units” means the Series A-2 Preferred Units issued to the Holdings Member as set forth on Exhibit A as of the Effective Date and any other Units issued after the date hereof and designated as Series A-2 Preferred Units.

“Series A-2 Quarterly Distribution” has the meaning set forth in Section 5.01(a).

“Series B Liquidation Amount” means, as of any date of determination with respect to a Series B Preferred Unit, the sum of (a) the Series B Preferred Unit Price and (b) an amount sufficient to provide the Holdings Member an IRR equal to *** with respect to such Series B Preferred Unit as of such date of determination, taking into account all distributions paid to the Holdings Member in respect of such Series B Preferred Unit.

“Series B Preferred Unit Price” means $1.00 per Series B Preferred Unit.

“Series B Preferred Units” means any Units issued after the date hereof and designated as Series B Preferred Units.

“Series C Preferred Units” means any Units issued after the date hereof and designated as Series C Preferred Units.

“Series C Unit Price” means $1.00 per Series C Preferred Unit.

“Special Proceeds” means any proceeds from asset sales, debt financings or equity issuances received by the Company directly or indirectly through distributions from Jackalope LLC or any Agreed Midstream Project.

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“Subscription Agreement” means that certain Subscription and Investment Agreement for Series A-2 Preferred Units in the Company dated as of the Effective Date by and among the Company, the Crestwood Member and the Holdings Member. 

“Subsidiary” means, with respect to any specified Entity, any corporation, association, partnership or other business entity (a) which is Controlled by such Entity and (b) the outstanding equity securities entitled to more than 50% of the distributions therefrom are held, directly or indirectly, by such Entity; provided, however, that, notwithstanding the foregoing, Jackalope LLC and its Subsidiaries will be deemed Subsidiaries of the Company when used in the definition of Public Offering, Section 6.03 and Section 7.04.

“Surviving Provisions” has the meaning set forth in Section 4.06(f).

“Tag-Along Acceptance” has the meaning set forth in Section 3.10(c).

“Tag-Along Notice Period” has the meaning set forth in Section 3.10(c).

“Tag-Along Offer” has the meaning set forth in Section 3.10(a).

“Tag-Along Right” has the meaning set forth in Section 3.10(a).

“Tag-Along Transfer” has the meaning set forth in Section 3.10(a).

“Tag-Along Transfer Period” has the meaning set forth in Section 3.10(d).

“Tag Interest” has the meaning set forth in Section 3.10(a).

“Tax Advances” has the meaning set forth in Section 5.01(d).

“Tax Proceeding” has the meaning set forth in Section 8.03.

“Tax Year” has the meaning set forth in Section 2.06.

“Total Amount in Default” means, as of any time, with respect to a Non-Funding Member, an amount equal to (a) the outstanding Post-Conversion Default that the Non-Funding Member has failed to pay pursuant to the terms of this Agreement, plus (b) Collection Costs applicable thereto, plus (c) interest accrued on the amounts set forth in clause (a) and clause (b) at an annual interest rate equal to the prime rate (as published on the applicable date of determination in the “Money Rates” table of The Wall Street Journal, Eastern Edition) plus an additional 10 percentage points (or, if such rate is contrary to any applicable law, the maximum rate permitted by such applicable law) compounded quarterly from the incurrence thereof until payment in full.

“Transfer”, “Transferred” or “Transferring” means with respect to a Person, a direct disposition, sale, assignment, transfer, gift, surrender for cancellation, exchange, or the direct grant or transfer of any economic interest, voting power, or any other direct transfer of beneficial interest, whether voluntary or involuntary, by operation of law or judicial decree (and including the direct disposition, sale, assignment, transfer, gift, surrender for cancellation, exchange, or the direct grant

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or transfer of any economic interest, voting interest or any other direct transfer of beneficial interest in such Person by a Controlling Person).

“Treasury Regulations” means temporary and final Treasury Regulations promulgated under the Code, as amended from time to time.

“Units” means the Interests of the Company and includes the Series A-2 Preferred Units, the Series B Preferred Units, the Series C Preferred Units, the Common Units and any other class or series of units or other equity securities of the Company issued after the date hereof.

“U.S. GAAP” has the meaning set forth in Section 7.02(a).

1.02Construction.

(a)Whenever the context requires, the gender of all words used in this Agreement includes the masculine, feminine and neuter. If a term is defined as one part of speech (such as a noun), it shall have a corresponding meaning when used as another part of speech (such as a verb). The words “includes” or “including” shall mean “including, without limitation.” All references to Articles and Sections refer to articles and sections of this Agreement unless otherwise specified, and all references to Exhibits are to exhibits attached hereto, each of which is made a part hereof for all purposes. For the purposes of the definitions of “Adjusted Capital Account,” “Capital Account,” “Common Member,” “Interest,” “IRR,” “Public Offering,” Article V, and Article X, references to “Member” shall also refer to transferees of such Members who acquire Units in accordance with the terms of this Agreement, without intending to confer on such transferees any rights or benefits of Members. All accounting terms used herein and not otherwise defined herein will have the meanings accorded them in accordance with U.S. GAAP and, except as expressly provided herein, all accounting determinations will be made in accordance with such accounting principles in effect from time to time.

(b)Each Party acknowledges that it and its attorneys and advisers have been given an equal opportunity to negotiate the terms and conditions of this Agreement and that any rule of construction to the effect that ambiguities are to be resolved against the drafting Party or any similar rule operating against the drafter of an agreement shall not be applicable to the construction or interpretation of this Agreement.

ARTICLE IIORGANIZATION

2.01Continuation of the Company. The Company was organized as a Delaware limited liability company by the filing of the Certificate of Formation of the Company (the “Certificate”) in the office of the Secretary of State pursuant to the Act on June 4, 2013. This Agreement amends and restates in its entirety the Amended and Restated Limited Liability Company Agreement of the Company, dated as of July 19, 2013. The Members desire to continue the Company for the purposes and upon the terms and conditions hereinafter set forth. Except as provided herein, the rights, duties and liabilities of each Member shall be as provided in the Act.

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2.02Name. The name of the Company is Crestwood Niobrara LLC. Company business will be conducted in such name or such other names that comply with applicable law as the Managing Member may select from time to time.

2.03Registered Office; Registered Agent. The registered office of the Company in the State of Delaware will be the initial registered office designated in the Certificate or such other office (which need not be a place of business of the Company) as the Managing Member may designate from time to time in the manner provided by law. The registered agent of the Company in the State of Delaware will be the initial registered agent designated in the Certificate, or such other Person or Persons as the Managing Member may designate from time to time in the manner provided by law.

2.04Principal Office. The principal office of the Company will initially be at 811 Main St., Suite 3400, Houston, TX 77002, (Facsimile – (832) 519-2250) or such other location as the Managing Member may designate from time to time, which need not be in the State of Delaware. The Company may have such other offices as the Managing Member may determine appropriate.

2.05Purpose; Powers. The Company is organized for the purpose of (a) owning and acting with respect to the Jackalope LLC Interests, (b) performing the Agreed Midstream Services and (c) engaging in any other lawful act or activity for which limited liability companies may be formed under the Act to the extent that the Crestwood Member and the Holdings Member have consented in writing to the Company’s engaging in such act or activity or to the extent related to opportunities that may be pursued by the Company pursuant to Section 6.03 without the consent of the Holdings Member. The Company will have all powers permitted to be exercised by a limited liability company organized in the State of Delaware.

2.06Fiscal Year; Tax Year. The fiscal year of the Company (the “Fiscal Year”) for financial statement purposes will end on December 31st unless otherwise jointly determined by the Crestwood Member and the Holdings Member. The tax year of the Company (the “Tax Year”) for any applicable income or franchise tax purposes will end on December 31st unless otherwise required under applicable law.

2.07Foreign Qualification Governmental Filings. Prior to the Company’s conducting business in any jurisdiction other than the State of Delaware, the Managing Member will cause the Company to comply, to the extent procedures are available, with all requirements necessary to qualify the Company as a foreign limited liability company in such jurisdiction. The Managing Member is authorized, on behalf of the Company, to execute, acknowledge, swear to and deliver all certificates and other instruments as may be necessary or appropriate in connection with such qualifications. Further, each Member will execute, acknowledge, swear to and deliver all certificates and other instruments that are necessary or appropriate to qualify, or, as appropriate, to continue or terminate such qualification of, the Company as a foreign limited liability company in all such jurisdictions in which the Company may conduct business.

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2.08Term. The Company commenced on the date the Certificate was filed with the Secretary of State of the State of Delaware and will continue in existence until terminated pursuant to this Agreement.

ARTICLE IIIMEMBERS; TRANSFERS OF INTERESTS

3.01Members. As of the Effective Date, the Crestwood Member and the Holdings Member are the sole Members. The names, addresses, initial Capital Contributions and number and class of Units of the Members are set forth on Exhibit A attached hereto and incorporated herein. The Managing Member is hereby authorized and directed to complete or amend Exhibit A to reflect the admission of additional Members, the withdrawal of a Member, the change of address of a Member, the Capital Contribution of a Member, the failure of a Member to make a required Capital Contribution, the number and classes of Units of a Member and other information called for by Exhibit A. Except as set forth in Section 6.01, Members shall not have any right to act on behalf of or with respect to the Company except to the extent expressly authorized to do so by the provisions of this Agreement. Any Person admitted to the Company as a Member following the Transfer of Units from a Member shall succeed to all of the rights, duties and obligations of its transferor with respect to such Units under this Agreement.

3.02Restrictions on the Transfer of Interests.

(a)General. No Units may be Transferred (and no indirect transfer may occur) unless in accordance with Article III or in connection with a redemption of Preferred Units effected pursuant to Section 4.06, 5.01 or 10.02, and any other Transfer (or any other indirect transfer) shall be void and will not be recognized by the Company. Notwithstanding anything to the contrary in this Agreement, a Member may not Transfer less than all of its Units to any Person (whether or not a Permitted Transferee) without the prior written approval of the other Member.

(b)Conditions to Transfer. No Transfer may be effected by any Person if: (i) such Transfer would violate any restrictions in the Jackalope LLC Agreement as may be applicable, (ii) such Transfer is not in compliance with the Securities Act and all applicable state securities laws, (iii) such Transfer would cause the Company to be required to register as an “Investment Company” under the Investment Company Act of 1940, as amended, or to be treated as an association taxable as a corporation or (iv) such Transfer would cause the Company to be a publicly traded partnership for tax purposes.

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(c)Permitted Transferees. Subject to Section 3.02(a), each Member will be permitted to Transfer all, but not less than all, of its Units to a Permitted Transferee of such Member.

(d)Competitors. Notwithstanding anything to the contrary in this Agreement, without the prior written consent of the Crestwood Member, the Holdings Member shall neither (i) Transfer Units to a Competitor nor (ii) effect or permit an indirect transfer of any of its equity interests, or of any equity interests in any of its direct or indirect owners, to a Competitor.

3.03Right of First Offer on Transfer of Units.

(a)If the Holdings Member seeks to Transfer all of its Units (the “Offered Units”) (it being understood that, pursuant to Section 3.02(a), the Holdings Member may not Transfer less than all of its Units without the consent of the Crestwood Member) other than to a Permitted Transferee, then it must first make an offering of the Offered Units to the Crestwood Member in accordance with the following provisions of this Section 3.03.

(b)The Holdings Member will give written notice (the “Offering Notice”) to the Crestwood Member stating its bona fide intention to Transfer the Offered Units. The Offering Notice will constitute the Holdings Member’s offer to review bids from the Crestwood Member, which offer will remain outstanding for a period of 30 days.

(c)Upon receipt of the Offering Notice, the Crestwood Member will have 30 days to make an irrevocable offer to purchase all (but not less than all) of the Offered Units at a specified price by delivering a written notice (a “ROFO Offer”) to the Holdings Member with such details.  If the Holdings Member provides written notice within 30 days of receiving the ROFO Offer, then both parties shall be bound and the purchase of the Offered Units shall occur at the price set forth in the applicable ROFO Offer within 60 days after delivery of such acceptance.

(d)If (i) the Crestwood Member does not deliver a ROFO Offer within the aforementioned 30 day period, (ii) the Holdings Member does not elect timely to accept a ROFO Offer or (iii) the Holdings Member receives a ROFO Offer but (A) the Holdings Member does not receive payment in full of the purchase price for all of the Offered Units within the aforementioned 60 days (provided that such failure to receive payment is not the result of a breach by the Holdings Member of its obligations to consummate the sale of the Offered Units) or (B) the Transfer of all of the Offered Units does not occur for any reason, including the failure to obtain any governmental approvals, but other than due to a breach by the Holdings Member of its obligation to consummate the sale of the Offered Units, then the Holdings Member may, during the 180-day period thereafter (which period may be extended for a reasonable time not to exceed an additional 60 days to the extent reasonably necessary to obtain any required government or other third party approvals), Transfer all, but not less than all, of the Offered Units to any Person (subject to, for the avoidance of doubt, Section 3.02(b), Section 3.02(d) and Section 3.05); provided that, solely if the Holdings Member received a ROFO Offer but did not accept the ROFO Offer, such Transfer is subject to a price greater than the price set forth in the ROFO Offer and other terms and conditions in the aggregate no more favorable to the Transferee than those set forth in the ROFO Offer.

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(e)If the Holdings Member does not Transfer the Offered Units within such 180 day period (as extended in accordance with Section 3.03(d)), then the Holdings Member must again comply with the provisions set forth in this Section 3.03, to the extent applicable, prior to making any subsequent Transfer of all of its Units other than to a Permitted Transferee.

(f)The Members will take all actions as may be reasonably necessary to consummate the sale contemplated by this Section 3.03, including entering into agreements and delivering certificates and instruments and consents as may be deemed necessary or appropriate.

3.04Right of First Offer on Indirect Holdings Member Transfer.

(a)Prior to consummating or permitting the consummation of any Transfer of any equity interest in the Holdings Member or in any of its direct or indirect owners (any such Transfer, other than any Excluded Indirect Holdings Member Transfer, an “Indirect Holdings Member Transfer”), the Holdings Member must first deliver a written offer to the Crestwood Member (the “Indirect Transfer Offering Notice”) of a number of the Units it holds equal to the product of the aggregate Units it holds multiplied by the percentage of equity interests (as of immediately prior to the consummation of such the Indirect Holdings Member Transfer) in the Holdings Member held directly or indirectly by the member of the Holdings Member whose change in direct or indirect ownership would cause the Indirect Holdings Member Transfer (the number of Units represented by such product, the “Indirect Transfer Offered Units”), in accordance with the following provisions of this Section 3.04.

(b)Upon receipt of the Indirect Transfer Offering Notice, the Crestwood Member will have 30 days to make an irrevocable offer to purchase all (but not less than all) of the Indirect Transfer Offered Units at a specified price by delivering a written notice (an “Indirect Transfer ROFO Offer”) to the Holdings Member with such details.  If the Holdings Member provides written notice to the Crestwood Member accepting the Indirect Transfer ROFO Offer within 30 days of receipt of the Indirect Transfer ROFO Offer, then both Parties shall be bound and the purchase of the Indirect Transfer Offered Units shall occur at the price set forth in the applicable Indirect Transfer ROFO Offer within 60 days after delivery of such acceptance.

(c)If (i) the Crestwood Member does not deliver an Indirect Transfer ROFO Offer within the aforementioned 30 day period, (ii) the Holdings Member does not elect timely to accept an Indirect Transfer ROFO Offer or (iii) the Holdings Member receives an Indirect Transfer ROFO Offer but (A) the Holdings Member does not receive payment in full of the purchase price for all of the Indirect Transfer Offered Units within the aforementioned 60 days (provided that such failure to receive payment is not the result of a breach by the Holdings Member of its obligations to consummate the sale of the Indirect Transfer Offered Units) or (B) the Indirect Holdings Member Transfer does not occur for any reason, including the failure to obtain timely any required governmental approvals, but other than due to a breach by the Holdings Member of its obligation to consummate the sale of the Indirect Transfer Offered Units, then the Holdings Member may, during the 180-day period thereafter (which period may be extended for a reasonable time not to exceed an additional 60 days to the extent reasonably necessary to obtain any required government or other third party approvals), consummate or permit the consummation of such Indirect Holdings Member Transfer (subject to, for the avoidance of doubt, Section 3.02(b), Section 3.02(d) and

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Section 3.05); provided that, solely if the Holdings Member received but did not accept an Indirect Transfer ROFO Offer, then the value ascribed to the Indirect Transfer Offered Units in the Indirect Holdings Member Transfer must be equal or greater than the price set forth in the Indirect Transfer ROFO Offer.

(d)If the applicable Indirect Holdings Member Transfer does not occur within such 180 day period (as extended in accordance with Section 3.04(c)), then the Holdings Member must again comply with the provisions set forth in this Section 3.04, to the extent applicable, prior to consummating or permitting the consummation of another Indirect Holdings Member Transfer. 

(e)The Members will take all actions as may be reasonably necessary to consummate the sale contemplated by this Section 3.04, including entering into agreements and delivering certificates and instruments and consents as may be deemed necessary or appropriate.

3.05Requirements Applicable to All Transfers. Except in connection with a redemption of Preferred Units effected pursuant to Sections 4.06, 5.01 or 10.02, if requested by any Member, a Member Transferring Units must deliver to the Company an opinion of counsel, in form and substance reasonably satisfactory to the Managing Member, to the effect that such Transfer is either exempt from the requirements of the Securities Act and the applicable securities laws of any state or that such registration requirements have been complied with. Any Person acquiring Units from a Member shall be obligated to execute an adoption agreement in a form reasonably satisfactory to the Managing Member (whether such Transfer resulted by operation of law or otherwise). Without limiting the foregoing, even if any such Person fails to execute such an adoption agreement, such Person and such Units shall nevertheless be subject to this Agreement in the same manner as the Member holding such Units immediately prior to such Transfer. The Managing Member will determine in its reasonable discretion whether the foregoing requirements have been satisfied and may, in its reasonable discretion, determine to waive any such requirements to the extent permitted by applicable law.

3.06Additional Members. In connection with any Transfer or issuance of Interests permitted hereunder, additional Persons may be admitted to the Company as Members and Units may be created and issued to such Persons as determined by the Managing Member on such terms and conditions as the Managing Member may determine at the time of admission which may include making a Capital Contribution, subject, solely to extent applicable pursuant to Section 6.02(a)(iv) or (ix), to the approval by the Holdings Member. As a condition to being admitted as a Member of the Company, any Person must agree to be bound by the terms of this Agreement by executing and delivering a counterpart signature page to this Agreement, and must make the representations and warranties set forth in Section 3.07 to the extent applicable as of the date of such Person’s admission to the Company. To the extent legally permissible and reasonably practicable, the Crestwood Member shall provide such information in its possession, access and cooperation, in each case at the Holding Member’s sole expense, as reasonably requested by the Holdings Member in connection with any proposed, bona fide Transfer of Preferred Units or Common Units permitted by this Agreement by the Holdings Member to a purchaser of such Preferred Units or Common Units;

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providedhowever, in no event shall the Crestwood Member be required to (i) take any action to obtain or provide information or access that it does not have in its possession or have the right to request, in each case at the time of such request by the Holdings Member, (ii) take any action that the Crestwood Member determines in its reasonable judgment would result in the loss of the protection of any attorney-client or other privilege held by any Person or the breach of any written agreement of the Company, the Crestwood Member or any of their respective Affiliates or (iii) initiate, or threaten to initiate, any action, proceeding or litigation in order to enforce any rights that the Company has to receive access in respect of the Jackalope LLC Interests or any Agreed Midstream Project.

3.07Representations and Warranties. Each Party hereby represents and warrants to the Company that:

(a)such Party has full power and authority to enter into this Agreement and to perform its obligations hereunder;

(b)the execution, delivery and performance of this Agreement do not conflict with any other agreement or arrangement to which such Party is a party or by which it is or its assets are bound; and

(c)such Party, if such Party is a Member, is and will be acquiring its Interest in the Company for investment purposes only for its own account and not with a view to the distribution, reoffer, resale, or other disposition not in compliance with the Securities Act and applicable state securities laws.

3.08Liability to Third Parties. No Member will have any personal liability for any obligations or liabilities of the Company, whether such liabilities arise in contract, tort or otherwise, except to the extent that any such liabilities or obligations are expressly assumed in writing by such Member.

3.09Representations and Warranties Made by Crestwood Member. The Crestwood Member hereby represents and warrants that the Company is a limited liability company duly organized, validly existing and in good standing under the laws of the State of Delaware and that, except in connection with (a) its formation and organization, (b) the negotiation and execution of the Prior Agreement, this Agreement, the Marketing Agreement and the transactions contemplated by the Jackalope Interest PSA or (c) its ownership interests in Jackalope LLC, the Company has not engaged in any business activities, acquired any assets or incurred any liabilities since its formation on June 4, 2013 under the Act.

3.10Tag-Along Right.

(a)Following a Conversion, if the Crestwood Member desires to Transfer, or effect or permit an indirect transfer of, all or any portion of its Units in the Company other than to an Affiliate and other than pursuant to an Excluded Indirect Crestwood Transfer, then (i) the Holdings Member shall have the right (but not the obligation) (the “Tag-Along Right,” and the Units held by the Crestwood Member, the “Tag Interest”) to participate in the proposed transaction (the “Tag-

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Along Transfer”) and (ii) the Crestwood Member shall make an offer (a “Tag-Along Offer”) by an irrevocable written notice to the Holdings Member, to include in the Tag-Along Transfer, on terms and conditions set forth in such notice (which must be at least as favorable to the Holdings Member as to the Crestwood Member), a number of the Holdings Member’s Units in accordance with the provisions of this Section 3.10.

(b)Pursuant to the Tag-Along Right, (i) in the case of a Tag-Along Transfer that is a Transfer of Units, the Holdings Member shall have the right to Transfer in such Tag-Along Transfer the same percentage of its Units as the percentage of the Crestwood Member’s aggregate Units that the Crestwood Member is proposing to Transfer and (ii) in the case of a Tag-Along Transfer that is an indirect transfer, the Holdings Member shall have the right to Transfer in such Tag-Along Transfer the same percentage of its Units as the percentage of equity interests in the Crestwood Member being directly or indirectly transferred in such Tag-Along Transfer. If the Crestwood Member is unable to cause the transferee to purchase all of the Units proposed to be sold directly or indirectly by the Crestwood Member and the Holdings Member, then the Crestwood Member and the Holdings Member shall reduce, on a pro rata basis, the amount of such Units that each otherwise would have sold so as to permit the Crestwood Member and the Holdings Member to sell directly or indirectly the number of Units (determined in accordance with such pro rata basis) that the proposed transferee is willing to purchase.

(c)The Tag-Along Offer may be accepted by the Holdings Member at any time within 30 days after the Holdings Member’s receipt of the Tag-Along Offer (such period, the “Tag-Along Notice Period”), which acceptance must be made by delivery of a written notice indicating such acceptance to the Crestwood Member (such notice, the “Tag-Along Acceptance”). If the Holdings Member exercises the Tag-Along Right, then the Holdings Member’s Units shall be purchased on the same terms and conditions as the Tag Interest (provided, that in the case of a Tag-Along Transfer involving the direct or indirect transfer of an equity interest in which the equity interest being transferred represents an ownership interest in anything other than an indirect ownership interest in the Crestwood Member’s Units, then the purchase price to be paid in respect of the Holdings Member’s Units shall equal the Fair Market Value thereof); provided that any representations and warranties relating specifically to any Member shall be made only by such Member.

(d)If (i) the Holdings Member does not deliver a Tag-Along Acceptance within the Tag-Along Notice Period or (ii) the Tag-Along Transfer fails to close for any reason other than due to a breach by the Crestwood Member of its obligation to consummate the Tag-Along Transfer, then the Crestwood Member (or the applicable indirect transferor) may, during the 180-day period following the expiration of the Tag-Along Notice Period (which period may be extended for a reasonable time not to exceed an additional 60 days to the extent reasonably necessary to obtain any required government or other third party approvals) (the “Tag-Along Transfer Period”) consummate the Tag-Along Transfer with only the Tag Interest; provided that, in either such case, the Tag-Along Transfer is subject to a price no greater than the price set forth in the Tag-Along Offer and on other terms and conditions in the aggregate no more favorable to the transferee than those set forth in the Tag-Along Offer.

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(e)If the Crestwood Member (or the applicable indirect transferor) does not sell the Tag Interest in the Tag-Along Transfer Period, the Crestwood Member must again comply with the provisions set forth in this Section 3.10, to the extent applicable, prior to making any subsequent sale of all or any portion of its Units or effecting or permitting any indirect transfer of all or any portion of Units.

ARTICLE IVCAPITAL CONTRIBUTIONS; REDEMPTIONS OF PREFERRED UNITS

4.01Interests. Each Member’s Interest in the Company will be represented by its Capital Account and by Units issued by the Company to such Member. The classes of authorized Units as of the Effective Date are the Series A-2 Preferred Units, the Series B Preferred Units, the Series C Preferred Units and the Common Units (it being understood that all of the Series A Preferred Units issued under the Prior LLC Agreement were redeemed and extinguished on the Effective Date). Except as expressly set forth herein, the Units have no voting rights and do not confer the right to vote on matters related to the Company or otherwise. The obligations of each Member hereunder shall be several and not joint, and no Member shall be obligated to make any of the Capital Contributions of another Member.

4.02Capital Contributions.

(a)Initial Capital Contributions. On the Effective Date, all of the Series A Preferred Units issued under the Prior LLC Agreement were redeemed and extinguished and the Company issued the number of Series A-2 Preferred Units set forth opposite the Holdings Member’s name on Exhibit A, and the aggregate amount of Capital Contributions made by the Holdings Member in respect of such Series A-2 Preferred Units is also set forth opposite the Holdings Member’s name on Exhibit A. As of the Effective Date, the Crestwood Member has contributed $139,906,373 to the Company and holds the number of Common Units set forth opposite the Crestwood Member’s name on Exhibit A.

(b)Pre-Conversion Capital Contributions by Members.

(i)Until the earlier to occur of (A) the fourth anniversary of the Effective Date and (B) a Conversion, the Crestwood Member may, in its sole discretion, elect to require the Holdings Member to fund any Agreed Midstream Project as set forth in this Section 4.02(b)(i). Any such election shall be exercised by delivering a written notice in compliance with Section 4.02(d) to the Holdings Member. If the Crestwood Member makes such an election and delivers such notice, then, on the funding dates set out in such notice, the Holdings Member will be required to fund 49.99% of all amounts required in connection with the Agreed Midstream Project (including any Required Jackalope Contribution in connection with an Agreed Midstream Project, but subject to any approvals or other limitations as may be set out in the applicable Project Request) by making Capital Contributions to the Company (each such required contribution, an “Accordion Capital Contribution”), and the Crestwood Member will be required to fund the balance of all amounts required in connection with such Agreed Midstream Project by making Capital Contributions to the Company (each such required contribution, a “Crestwood Additional

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Capital Contribution”). Notwithstanding anything herein to the contrary, if any Accordion Capital Contribution or Crestwood Additional Capital Contribution with respect to an Agreed Midstream Project has been approved but not fully funded prior to the earlier to occur of the fourth anniversary of the Effective Date and Conversion, then in each case such Accordion Capital Contribution or Crestwood Additional Capital Contribution will continue to be required to be made (and Section 4.02(b)(i)(A) or (B), as applicable, shall be disregarded with respect thereto) except that, in the case of a Conversion, instead of issuing Series A-2 Preferred Units to any Member that is funding an Accordion Capital Contribution (or Common Units based on the Common Unit Price in respect of Crestwood Additional Capital Contributions), instead the Company shall issue to each Member that is so funding a number of Common Units equal to the amount of such Accordion Capital Contribution or Crestwood Additional Capital Contribution made by such Member (as the case may be) divided by the Fair Market Value of a Common Unit. In the event that, prior to a Conversion, the Crestwood Member (i) does not elect to require an Accordion Capital Contribution in respect of an Agreed Midstream Project, (ii) causes the Company to pursue a Midstream Project Opportunity undertaken by Jackalope LLC or its Subsidiaries pursuant to Section 6.03(d)(ii)(A) or (iii) causes the Company to pursue a De Minimis Midstream Project Opportunity pursuant to Section 6.03(e), any Capital Contribution required in connection therewith shall be considered a Crestwood Additional Capital Contribution.

(ii)Notwithstanding the foregoing, once the Holdings Member has made aggregate Accordion Capital Contributions at least equal to the Maximum Holdings Member Accordion Amount, the Holdings Member will have no further obligation to make any further Accordion Capital Contributions to the Company, and the Holdings Member shall not be required to make Accordion Capital Contributions at any time at which either any Series B Preferred Units are outstanding or any Series A-2 Quarterly Distribution required to have been distributed in cash has not been paid in full in accordance with Section 5.01(a). For the avoidance of doubt, (I) if (x) the Crestwood Member makes an election to require the Holdings Member to fund any Agreed Midstream Project at a time at which the aggregate amount of all Accordion Capital Contributions as of immediately prior to such election (the “Prior Aggregate Accordion Amount”) does not exceed the Maximum Holdings Member Accordion Amount and (y) the excess of the Maximum Holdings Member Accordion Amount minus the Prior Aggregate Accordion Amount is an amount less than 49.99% of all amounts required in connection with an Agreed Midstream Project, then the Accordion Capital Contribution of the Holdings Member pursuant to such election shall be reduced to such excess amount and the Crestwood Additional Capital Contribution relating to such Agreed Midstream Project shall be increased accordingly and (II) the Maximum Holdings Member Accordion Amount shall not be reduced by any Series A-2 PIK Distribution. Immediately upon receipt of any Accordion Capital Contribution by the Company, except as provided in the penultimate sentence of Section 4.02(b)(i), the Company shall issue to the Holdings Member a number of Series A-2 Preferred Units equal to the amount of such Accordion Capital Contribution divided by the Series A-2 Preferred Unit Price. Immediately upon receipt of any Crestwood Additional Capital Contribution by the Company, except as provided in the penultimate sentence of Section 4.02(b)(i), the Company shall issue to the

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Crestwood Member a number of Common Units equal to the amount of such Crestwood Additional Capital Contribution divided by the Common Unit Price.

(iii)The Parties acknowledge and agree that, immediately following any acquisition of Series A-2 Preferred Units by the Crestwood Member pursuant to Section 3.04, all obligations of the “Holdings Member” set forth in the foregoing provisions of Section 4.02(b) to fund Accordion Capital Contributions shall become obligations of both the Crestwood Member and the Holdings Member, and such obligations shall be performed pro rata in proportion to each of such Member’s respective ownership of outstanding Series A-2 Preferred Units, and the Maximum Holdings Member Accordion Amount shall be reduced proportionately to adjust for the percentage of Series A-2 Preferred Units no longer held by the Holdings Member. Immediately upon the receipt of any Accordion Capital Contribution by the Crestwood Member, except as provided in the penultimate sentence of Section 4.02(b)(i), the Company shall issue to the Crestwood Member a number of Series A-2 Preferred Units equal to the amount of such Accordion Capital Contribution made by the Crestwood Member divided by the Series A-2 Preferred Unit Price.

(iv)Before a Conversion, in connection with any capital requirements of the Company, other than an Agreed Midstream Project, the Managing Member shall fund the amount of such capital requirement (A) out of the operating cash flows of the Company (but only to the extent of Available Cash) and/or (B) by drawing on a credit facility approved in accordance with Section 6.02(a)(xvi), as applicable, except to the extent that the Managing Member has determined that it is commercially reasonable to fund all or a portion of such capital requirements with Capital Contributions from the Crestwood Member. To the extent that the Managing Member has determined to fund any such capital requirements pursuant to clauses (A) or (B) above in this Section 4.02(b)(iv), and such funding sources are not sufficient to satisfy the full capital requirement, the remaining amount of such capital requirement shall be made by the Crestwood Member in exchange for a number of Common Units equal to the amount of such contribution divided by the Common Unit Price.

(c)Post-Conversion Capital Call For Capital Contribution. Without limiting the obligations of the Members pursuant to the penultimate sentence of Section 4.02(b)(i), subject to Section 6.02 and Section 6.03, at any time after a Conversion, the Managing Member may request that the Members make additional Capital Contributions by issuing a notice to the Members in accordance with Section 4.02(d). Each Member shall have the right, but not the obligation, to elect to make Capital Contributions pursuant to such a notice. Within 30 days after the receipt of such notice, each Member shall notify the Managing Member whether it elects to fund its pro rata portion of the requested Capital Contribution. If any Member does not notify the Managing Member of such election within such 30 days, then such Member will be deemed to have elected not to fund its pro rata portion, and the Member that has elected to fund will have the option to fund the entire Capital Contribution amount and/or may allow another Person to make all or any portion of the Capital Contribution.

(d)Capital Call Notices. Prior to any request for Capital Contributions, the Managing Member shall send each Member a written notice setting forth (i) in reasonable detail

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the Agreed Midstream Project or other project giving rise to such request for Capital Contributions, (ii) the amount of such Capital Contribution requested (and, if applicable, the amount of any future anticipated requests for Capital Contributions in connection with such Agreed Midstream Project or other project), (iii) the portion of such requested Capital Contribution that each Member is obligated or requested to contribute, (iv) if after Conversion, the Fair Market Value of the Common Units to be issued in exchange for such Capital Contributions and (v) the date on which such Capital Contributions must occur, which shall in each case be no less than 30 days after the date of such notice.

4.03Funding Defaults

(a)Failure of the Crestwood Member to Make a Crestwood Additional Capital Contribution. If, prior to a Conversion, the Crestwood Member fails to fund 100% of any Crestwood Additional Capital Contribution when due and fails to cure such default within three Business Days after such due date (any such failure, a “Deficiency Event”), then the Company shall promptly, but in no event later than three Business Days after the due date for such Crestwood Additional Capital Contribution, provide written notice of such failure to the Holdings Member, and the Holdings Member shall have the option, in its sole discretion and as its sole and exclusive remedy hereunder, to fund the amount of such deficiency, including any interest payable to Jackalope LLC pursuant to Section 3.1(d) of the Jackalope LLC Agreement as a result of such deficiency (any such amount funded by the Holdings Member, a “Deficiency Contribution”). Immediately upon receipt of any Deficiency Contribution by the Company, the Company shall issue to the Holdings Member a number of Series B Preferred Units equal to the amount of such Deficiency Contribution divided by the Series B Preferred Unit Price. A Deficiency Event shall not relieve the Crestwood Member of its obligation to make any Crestwood Additional Capital Contributions subsequent thereto.

(b)Failure of Holdings Member to Make an Accordion Capital Contribution. If, prior to a Conversion, the Holdings Member fails to fund 100% of any Accordion Capital Contribution when due and fails to cure such default within three Business Days after such due date (any such failure, a “Holdings Member Default”), then the Company shall promptly, but in no event later than three Business Days after the due date for such Accordion Capital Contribution, provide written notice of such failure to the Crestwood Member, and the Crestwood Member shall have the option, in its sole discretion and as its sole and exclusive remedy hereunder, to fund the amount of such deficiency, including any interest due and payable to Jackalope LLC pursuant to Section 3.1(d) of the Jackalope LLC Agreement as a result of such deficiency (any such amount funded by the Crestwood Member, a “Default Contribution”). Immediately upon receipt of any Default Contribution by the Company, the Company shall issue to the Crestwood Member a number of Series C Preferred Units equal to the amount of such Default Contribution divided by the Series C Unit Price. A Holdings Member Default shall not relieve the Holdings Member of its obligation to make any Accordion Capital Contributions subsequent thereto.

(c)Failure of a Member to Fund a Post-Conversion Capital Contribution.

(i)If, following a Conversion, either Member elects to fund in response to a request for Capital Contributions (or is required to fund pursuant to the penultimate sentence of Section 4.02(b)(i)) but fails to fund such amount when due, and in either case,

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fails to cure such default within three Business Days after such due date (such Member, a “Non-Funding Member,” and any such failure, a “Post-Conversion Default”), then the Company shall promptly, but in no event later than three Business Days after the due date for such Capital Contribution, provide written notice of such failure to the non-defaulting Member, and such non-defaulting Member shall have the option, in its sole discretion, to fund the amount of such Post-Conversion Default, including any interest due and payable to Jackalope LLC pursuant to Section 3.1(d) of the Jackalope LLC Agreement as a result of such deficiency (any such amount funded by such Member in accordance with this Section 4.03(c)(i), a “Post-Conversion Default Contribution”). Any Member that funds a Post-Conversion Default Contribution in accordance with this Section 4.03(c) is referred to herein as a “Funding Member” and shall be entitled to certain amounts as set forth in this Section 4.03(c).

(ii)If a Post-Conversion Default Contribution is made by the Funding Member, and the Total Amount in Default with respect thereto is paid by or on behalf of a Non-Funding Member to the Company within 30 days after the applicable Post-Conversion Default (a “Payment Cure”, and such 30 day period, the “Cure Period”), then the Company shall pay to the Funding Member, within five Business Days of receipt, an amount equal to the Total Amount in Default less any distributions already paid to the Funding Member pursuant to Section 4.03(c)(iii).

(iii)From and after a Post-Conversion Default, the applicable Non-Funding Member’s right to receive distributions pursuant to this Agreement shall be suspended and paid to the Funding Member or retained by the Company, as applicable, until the earlier of a Payment Cure and the time at which such aggregate distributions withheld from the Non-Funding Member (together with any additional contributions made by the Non-Funding Member pursuant to the following sentence) equal either (x) if a Funding Member funded the Post-Conversion Default Contribution, *** of the Total Amount in Default or (y) if no Funding Member funded the Post-Conversion Default Contribution, the amount of the Post-Conversion Default Contribution plus any interest owed or distributions foregone pursuant to the Jackalope LLC Agreement as a result of any failure to make any Capital Contribution to Jackalope LLC as and when due plus interest at a *** interest rate on the sum of the foregoing amounts in this clause (y). Notwithstanding the foregoing, a Non-Funding Member shall have the right, at any time prior to the suspension of distributions referenced above terminating, to accelerate the date on which such suspension terminates by paying to the Company such amounts as are necessary to achieve the threshold identified in foregoing clause (x) or (y), as applicable, and if it does so, then such thresholds will be deemed satisfied and such funds shall be paid to the Funding Member or retained by the Company, as applicable, and then such suspension of distributions shall immediately cease.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

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(iv)A Post-Conversion Default shall not relieve the Non-Funding Member of its obligation to fund its pro rata portion of any other Capital Contributions that it elected or is required to fund.

4.04Withdrawal or Return of Capital. Except as provided in this Agreement, including Sections 4.06 and 5.01, no Member is entitled to the return of or has the right to withdraw any part of its Capital Contribution from the Company prior to its liquidation and termination pursuant to Article X hereof. No Member is entitled to be paid interest in respect of either its Capital Account or its Capital Contributions. Any unrepaid Capital Contribution is not a liability of the Company or of the other Members. A Member is not required to contribute or to lend any cash or property to the Company to enable the Company to return any other Member’s Capital Contributions.

4.05Further Contributions. (a) If the Company becomes obligated to make an indemnification payment (or to expend funds, or to make payments to third parties) pursuant to the Subscription Agreement with respect to Losses (as defined in the Subscription Agreement) and it does not at such time have sufficient Available Cash after payment of all amounts otherwise due or owing at such time, then the Crestwood Member shall promptly make a contribution of immediately available funds into the Company in an amount sufficient to permit the Company promptly to make such indemnification payment (or to pay such expense, or to pay any such third party) in full, and the Company shall promptly make such indemnification payment (or pay such expense, or pay any such third party) upon receipt; provided, however, that, following a Conversion, indemnification payments (as well as payments of expenses and payments to third parties) pursuant to the Subscription Agreement with respect to Losses (as defined in the Subscription Agreement) shall not be made by the Company from Available Cash but instead the Crestwood Member shall promptly make a contribution of immediately available funds into the Company in an amount sufficient to make the full amount of such indemnification or other payments in full from such contributed funds. Notwithstanding anything else in this Agreement to the contrary, (i) any such indemnification payment made by the Company from Available Cash (or any funds expended by the Company, or paid by the Company to a third party from a source other than a contribution by the Crestwood Member to the Company pursuant to this Section 4.05(a)) with respect to Losses (as defined in the Subscription Agreement) giving rise to such indemnification obligation shall be deemed a distribution to the Crestwood Member for purposes of the definition of Adjusted Capex Amount and shall not be a distribution to the Holdings Member for any purpose under this Agreement and (ii) any contribution by the Crestwood Member to the Company to permit the Company to make such an indemnification payment (or to fund such an expense, or such a payment to a third party) with respect to Losses (as defined in the Subscription Agreement) shall not be a Capital Contribution for the purposes of the definition of Adjusted Capex Amount or for the purposes of Section 5.01(b)(ii)(A). Without any effect on the foregoing, if the Crestwood Member makes any contribution to the Company pursuant to this Section 4.05(a), then the Company shall (I) issue to the Crestwood Member a number of Common Units equal to the quotient obtained by dividing the amount of such contribution by either (x) the Common Unit Price, if such contribution occurs prior to a Conversion or (y) the Fair Market Value per Common Unit, if such contribution occurs following a Conversion

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and (II) if such contribution by the Crestwood Member occurs following a Conversion, issue to the Holdings Member a number of Common Units equal to the product of the number of Common Units issuable to the Crestwood Member pursuant to the foregoing clause (I)(y)multiplied by a fraction, the numerator of which is the number of Common Units held by the Holdings Member as of immediately prior to such contribution and the denominator of which is the number of Common Units held by the Crestwood Member as of immediately prior to such contribution. For the avoidance of doubt, the issuance of Common Units as contemplated by the preceding sentence shall not be a Capital Contribution for purposes of, and shall not be subject to, Section 4.02 or Section 4.03, and neither Member shall be required to make any contributions with respect thereto (other than the obligation of the Crestwood Member expressly referenced in this Section 4.05).

(b)     Except as otherwise specifically provided in this Agreement, no further Capital Contributions will be required from any Member without such Member’s prior written consent, and no Member shall have any obligation to restore any deficit balance in such Member’s Capital Account.

4.06Redemption of Preferred Units.

(a)Deficiency Preferred Units. Following the issuance of any Deficiency Preferred Units and until the earlier of the date that such Deficiency Preferred Units have been redeemed in full in accordance with this Agreement, 100% of all Adjusted Available Cash on hand and thereafter received by the Company shall immediately be paid over to the Holdings Member and the Crestwood Member, pro rata in accordance with their respective holdings of Deficiency Preferred Units, to redeem all outstanding Deficiency Preferred Units; provided that (i) a Series B Preferred Unit will be redeemed pursuant to the foregoing clause upon the Holdings Member’s receipt of cash in respect of such Series B Preferred Unit in the amount required to provide the Holdings Member an IRR equal to *** with respect to such Series B Preferred Unit and (ii) a Series C Preferred Unit will be redeemed pursuant to the foregoing clause upon the Crestwood Member’s receipt of cash in respect of such Series C Preferred Unit in the amount required to provide the Crestwood Member an IRR equal to *** with respect to such Series C Preferred Unit. Without limiting the generality of the foregoing, the right of the Holdings Member and the Crestwood Member to have any Deficiency Preferred Units redeemed pursuant to this Section 4.06(a) will be senior in right of payment to all distributions to Members or redemptions of Units by the Company.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

(b)Crestwood Change of Control; Company Change of Control. Within five Business Days following a Crestwood Change of Control or a Company Change of Control, in each case, if any, the Holdings Member may elect by written notice to the Crestwood Member (the “Change of Control Redemption Notice”) to require the Company to redeem from the Holdings Member all then-outstanding Series A-2 Preferred Units and Series B Preferred Units. Within five Business Days following delivery of the Change of Control Redemption Notice, the Crestwood Member shall deliver written notice to the Holdings Member (the “Consideration Election Notice”)

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indicating whether (i) the Company has elected to redeem the then-outstanding Series A-2 Preferred Units and Series B Preferred Units for cash, (ii) in lieu of such redemption, the Crestwood Member will acquire from the Holdings Member the then-outstanding Series A-2 Preferred Units and Series B Preferred Units through the issuance to the Holdings Member or its designee as consideration a number of CEQP Units, valued at the CEQP Unit Price calculated as of the date of such Crestwood Change of Control or Company Change of Control, or (iii) it elects to effect a combination of the actions described in clauses (i) and (ii) above, in any case, in an amount per Series A-2 Preferred Unit equal to the Change of Control Redemption Price and an amount per Series B Preferred Unit equal to the Change of Control Redemption Price; provided, however, that (A) the options set forth in the foregoing clauses (ii) and (iii) shall not be available at any time at which an RRA Suspension Right would be, or would reasonably likely to be, exercisable by CEQP pursuant to the Registration Rights Agreement if the Holdings Member were to exercise a demand registration right pursuant to Section 2.03 of the Registration Rights Agreement immediately following the issuance of CEQP Units to the Holdings Member, (B) the number of CEQP Units issued pursuant to this Section 4.06(b) shall not exceed the Maximum Redemption Units (it being acknowledged and agreed that the issuance of the Maximum Redemption Units, if applicable, shall redeem in full all of the then-outstanding Series A-2 Preferred Units and Series B Preferred Units and no further cash or other consideration shall be required to be paid in connection therewith) and (C) CEQP shall comply with its obligations under the Registration Rights Agreement with respect to such CEQP Units so issued. The closing of any redemption or acquisition pursuant to this Section 4.06(b) shall occur no later than the tenth Business Day following the delivery of the Change of Control Redemption Notice; provided, however, that in the event that the Crestwood Member fails to deliver a Consideration Election Notice prior to the fifth Business Day following the delivery of the Change of Control Redemption Notice, the Company shall be deemed to have elected to redeem the then-outstanding Series A-2 Preferred Units and Series B Preferred Units pursuant to this Section 4.06(b) in cash and the closing for such redemption shall occur no later than the tenth Business Day following the delivery of the Change of Control Redemption Notice.

(c)Crestwood Option for Redemption. At any time following the fourth anniversary of the Effective Date, subject to Section 4.06(a) in respect of the redemption of Deficiency Preferred Units, by delivery of 10 Business Days’ prior written notice to each of the Company and the Holdings Member, the Crestwood Member may elect to cause the Company to redeem some or all of the then-outstanding Series A-2 Preferred Units effective as of the 10th Business Day following delivery of such notice (the “Redemption Effective Date”) for an amount per Series A-2 Preferred Unit equal to the product of (i) *** and (ii) the Series A-2 Liquidation Amount calculated as of close of business on the day prior to the Redemption Effective Date; provided, that such aggregate amount payable may be satisfied by the Crestwood Member’s (1) causing the Company to redeem some or all of the then-outstanding Series A-2 Preferred Units in exchange for the Company’s paying the Holdings Member cash, (2) acquiring some or all of the then-outstanding Series A-2 Preferred Units by the issuance to the Holdings Member or its designee as consideration a number of CEQP Units, valued at the CEQP Unit Price calculated as of close of business on the day prior to the Redemption Effective Date, or (3) acquiring some or all of the then-outstanding Series A-2 Preferred Units by a combination of the actions described in clauses (1) and (2) above, subject to compliance with the Registration Rights Agreement; provided, however,that no redemption or acquisition of fewer than all of the then-outstanding Series A-2 Preferred Units

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owned by the Holdings Member may be effected pursuant to this Section 4.06(c) unless the sum of the aggregate cash paid to the Holdings Member plus the aggregate value of the CEQP Units issued to the Holdings Member in such redemption or acquisition pursuant to this Section 4.06(c) equals or exceeds ***; providedfurther, that (A) the options set forth in the foregoing clauses (2) and (3) shall not be available (x) if the aggregate value of the CEQP Units issued to the Holdings Member in such redemption or acquisition does not equal or exceed *** or (y) at any time at which an RRA Suspension Right would be, or would reasonably likely to be, exercisable by CEQP pursuant to the Registration Rights Agreement if the Holdings Member were to exercise a demand registration right pursuant to Section 2.03 of the Registration Rights Agreement immediately following the issuance of CEQP Units to the Holdings Member and (B) CEQP shall comply with its obligations under the Registration Rights Agreement with respect to such CEQP Units so issued; providedfurther, that such notice shall state the number of Series A-2 Preferred Units and/or Series B Preferred Units that the Crestwood Member has elected to cause the Company to redeem.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

(d)Holdings Member Option Period. From and after the fifth anniversary of the Effective Date and until such time as there are no Series A-2 Preferred Units or Series B Preferred Units outstanding (such period, the “Holdings Member Option Period”), subject to Section 4.06(a) in respect of the redemption of Deficiency Preferred Units and subject also to Section 4.06(e), the Holdings Member may elect at any time when there are no Series C Preferred Units outstanding for one or more of the following three options by delivery of written notice to the Crestwood Member stating the chosen option and the anticipated closing date for the applicable transaction for such chosen option, and, no later than two Business Days following the delivery of such notice to the Crestwood Member by the Holdings Member, the Crestwood Member shall deliver a written notice to the Holdings Member indicating whether an RRA Suspension Right would be, or would reasonably likely to be, exercisable by CEQP (and also indicating the anticipated period of suspension) pursuant to the Registration Rights Agreement if the Holdings Member were to exercise a demand registration right pursuant to Section 2.03 of the Registration Rights Agreement immediately following the issuance of CEQP Units to the Holdings Member, providedthat, if the Holdings Member’s election notice opted for clause (ii) below and the Crestwood Member’s notice indicates that an RRA Suspension would be, or would reasonably likely to be, so exercisable, then the Holdings Member shall have the right, exercisable in its sole discretion by delivery of another written notice to the Crestwood Member, to elect to amend its prior election notice in order to choose an alternative option set forth below or to delay the issuance of CEQP Units until the expiration of the suspension period:

(i)for 100% of all Adjusted Available Cash on hand and thereafter received by the Company to immediately be paid over to the Members owning Class A-2 Preferred Units to redeem all outstanding Series A-2 Preferred Units; provided that (A) a Series A-2 Preferred Unit will be redeemed pursuant to this Section 4.06(d)(i) upon the applicable Member’s receipt of cash in respect of such Series A-2 Preferred Unit in the amount required to provide such Member an IRR equal to *** with respect to such Series A-2 Preferred Unit, taking into account all Series A-2 Quarterly Distributions (including

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any Series A-2 PIK Distributions) paid by the Company as of such date of determination, (B) without limiting the generality of the foregoing, and notwithstanding anything to the contrary in this Agreement, the right of the Holdings Member to have the Series A-2 Preferred Units redeemed pursuant to this Section 4.06(d)(i) will be senior in right of payment to all distributions to Members or redemptions of Units by the Company, other than in respect of the redemption of Deficiency Preferred Units pursuant to Section 4.06(a) or redemption of Series A-2 Preferred Units held by the Crestwood Member pursuant to this Section 4.06(d)(i) and (C) if the Holdings Member elects for this Section 4.06(d)(i), then, following such election, the Holdings Member shall have the right to elect for Section 4.06(d)(ii) or Section 4.06(d)(iii) at a later time; or

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

(ii)to require the Crestwood Member to acquire, on or before the tenth Business Day following the Holdings Member’s delivery of such notice, some or all of the then-outstanding Series A-2 Preferred Units and Series B Preferred Units in exchange for the issuance to the Holdings Member or its designee as consideration the number of CEQP Units, valued at the CEQP Unit Price, required to provide to the Holdings Member an IRR equal to (A) *** on each Series A-2 Preferred Unit so purchased, taking into account all Series A-2 Quarterly Distributions (including any Series A-2 PIK Distributions) paid by the Company as of such date of determination, and (B) *** on each Series B Preferred Unit so acquired; provided, however, that (I) in no event shall the number of CEQP Units issued pursuant to this Section 4.06(d)(ii) exceed the Maximum Redemption Units (it being acknowledged and agreed that the issuance of the Maximum Redemption Units pursuant to this Section 4.06(d)(ii), if applicable, shall redeem in full all of the then-outstanding Series A-2 Preferred Units and Series B Preferred Units) and (II) CEQP shall comply with its obligations under the Registration Rights Agreement with respect to such CEQP Units so issued; and providedfurther, however, that (x) with respect to any Partial Redemption, such notice shall state the number of Series A-2 Preferred Units and/or Series B Preferred Units that the Holdings Member has elected to require the Crestwood Member to acquire, (y) there shall be no more than one Partial Redemption (it being understood that, subject to the succeeding clause (z), following a Partial Redemption, any exercise by the Holdings Member of its rights under this Section 4.06(d)(ii) shall be for all (but not less than all) of the then-outstanding Series A-2 Preferred Units and Series B Preferred Units owned by the Holdings Member) and (z) for 180 days following a Partial Redemption, the Holdings Member shall be prohibited from exercising its rights under this Section 4.06(d)(ii) in respect of the remainder of its Series A-2 Preferred Units and Series B Preferred Units; or

(iii)to require the Company, at the direction of the Holdings Member, promptly, but in no event later than ten Business Days following the delivery of such notice (any such notice pursuant to this Section 4.06(d)(iii), a “Sale Option Notice”), to commence a process to effect a sale of all of the assets of the Company, including the Jackalope LLC Interest, subject to Article 4 of the Jackalope LLC Agreement (a “Sale Transaction”), in order to generate proceeds to the Company (such proceeds, net of any proceeds necessary

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to pay third party expenses, the “Sale Proceeds”); provided, however, for the avoidance of doubt, that, the Crestwood Member may, at any time prior to the consummation of any such Sale Transaction, exercise its rights arising under Section 4.06(e). At any time following the delivery of a Sale Option Notice pursuant to this Section 4.06(d)(iii), the Holdings Member shall have the option to cause the Company to engage a nationally recognized investment bank to undertake a process to effect a Sale Transaction, which process will be controlled by the Crestwood Member (unless the Crestwood Member determines that the process will be controlled by the Holdings Member) after reasonable consultation with the Holdings Member, and the Crestwood Member and the Company hereby agree to take all actions and grant all approvals reasonably requested by the Holdings Member in connection with any such process. Upon receipt of the Sale Proceeds, the Company shall promptly, but in any event not more than five Business Days following such receipt, use such Sale Proceeds to redeem for cash all then-outstanding Series A-2 Preferred Units and Series B Preferred Units at prices per Series A-2 Preferred Unit and Series B Preferred Unit required to provide the holder thereof an IRR equal to *** on each such Series A-2 Preferred Unit so redeemed, taking into account all Series A-2 Quarterly Distributions (including any Series A-2 PIK Distributions) paid by the Company as of such date of determination and an IRR equal to *** on each such Series B Preferred Unit so redeemed. All of the remaining Sale Proceeds, if any, after the redemption of all then-outstanding Series A-2 Preferred Units and Series B Preferred Units, shall be distributed to the Crestwood Member in respect of the Common Units and thereafter the Company will be terminated pursuant to Section 10.03. If the Sale Proceeds are insufficient to provide for the redemption of all then-outstanding Series A-2 Preferred Units and Series B Preferred Units in full, then the Holdings Member shall have the right to elect the remedies set out in Section 4.06(d)(ii) as to any shortfall in amounts required to achieve such IRR thresholds unless all of the following occur: (x) the Crestwood Member, upon receipt of the Sale Option Notice, responded within five days that it was granting the Holdings Member the sole and exclusive right to run and control the Sale Transaction, (y) following such grant by the Crestwood Member, the Holdings Member failed to use commercially reasonable efforts to obtain the greatest amount of Sale Proceeds reasonably available to the Company in a Sale Transaction and (z) the Crestwood Member and the Company used commercially reasonable efforts to take such actions as were reasonably requested by the Holdings Member in connection therewith. If the foregoing conditions set forth in clauses (x), (y) and (z) are all satisfied, then, upon completion of the Sale Transaction, all then-outstanding Series A-2 Preferred Units and Series C Preferred Units shall be deemed to have been redeemed in full for the Sale Proceeds.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

(e)Rights of Crestwood Member During Holdings Member Option Period. Notwithstanding anything to the contrary in this Section 4.06, if the Holdings Member has delivered a written notice pursuant to Section 4.06(d) (and provided that neither an acquisition pursuant to Section 4.06(d)(ii) nor a Sale Transaction pursuant to Section 4.06(d)(iii) has been consummated), then, from and after the delivery of such notice by the Holdings Member and until the expiration of the Holdings Member Option Period, the Crestwood Member may elect by delivering 10 Business

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Days’ prior written notice to the Holdings Member to (i) cause the Company to redeem all of the then-outstanding Series A-2 Preferred Units and Series B Preferred Units in exchange for the Company’s paying the Holdings Member cash, (ii) acquire all of the then-outstanding Series A-2 Preferred Units and Series B Preferred Units owned by the Holdings Member by the issuance to the Holdings Member or its designee as consideration a number of CEQP Units, valued at the CEQP Unit Price, in either case, effective as of the 10th Business Day following delivery of such notice and as required to provide to the Holdings Member an IRR equal to *** on each Series A-2 Preferred Unit so redeemed or acquired, taking into account all Series A-2 Quarterly Distributions (including any Series A-2 PIK Distributions) paid by the Company as of such date of determination and *** on each Series B Preferred Unit so redeemed or acquired, or (iii) acquire all of the then-outstanding Series A-2 Preferred Units and Series B Preferred Units owned by the Holdings Member by a combination of the actions described in clauses (i) and (ii) above; provided, however, that, solely with respect to the Series A-2 Preferred Units and the Series B Preferred Units subject to a Partial Redemption, the references to “all” in the foregoing clauses (i), (ii) and (iii) of this Section 4.06(e) shall instead be deemed to refer to the number of Series A-2 Preferred Units and Series B Preferred Units that the Holdings Member elected to require the Crestwood Member to acquire in such Partial Redemption; and providedfurther, that in connection with any election by the Crestwood Member to exercise its rights under this Section 4.06(e), (A) the options set forth in the foregoing clauses (ii) and (iii) shall not be available at any time at which an RRA Suspension Right would be, or would reasonably likely to be, exercisable by CEQP pursuant to the Registration Rights Agreement if the Holdings Member were to exercise a demand registration right pursuant to Section 2.03 of the Registration Rights Agreement immediately following the issuance of CEQP Units to the Holdings Member, (B) the number of CEQP Units shall not exceed the Maximum Redemption Units (it being acknowledged and agreed that the issuance of the Maximum Redemption Units, if applicable, shall redeem in full all of the then-outstanding Series A-2 Preferred Units and Series B Preferred Units and no further cash or other consideration shall be required to be paid in connection therewith) and (C) CEQP shall comply with its obligations under the Registration Rights Agreement with respect to such CEQP Units so issued; and providedfurther, for the avoidance of doubt, that, if the Holdings Member has not delivered a written notice pursuant to Section 4.06(d), then the Crestwood Member shall not have the right to elect from among the foregoing clauses (i), (ii) or (iii) in this Section 4.06(e).

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

(f)Effect of Redemption or Purchase of Preferred Units. To the extent that any Series A-2 Preferred Unit or Series B Preferred Unit is redeemed in full by the Company pursuant to this Agreement, at the time of such redemption, such Series A-2 Preferred Unit or Series B Preferred Unit will be immediately cancelled and retired by the Company. Upon the acquisition of any Series A-2 Preferred Unit or Series B Preferred Unit by the Crestwood Member pursuant to this Agreement (other than pursuant to Section 3.04 (Right of First Offer on Indirect Holdings Member Transfer)), immediately following such acquisition, such Preferred Unit shall be automatically be converted into, and shall be treated in all respects as, one Common Unit. Upon the acquisition of any Series A-2 Preferred Unit, Series B Preferred Unit or other Unit by the Crestwood Member pursuant to Section 3.04 (Right of First Offer on Indirect Holdings Member

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Transfer), such Units shall remain outstanding but, notwithstanding anything herein to the contrary, such Units (and the Crestwood Member as the owner of such Units) shall not have any redemption rights (other than pursuant to Section 4.06(d)(i), Section 4.06(d)(iii), or Section 5.01(c)), voting rights, governance rights or other rights hereunder but instead shall only have economic rights with respect thereto (including, for the avoidance of doubt, the right to receive distributions in accordance with Article V) and the conversion rights set forth in Section 4.07. Further, at such time as 100% of the Series A-2 Preferred Units and Series B Preferred Units held by the Holdings Member have been redeemed in full by the Company or acquired by the Crestwood Member in accordance with this Agreement, the Holdings Member shall immediately cease to be both a Member and a Party; provided, however, that the rights and obligations of the Holdings Member under Sections 3.07, 3.08, 3.09, Article V, Sections 6.03(c)(ii), 6.04(c), (d), (e) and (f), 6.05, 7.03, 7.04, 7.05, Article VIII, Section 9.01 and Article XI (the “Surviving Provisions”) shall survive the Holdings Member’s termination as a Member subject to any time limitations expressly set forth in any of the foregoing sections. In connection with any redemption or acquisition of less than all of the then-outstanding Series A-2 Preferred Units or Series B Preferred Units pursuant to this Section 4.06, such redemption or acquisition shall be effected in a manner such that the earliest-issued, then-outstanding Series A-2 Preferred Units or Series B Preferred Units, as applicable, are redeemed prior to the redemption of any later-issued Series A-2 Preferred Units or Series B Preferred Units.

(g)CEQP Guaranty. CEQP hereby irrevocably and unconditionally agrees to be jointly and severally liable for the full, complete and timely performance by the Crestwood Member of the obligation to deliver CEQP Units to the Holdings Member under Section 4.06(b), Section 4.06(c), Section 4.06(d)(ii) and Section 4.06(e) (the “CEQP Guaranty”), and CEQP’s obligations under the CEQP Guaranty shall be primary and not secondary to the obligations of the Crestwood Member. The CEQP Guaranty is absolute, continuing and independent of, and in addition to, any and all rights and remedies of the Holdings Member under this Agreement, and shall not in any way be discharged, impaired or otherwise affected by any of the following, each of which is hereby waived by CEQP: (a) any release or waiver of, or delay in, the enforcement of any rights of the Holdings Member, or (b) any requirements for promptness, diligence, notice of acceptance, presentment, demand for performance, notice of non-performance, default, acceleration, protest or dishonor or any other notice or similar requirement.

4.07Conversion of Preferred Units.

(a)Conditional Conversion Option. For so long as any outstanding Series A-2 Preferred Units are issued and outstanding and until the later of the fourth anniversary of the Effective Date and 30 days following the date on which no Series B Preferred Units are outstanding (such later date, the “Conversion Notice Deadline”), (i) if an Exit Event occurs, (ii) if the CWN TTM EBITDA Condition is satisfied or (iii) at any time following the third anniversary of the Effective Date, the Holdings Member may elect in each case by written notice to the Crestwood Member (the “Conversion Notice”) to cause the Company to convert all, but not less than all, of the then-outstanding Series A-2 Preferred Units into an aggregate number of Common Units that, following such Conversion, shall equal 49.99% of the aggregate number of outstanding Common Units as of immediately following such Conversion (the “Conversion”), which Common Units shall be issued to the Holdings Member (or, if the Crestwood Member acquired any Series A-2 Preferred Units

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pursuant to Section 3.04 (Right of First Offer on Indirect Holdings Member Transfer), then to the Holdings Member and the Crestwood Member in proportion to their respective ownership of all Series A-2 Preferred Units); provided, however, that (x) the Holdings Member’s right to effect a Conversion shall be limited solely to the extent required to be limited by applicable law and (y) if any of the conditions set forth in clauses (i) or (ii) has not been satisfied prior to the date that is 45 days prior to the Conversion Notice Deadline, but subsequently is satisfied prior to the Conversion Notice Deadline and the Holdings Member notifies the Company in writing that it desires to deliver a Conversion Notice prior to the Conversion Notice Deadline, and expiration or earlier termination of any applicable waiting period under the Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, is required in order for the Conversion to occur (“HSR Approval”), then the Conversion Notice Deadline shall automatically be extended until the earlier of (A) receipt of HSR Approval and (B) 45 days following the satisfaction of such condition.

(b)Effectiveness of Conversion; Rights of Holdings Member Upon Conversion. A Conversion shall be effective immediately, and without any payment of consideration or further action by the Company, or the Members, upon the delivery by the Holdings Member of a Conversion Notice to the Crestwood Member. Upon a Conversion, the rights of the Holdings Member (and if applicable, the Crestwood Member) in its capacity as a holder of Series A-2 Preferred Units or Series B Preferred Units shall cease with respect to such Units, including any rights under this Agreement with respect to such Units.

(c)Reimbursement Obligation of the Holdings Member Following Conversion. No later than 10 Business Days following a Conversion, the Crestwood Member shall deliver a written notice to the Holdings Member setting forth the Adjusted Capex Amount and wire transfer instructions for the account to which the Holdings Member should deliver the funds required (if any) pursuant to this Section 4.07(c).  No later than 10 Business Days following the receipt of such notice, the Holdings Member shall deliver to the Crestwood Member a written notice agreeing to one of the following three options: (i) to pay to the Crestwood Member the Adjusted Capex Amount in immediately available funds to an account designated by the Crestwood Member, (ii) having the Company reduce the number of Common Units held by the Holdings Member following the Conversion by a number of Common Units equal to the quotient of (A) the Adjusted Capex Amount divided by (B) the Common Unit Price or (iii) electing to pay a portion of the Adjusted Capex Amount and instructing the Company to reduce the number of Common Units held by the Holdings Member following the Conversion by a number of Common Units equal to the quotient of (A) the balance of the Adjusted Capex Amount, divided by (B) the Common Unit Price. If the Holdings Member elects options (i) or (iii), then the Holdings Member shall deliver the Adjusted Capex Amount (or in the case of option (iii) the reduced amount thereof) to the Crestwood Member no later than 10 Business Days following the delivery of such notice to the Crestwood Member.  If the Holdings Member elects options (ii) or (iii), then, without any further action by the Company, the board or the Members, the number of Common Units held by the Holdings Member shall automatically be reduced as instructed, effective upon the Conversion. For the avoidance of doubt, in no event shall the Crestwood Member be required to pay any Adjusted Capex Amount to the Holdings Member.

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ARTICLE VDISTRIBUTIONS AND ALLOCATIONS

5.01Distributions.

(a)Quarterly Series A-2 Preferred Distributions. Commencing with the Fiscal Quarter ending on March 31, 2018 and ending upon the earlier to occur of a Conversion or the redemption of all of the Series A-2 Preferred Units, the holders of the Series A-2 Preferred Units shall be entitled to receive cumulative distributions (each, a “Series A-2 Quarterly Distribution”), prior to any other distributions made in respect of any Common Units or other Interests other than any outstanding Deficiency Preferred Units, in the amount set forth in this Section 5.01(a) in respect of each Series A-2 Preferred Unit outstanding as of the end of such Fiscal Quarter. All such distributions shall be paid within 30 days after the end of each such Fiscal Quarter and, except as provided in the immediately following sentence, in cash in an amount equal to the Series A-2 Coupon Amount; provided, however, that the Series A-2 Coupon Amount shall be equal to zero for each Fiscal Quarter in respect of which there are Series C Preferred Units outstanding as of end of such Fiscal Quarter. For the Fiscal Quarter ending March 31, 2018, and for each Fiscal Quarter thereafter through and including the Fiscal Quarter ending March 31, 2019, the Series A-2 Quarterly Distribution may, at the election of the Company, be paid through the issuance to the Holdings Member of a number of Series A-2 Preferred Units (a “Series A-2 PIK Distribution”) equal to the quotient resulting from the division of (A) the Series A-2 Coupon Amount, by (B) the Series A-2 Preferred Unit Price. For purposes of this Agreement, a Series A-2 PIK Distribution shall be treated as a distribution of the Series A-2 Coupon Amount followed by an immediate contribution to the Company of such amount by the Holdings Member.

(b)Distributions of Available Cash.

(i)Subject to Section 5.01(b)(ii), the Managing Member shall cause the Company to make a distribution of 100% of all Available Cash in respect of a particular Fiscal Quarter to the Common Members in respect of the Common Units outstanding as of the end of such Fiscal Quarter (it being understood that, as of the Effective Date, the Crestwood Member shall be the only Common Member), provided that, if such distribution is prior to a Conversion, immediately prior to making such distribution (A) the Company has distributed any Series A-2 Quarterly Distribution required with respect to such Fiscal Quarter, (B) there are no Series A-2 Quarterly Distributions required to have been distributed pursuant to Section 5.01(a) with respect to any concluded Fiscal Quarter that remain unpaid, (C) no Series B Preferred Units are outstanding and (D) the Managing Member and the Company have each provided the Holdings Member with a written certificate in the form attached as Exhibit B at least three Business Days prior to making such distribution specifying that as of such time, no Material Adverse Change has occurred, nor will any Material Adverse Change occur as a result of the Company’s making such distribution.

(ii)If a Conversion has not yet occurred, in addition to fulfilling the conditions set forth in the proviso of Section 5.01(b)(i), at any time after the fifth anniversary of the Effective Date, the Managing Member shall cause the Company to make a distribution of 100% of all Available Cash in respect of a particular Fiscal Quarter as follows:

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(A)First, pro rata to the Holdings Member and the Crestwood Member in accordance with their then-current respective aggregate Capital Contributions (but disregarding any contributions as contemplated by Section 4.05) as of the making of such distribution; provided that, for the purpose of this Section 5.01(b)(ii), (1) “Available Cash” shall include the aggregate amount of the Series A-2 Quarterly Distribution required to be distributed in respect of the Series A-2 Preferred Units with respect to such Fiscal Quarter and (2) the amount of Available Cash deemed to have been distributed to the Holdings Member for purposes of this Section 5.01(b)(ii) shall include the amount of any such Series A-2 Quarterly Distribution required to be distributed to the Holdings Member with respect to such Fiscal Quarter; and

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

(B)Second, upon the receipt by the Holdings Member pursuant to Section 5.01(b)(ii)(A) of an amount of distributions in respect of each outstanding Series A-2 Preferred Unit equal to (1) the amount required to provide to the Holdings Member an IRR equal to *** on each such outstanding Series A-2 Preferred Unit, less (2) the Series A-2 Preferred Unit Price, then, 100% to the Crestwood Member in respect of the Common Units.

(c)Special Proceeds. The Company shall use any Special Proceeds solely as follows: (A) first, to the extent that such Special Proceeds are not proceeds of a debt financing transaction undertaken by the Company or Jackalope LLC, to make (or be reserved for the making of) Required Jackalope Contributions; and (B) second, (I) to the extent that the Managing Member reasonably determines that no Required Jackalope Contributions will be required to be made at any time during the twelve months immediately following the Company’s receipt of such Special Proceeds, or (II) in the case that such Special Proceeds result from a debt financing transaction undertaken by the Company or Jackalope LLC, then the Managing Member shall cause the Company to redeem Series A-2 Preferred Units, pro rata from the Members in accordance with their respective ownership percentages of the aggregate outstanding Series A-2 Preferred Units, in cash as follows:

(i)at any time prior to the fourth anniversary of the Effective Date, pursuant to Section 4.06(b) as if the Crestwood Member had elected to cause the Company to make such redemption solely for cash in connection with a Company Change of Control;

(ii)at any time on or after the fourth anniversary of the Effective Date but prior the commencement of the Holdings Member Option Period, pursuant to Section 4.06(c) as if the Crestwood Member had elected to cause the Company to make such redemption solely for cash; or

(iii)at any time after the commencement of the Holdings Member Option Period, pursuant to Section 4.06(e)(i) as if the Crestwood Member had elected to cause the Company to make such redemption solely for cash.

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(d)Withholding. Notwithstanding anything to the contrary herein, the Managing Member, in connection with and subject to the consent of the Holdings Member (such consent not to be unreasonably withheld, conditioned or delayed), shall determine the amounts of any required tax withholdings. In connection therewith, the Managing Member may retain or withhold amounts (including any amounts imposed pursuant to Section 6225 of the Code) and make tax payments, including interest and penalties thereon, on behalf of or with respect to any Member (“Tax Advances”). All Tax Advances made on behalf of a Member shall, at the option of the Managing Member, (i) be promptly paid to the Company by the Manager on whose behalf such Tax Advances were made or (ii) be repaid by reducing the amount of the current or next succeeding distribution or distributions which would otherwise have been made to such Member or, if such distributions are not sufficient for that purpose, by so reducing the proceeds of liquidation of the Company otherwise payable to such Member. Whenever the Managing Member selects option (ii) pursuant to the preceding sentence for repayment of a Tax Advance by a Member, for all other purposes of this Agreement, such Member shall be treated as having received all distributions unreduced by the amount of such Tax Advance. For the avoidance of doubt, notwithstanding anything to the contrary in this Agreement, the liabilities and obligations of each Member under this Section 5.01(d) shall survive any deemed Transfer of an interest in the Company by such Member or such Member ceasing to be a Member under this Agreement.

(e)Distributions in Error. Any distributions pursuant to this Section 5.01made in error or in violation of Section 18-607(a) of the Act, will, upon good faith demand by the Managing Member (or the Holdings Member, if such distribution in error was received by the Managing Member), be returned to the Company.

5.02Allocations.

(a)In General. Except as provided in Section 5.02(b), for purposes of maintaining Capital Accounts, items of Company income, gain, loss, deduction and credit for each applicable accounting period (taking into account, for this purpose, any positive adjustments to the Book Values of Company assets in the same manner as if such adjustments were items of income or gain and any negative adjustments to the Book Values of Company assets in the same manner as if such adjustments were items of deduction or loss) shall be allocated among the Members in a manner that will, as nearly as possible, cause the Capital Account balance of each Member at the end of such period to equal the amount (which may be negative) determined for such Member by subtracting item (ii) from item (i) below:

(i)the amount that would be distributed to such Member (other than any amounts treated as a guaranteed payment under Section 707(c) of the Code) if: (A) all Company assets were sold for cash equal to their Book Values; (B) all Company obligations were satisfied in cash according to their terms (limited, with respect to each Nonrecourse Liability or Member Nonrecourse Debt, to the Book Values of the assets securing or subject to such liability); and (C) the net proceeds thereof (after satisfaction of such liabilities) were distributed in full pursuant to Section 10.02(c) (ignoring, for this purpose, Section 10.02(c)(ii)(B)(1), and applying Section 10.02(c)(ii)(B)(2) as if it applied at any time prior to the commencement of the Holdings Member Option Period); over

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(ii)the sum of: (A) such Member’s share of the Company Minimum Gain determined pursuant to Treasury Regulations Section 1.704-2(g) computed immediately prior to the hypothetical sale described above, (B) such Member’s share of Member Minimum Gain determined pursuant to Treasury Regulations Section 1.704-2(i)(5), computed immediately prior to the hypothetical sale described above and (C) the amount, if any, that such Member is obligated to contribute to the capital of the Company computed after the hypothetical events described in Section 5.02(a)(i) above;

provided, however, notwithstanding anything to the contrary in this Section 5.02(a), the amount of items of Company deduction and loss allocated to any Member pursuant to this Section 5.02(a) shall not exceed the maximum amount of such items that can be so allocated without causing such Member to have a deficit balance in its Adjusted Capital Account at the end of any Tax Year or other applicable accounting period. Items of deduction and loss in excess of such limitation shall be allocated to the Members who do not have deficit balances in their Adjusted Capital Accounts, pro rata, in proportion to the amounts that may be so allocated to them without causing them to have such deficit balances.

(b)Regulatory Allocations. Notwithstanding the foregoing provisions of Section 5.02(a), the following special allocations will be made in the following order of priority:

(i)Minimum Gain Chargeback. If there is a net decrease in Company Minimum Gain during an applicable accounting period, then each Member will be allocated items of Company income and gain for such period (and, if necessary, for subsequent periods) in an amount equal to such Member’s share of the net decrease in Company Minimum Gain, determined in accordance with Treasury Regulations Section 1.704-2(g)(2). This Section 5.02(b)(i) is intended to comply with the minimum gain chargeback requirement of Treasury Regulations Section 1.704-2(f) and will be interpreted consistently therewith.

(ii)Member Minimum Gain Chargeback. If there is a net decrease in Member Minimum Gain attributable to a Member Nonrecourse Debt during any applicable accounting period, each Member who has a share of the Member Minimum Gain attributable to such Member Nonrecourse Debt, determined in accordance with Treasury Regulations Section 1.704-2(i)(5) will be specially allocated items of Company income and gain for such period (and, if necessary, subsequent periods) in an amount equal to such Member’s share of the net decrease in Member Minimum Gain attributable to such Member Nonrecourse Debt, determined in a manner consistent with the provisions of Treasury Regulations Section 1.704-2(g)(2) and (j)(2)(ii). This Section 5.02(b)(ii) is intended to comply with the partner nonrecourse debt minimum gain chargeback requirement of Treasury Regulations Section 1.704-2(i)(4) and will be interpreted consistently therewith.

(iii)Qualified Income Offset. If any Member unexpectedly receives an adjustment, allocation, or distribution of the type contemplated by Treasury Regulations Sections 1.704-1(b)(2)(ii)(d)(4), (5) or (6), items of income and gain will be allocated to such Member in an amount and manner sufficient to eliminate any resulting deficit balance in such Member’s Adjusted Capital Account as quickly as possible, provided that an allocation pursuant to this Section 5.02(b)(iii) shall be made if and only to the extent that

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such Member would have an Adjusted Capital Account deficit after all other allocations provided for in this Article V have been tentatively made as if this Section 5.02(b)(iii) were not in this Agreement. It is intended that this Section 5.02(b)(iii) qualify and be construed as a “qualified income offset” within the meaning of Treasury Regulations Section 1.704-1(b)(2)(ii)(d).

(iv)Certain Additional Adjustments. To the extent that an adjustment to the adjusted tax basis of any Company asset pursuant to Code Section 734(b) or Code Section 743(b) is required, pursuant to Treasury Regulations Section 1.704‑1(b)(2)(iv)(m)(2) or Treasury Regulations Section 1.704-1(b)(2)(iv)(m)(4), to be taken into account in determining Capital Accounts as the result of a distribution to a Member in complete liquidation of its Interest, the amount of such adjustment to the Capital Accounts will be treated as an item of gain (if the adjustment increases the basis of the asset) or loss (if the adjustment decreases such basis), and such gain or loss will be specially allocated to the Members in accordance with their Interests in the Company in the event that Treasury Regulations Section 1.704-1(b)(2)(iv)(m)(2) applies, or to the Members to whom such distribution was made in the event that Treasury Regulations Section 1.704-1(b)(2)(iv)(m)(4) applies.

(v)Nonrecourse Deductions. The Nonrecourse Deductions for each Tax Year will be allocated to holders of Common Units in proportion to the relative number of Common Units held.

(vi)Member Nonrecourse Deductions. Member Nonrecourse Deductions will be allocated to the Members that bear the economic risk of loss (within the meaning of Treasury Regulations Section 1.752-2) for the Member Nonrecourse Debt to which such Member Nonrecourse Deductions are attributable.

(vii)Curative Allocations. The allocations contained in the foregoing provisions of this Section 5.02(b), and any allocations required following the proviso in Section 5.02(a), are intended to comply with certain requirements of the Treasury Regulations promulgated under Code Section 704. It is the intent of the Members and the Company that, to the extent possible, all such allocations shall be offset either with other such allocations or with special allocations of other items of income, gain, loss or deduction pursuant to this Section 5.02(b)(vii), so that after such offsetting allocations are made, each Member’s Capital Account balance is, to the extent possible, equal to the Capital Account balance such Member would have had if no such allocations had been made and all items were allocated pursuant to Section 5.02(a) (not including the allocations required following the proviso in Section 5.02(a)).

(viii)Noncompensatory Option. Items of income, gain, loss or deduction resulting from a restatement of the Book Values of Company assets pursuant to clause (b)(iii) of the definition of Book Value shall be allocated among the Members in the manner described in Treasury Regulations Section 1.704-1(b)(2)(iv)(s)(2).

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(c)Tax Allocations.

(i)Except as provided in Section 5.02(c)(ii) hereof, to the maximum extent possible, for U.S. federal income tax purposes (and for purposes of any state or local income or franchise tax that follows the federal treatment), each item of Company income, gain, loss or deduction will be allocated among the Members in the same manner as the correlative item of income, gain, loss or deduction is allocated for purposes of maintaining Capital Accounts pursuant to this Article V.

(ii)Tax items with respect to any Company asset that has a Book Value that differs from its adjusted tax basis will be allocated among the Members for federal income tax purposes in a manner consistent with the Treasury Regulations promulgated under Code Sections 704(b) and 704(c) so as to take into account such difference utilizing the remedial allocation method under Treasury Regulations Section 1.704-3(d).

(d)Other Provisions. The Members, their respective Affiliates and Permitted Transferees, and the Company, intend and agree to treat the Preferred Units as equity interests in the Company for U.S. federal income tax purposes, and the Company as a partnership, for U.S. federal income tax purposes, except as otherwise required by applicable law following a final “determination” under Code Section 1313 or as otherwise agreed by all of the Members (including, for the avoidance of doubt, the Holdings Member to the extent such treatment is relevant to the treatment of the Company or any holder of a Preferred Unit for any Tax Year or portion thereof in which the Holdings Member, any of its Affiliates or Permitted Transferees, is or was a Member). In the event that it is determined upon audit by the Internal Revenue Service that the Company, the Crestwood Member, or any of its Affiliates or Permitted Transferees, is required to treat the rights and obligations represented by the Preferred Units as indebtedness for U.S. federal income tax purposes, the Members, their respective Affiliates and Permitted Transferees, and the Company agree to revise the provisions of this Agreement and take such other action as may be reasonably requested by either Member to minimize the effect of such treatment on all of the Members.

(e)Compliance with Subchapter K. Notwithstanding anything to the contrary in this Agreement, in the discretion of the Managing Member, with the consent of the Holdings Member, the Company may diverge from the allocations described herein as may be necessary or appropriate to comply with the provisions of subchapter K of the Code and the Treasury Regulations promulgated thereunder.

ARTICLE VIMANAGEMENT

6.01Authority of the Managing Member. Except as otherwise provided in this Agreement (including as provided in Section 6.02 or by applicable law), the power and authority to manage, direct and control the Company will be vested in the Managing Member, and the Managing Member will have full, complete and exclusive authority to manage, direct and control the business, affairs and properties of the Company. The Company will not have any officers or employees.

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6.02Actions Requiring Holdings Member Consent.

(a)Actions Requiring Holdings Member Consent Prior to a Conversion. Notwithstanding anything herein to the contrary, except as provided in Section 6.03, prior to a Conversion, neither the Company nor any of its Subsidiaries will take, and neither the Managing Member nor any other Member will take any action so as to cause or permit the Company or any of its Subsidiaries to take, any of the following actions without the prior written consent of the Holdings Member:

(i)the voting of the Jackalope LLC Interests held by the Company in connection with:

(A)except during any Holdings Member Default Period, the sale of any material assets of Jackalope LLC or any of its Subsidiaries;

(B)except during any Holdings Member Default Period, any merger or consolidation of Jackalope LLC or any of its Subsidiaries with or into any other Person;

(C)any change in the distribution policy of Jackalope LLC;

(D)except during any Holdings Member Default Period, the entry by Jackalope LLC or its Subsidiaries into any line of business other than (1) the Business (for purposes of this clause (D), as defined in the Jackalope LLC Agreement as of the Effective Date) or any change to any fundamental characteristic of, or exit from, the Business, or (2) in addition to any Business under clause (1), any commercial proposal, prospect, solicitation, deal, transaction or opportunity relating to midstream infrastructure services (other than midstream infrastructure services that create material direct commodity price exposure) in connection with the production of crude oil or natural gas or natural gas liquids within the Area of Interest;

(E)the issuance by Jackalope LLC of any equity securities;

(F)the filing of a voluntary bankruptcy or similar proceeding by Jackalope LLC or any of its Subsidiaries or the election not to contest any bankruptcy or similar proceeding filed against Jackalope LLC or any of its Subsidiaries;

(G)except during any Holdings Member Default Period, the incurrence by Jackalope LLC of any indebtedness for borrowed money (including the guarantee of the obligations of any other Person) not outstanding as of the Effective Date; or

(H)the amendment, waiver, termination or any other material modification to material commercial contracts or the Jackalope LLC Agreement;

(ii)except during any Holdings Member Default Period, the exercise by the Company of any tag-along right under Section 4.3 of the Jackalope LLC Agreement;

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(iii)the liquidation, dissolution, recapitalization or reorganization of the Company in any form of transaction;

(iv)the authorization or issuance of any equity security, convertible security, phantom equity instrument or similar right that would not be subordinated to the Preferred Units, or the amendment of the terms of any such security, instrument or right to the extent such amendment would cause such security, instrument or right not to be subordinated to the Preferred Units;

(v)the acquisition by the Company of any equity interest in any Entity other than Jackalope LLC;

(vi)the election of, or any change in, the manner in which either (A) the Company or any material transaction undertaken by the Company is treated for tax purposes or (B) any material item of income or expense of the Company is treated for tax purposes;

(vii)any change in the Company’s accountants to a firm that is not a Big Four Firm;

(viii)the merger or consolidation of the Company with or into any other Entity;

(ix)the Transfer of any equity interest in the Company (other than a Transfer permitted pursuant to Article III or a redemption or purchase of any Units effected in accordance with Article IV or Article V);

(x)the sale, lease, pledge or other disposition of any material assets of the Company, including the Jackalope LLC Interest;

(xi)except during any Holdings Member Default Period, undertaking a Public Offering;

(xii)the entry by the Company into any line of business or activity other than (A) holding an equity interest in Jackalope LLC or (B) engaging in Agreed Midstream Services;

(xiii)the amendment or waiver of any provision of the Certificate;

(xiv)the filing of a voluntary bankruptcy or similar proceeding or the failure to contest any bankruptcy or similar proceeding filed against the Company;

(xv)the conversion of the Company from a limited liability company into any other form of Entity;

(xvi)the incurrence by the Company of any indebtedness for borrowed money (including the guarantee of the obligations of any other Person) or the encumbrance by the Company of any of its assets;

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(xvii)the entry into, or termination or amendment of, any contract, agreement, transaction or other arrangement between the Company or any of its Subsidiaries and the Crestwood Member or any of its Affiliates, other than a Permitted Utilization Arrangement;

(xviii)except during any Holdings Member Default Period, the commencement or settlement of any tax contest, material dispute, arbitration, litigation, mediation or other proceeding;

(xix)except during any Holdings Member Default Period, the amendment of the budget for any Agreed Midstream Project or any material change in the scope of development or operation of any Agreed Midstream Project;

(xx)the removal or replacement of the Crestwood Member as the Managing Member other than as a result of a Transfer by the Crestwood Member in compliance with this Agreement;

(xxi)any change in the distribution policy of the Company, or the making or authorization of any distribution other than as permitted by Article V; or

(xxii)agree or commit to do any of the foregoing.

(b)Actions Requiring Holdings Member Consent Following a Conversion. Notwithstanding anything herein to the contrary, except as provided in Section 6.03, following a Conversion, neither the Company nor any of its Subsidiaries will take, and neither the Managing Member nor any other Member will take any action so as to cause or permit the Company or any of its Subsidiaries to take, any of the following actions without the prior written consent of the Holdings Member:

(i)the voting of the Jackalope LLC Interests held by the Company in connection with:

(A)except during any Holdings Member Default Period, the purchase or sale of any assets of Jackalope LLC or any of its Subsidiaries in a single transaction or a series of related transactions for aggregate consideration exceeding ***;

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

(B)except during any Holdings Member Default Period, any merger or consolidation of Jackalope LLC or any of its Subsidiaries with or into any other Person;

(C)any change in the distribution policy of Jackalope LLC;

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(D)except during any Holdings Member Default Period, the entry by Jackalope LLC or its Subsidiaries into any line of business other than (1) the Business (for purposes of this clause (D), as defined in the Jackalope LLC Agreement as of the Effective Date) or any change to any fundamental characteristic of, or exit from, the Business, or (2) in addition to any Business under clause (1), any commercial proposal, prospect, solicitation, deal, transaction or opportunity relating to midstream infrastructure services (other than midstream infrastructure services that create material direct commodity price exposure) in connection with the production of crude oil or natural gas or natural gas liquids within the Area of Interest;

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

(E)the issuance by Jackalope LLC of any equity securities;

(F)the filing of a voluntary bankruptcy or similar proceeding by Jackalope LLC or any of its Subsidiaries or the election not to contest any bankruptcy or similar proceeding filed against Jackalope LLC or any of its Subsidiaries;

(G)except during any Holdings Member Default Period, the incurrence by Jackalope LLC of any indebtedness for borrowed money (including the guarantee of the obligations of any other Person) not outstanding as of the Conversion; or

(H)the amendment, waiver, termination or any other material modification to material commercial contracts or the Jackalope LLC Agreement.

(ii)the liquidation, dissolution, recapitalization or reorganization of the Company in any form of transaction;

(iii)except as contemplated by Section 4.02(c), the issuance of any equity security, convertible security, phantom equity instrument or similar right to a third party;

(iv)the election of, or any change in, the manner in which either (A) the Company or any material transaction undertaken by the Company is treated for tax purposes or (B) any material item of income or expense of the Company is treated for tax purposes;

(v)the merger or consolidation of the Company with or into any other Entity;

(vi)the Transfer of any equity interest in the Company (other than a Transfer permitted pursuant to Article III or a redemption or purchase of any Units effected in accordance with Article IV or Article V);

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(vii)the sale, lease, pledge or other disposition of any material assets of the Company, including the Jackalope LLC Interest, in a single transaction or a series of related transactions for aggregate consideration exceeding ***;

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

(viii)except during any Holdings Member Default Period, undertaking a Public Offering;

(ix)the entry by the Company into any line of business or activity other than (A) holding an equity interest in Jackalope LLC or (B) engaging in Agreed Midstream Services;

(x)the amendment or waiver of any provision of the Certificate;

(xi)the filing of a voluntary bankruptcy or similar proceeding or the failure to contest any bankruptcy or similar proceeding filed against the Company;

(xii)the conversion of the Company from a limited liability company into any other form of Entity;

(xiii)the incurrence by the Company of any indebtedness for borrowed money (including the guarantee of the obligations of any other Person) or the encumbrance by the Company of any of its assets;

(xiv)the entry into, or termination or amendment of, any material contract, material agreement, material transaction or other material arrangement between the Company or any of its Subsidiaries and the Crestwood Member or any of its Affiliates, other than a Permitted Utilization Arrangement;

(xv)subject to Section 6.06, adopt, approve or amend any Annual Budget, or make any expenditures resulting in an overrun in excess of 10% for any material line item in an Annual Budget;

(xvi)except during any Holdings Member Default Period, the commencement or settlement of any tax contest, material dispute, arbitration, litigation, mediation or other proceeding in each case involving an amount in controversy exceeding ***;

(xvii)to the extent that such expenditures exceed *** in the aggregate annually, the incurrence of expenditures for any capital asset expansion or capital asset enhancement, or series of related capital asset expansions and capital asset enhancements;

(xviii)any change in the distribution policy of the Company, or the making or authorization of any distribution other than as contemplated by Article V; or

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(xix)agree or commit to do any of the foregoing.

(c)Supplemental Holdings Member Consent Rights. In addition to matters set forth in Section 6.02(a), during any period in which either (x) any Series B Preferred Units are outstanding or (y) any Series A-2 Quarterly Distribution required to have been distributed in cash has not been paid in full in accordance with Section 5.01(a), neither the Company nor any of its Subsidiaries will take, and neither the Managing Member nor any other Member will take any action so as to cause or permit the Company or any of its Subsidiaries to take, any of the following actions without the prior written consent of the Holdings Member:

(i)the voting of the Jackalope LLC Interests held by the Company in connection with any budget matters, capital expenditures or the incurrence of any indebtedness for borrowed money; or

⁽ⁱⁱ⁾the granting of consent to any amendment to, modification of or waiver of any provision of the Articles of Organization of Jackalope LLC, the Jackalope LLC Agreement or any Transaction Document (as defined in the Jackalope LLC Agreement).

6.03Opportunities; Midstream Project Opportunities.

(a)Right to Compete. Notwithstanding anything else to the contrary in this Agreement, except for the limitations applicable to the Crestwood Member pursuant to Section 6.03(b), Section 6.03(c) and Section 6.03(d), nothing herein shall require the Crestwood Member or the Holdings Member (or any of their respective Affiliates or their direct or indirect equity owners) to bring any Midstream Project Opportunity or other opportunity to the Company (including any De Minimis Midstream Project Opportunity), and the Members (and their respective Affiliates and their respective direct or indirect equity owners) may engage or invest in, and devote their time to, any other business venture or activity of any nature and description, whether or not such activities are considered competitive with the Company or its business (the “Right to Compete”), and neither the Company nor any other Member (nor any of their respective Affiliates or their direct or indirect equity owners) will have any right by virtue of this Agreement or the relationship created hereby in or to such other venture or activity (or to the income or proceeds derived therefrom), and the pursuit of such other venture or activity will not be deemed wrongful or improper. Subject to the limitations applicable to the Crestwood Member pursuant to Section 6.03(b), Section 6.03(c) and Section 6.03(d), the foregoing Right to Compete does not require notice to, approval from, or other sharing with, any of the other Members, the Company or any other Person, and, notwithstanding anything herein to the contrary, including in this Section 6.03, the legal doctrines of “corporate opportunity,” “business opportunity” and similar doctrines will not be applied to any such competitive venture or activity (except as otherwise set forth in Section 6.03(b),Section 6.03(c) or Section 6.03(d)) and are hereby fully and irrevocably disclaimed.

(b)Prohibition on Pursuing Opportunities. Except for those matters set forth on Schedule I and for Excluded Opportunities, the Crestwood Member, CEQP and their controlled Affiliates are prohibited from pursuing, developing, owning, operating or investing in any Midstream Project Opportunities relating to the Business in the Area of Interest other than in

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accordance with this Section 6.03 (including with respect to De Minimis Midstream Project Opportunities which are prohibited other than as set out in Section 6.03(e)).

(c)Project Requests.

(i)The Crestwood Member may (but in no event shall be required to), from time to time, propose that the Company engage in a Midstream Project Opportunity relating to the Business in the Area of Interest by delivering a written request (each, a “Project Request”) to the Holdings Member. Each Project Request shall contain a reasonably detailed explanation of the Midstream Project Opportunity relating to the Business in the Area of Interest, including:

(A)a detailed monthly budget for such Midstream Project Opportunity, including a good faith estimate of the costs and expenses of constructing, operating and maintaining such Midstream Project Opportunity and the revenues to be derived therefrom;

(B)a detailed timetable for such Midstream Project Opportunity, including an estimated commencement date and material milestones and the estimated schedule for calling capital;

(C)a framework for project review meetings with the Holdings Member, including approvals for any budget overruns, delays and other events that could materially impair the economics or viability of such Midstream Project Opportunity and subsequent requirements for Capital Contributions;

(D)the proposed terms of any agreements with third parties that arise in connection with such Midstream Project Opportunity; and

(E)the expected effect of such Midstream Project Opportunity on the Company and its existing business and assets.

(ii)The Holdings Member agrees that any information furnished to the Holdings Member or its advisors in a Project Request or by or on behalf of the Crestwood Member in connection with the Holdings Member’s evaluation of any Midstream Project Opportunity (such information, “Evaluation Material”) shall be (A) kept strictly confidential and (B) used by the Holdings Member and its Affiliates, on or before the second anniversary of the date such Evaluation Material is furnished to the Holdings Member, solely for the purpose of evaluating the Company’s undertaking the Midstream Project Opportunity and implementing any Midstream Project Opportunity that becomes an Agreed Midstream Project; provided, however, that Evaluation Material shall not include any information to the extent that such information (I) was or becomes generally available to the public other than as a result of a disclosure by the Holdings Member, (II) was or becomes available to the Holdings Member from a source other than the Crestwood Member or its Affiliates, advisors or other representatives that is not bound by an obligation of confidentiality to the

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Crestwood Member or its Affiliates or (III) was independently developed by the Holdings Member or its Affiliates without reference to or otherwise using the Evaluation Material.

(d)Agreed Midstream Projects and Rejection.

(i)If, within 45 days following receipt of a Project Request, the Holdings Member provides written notice to the Crestwood Member of its consent to the Company’s undertaking the applicable Midstream Project Opportunity, then such Midstream Project Opportunity shall be deemed an “Agreed Midstream Project” and the Company may pursue such Agreed Midstream Project in accordance with the terms set forth in the applicable Project Request and may request Capital Contributions with respect thereto in accordance with Section 4.02.

(ii)If the Holdings Member (x) does not provide written notice to the Crestwood Member of its consent to the Company’s undertaking a Midstream Project Opportunity within 45 days following receipt of the applicable Project Request or (y) provides written notice to the Crestwood Member that it does not consent to the Company’s undertaking the relevant Midstream Project Opportunity prior to the expiration of such 45-day period (each such circumstance described in the foregoing clauses (x) and (y), a “Rejection”), then none of the Crestwood Member or its Affiliates, the Company or any of the Company’s Subsidiaries may pursue such Midstream Project Opportunity except as follows:

(A)Prior to a Conversion, if such Midstream Project Opportunity was proposed to be undertaken by Jackalope LLC or its Subsidiaries, then the Company may undertake such Midstream Project Opportunity without the consent of the Holdings Member so long as the Crestwood Member commits to provide the required Capital Contributions to fund contributions required to be made by the Company to Jackalope LLC for such Midstream Project Opportunity pursuant to Section 4.02;

(B)Following Conversion, if such Midstream Project Opportunity was proposed to be undertaken by Jackalope LLC or its Subsidiaries, then the Crestwood Member may undertake such Midstream Project Opportunity, as well as any enhancements, extensions or expansions of such Midstream Project Opportunity outside of the Company and its Subsidiaries (including Jackalope LLC and its Subsidiaries) so long as it does not utilize any assets of the Company and its Subsidiaries (including Jackalope LLC and its Subsidiaries) unless either the Holdings Member consents to such utilization or (1) such utilization is pursuant to arrangements that are on arms’ length terms and (2) such arrangements will not prevent the Company or its Subsidiaries (including Jackalope LLC and its Subsidiaries) from satisfying its obligations to any other Person (any arrangement permitted by this clause (B), a “Permitted Utilization Arrangement”); or

(C)if such Midstream Project Opportunity was not proposed to be undertaken by Jackalope LLC or its Subsidiaries, then the Crestwood Member

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may undertake such Midstream Project Opportunity, as well as any enhancements, extensions or expansions of such Midstream Project Opportunity, outside of the Company and its Subsidiaries so long as it does not utilize any assets of the Company and its Subsidiaries (including Jackalope LLC and its Subsidiaries) unless under a Permitted Utilization Arrangement.

(e)De Minimis Midstream Project Opportunities. Notwithstanding anything herein to the contrary, the Company shall be permitted (but not required) to pursue and effect a De Minimis Midstream Project Opportunity without the consent of the Holdings Member.

(f)PRB JV. Without limiting the foregoing in this Section 6.03, if and to the extent that the Crestwood Member, CEQP or any of their controlled Affiliates become obligated pursuant to the terms of that certain PRB LLCA (as defined on Schedule I) to pursue, develop, own, operate or invest in a Midstream Project Opportunity relating to the Business in the Area of Interest that does not constitute an Excluded Opportunity through the PRB JV (as defined on Schedule I), then the Crestwood Member shall use its reasonable best efforts to do so by means of an investment by the Company or its Subsidiaries; provided that such reasonable best efforts shall not require the Crestwood Member or any of its Affiliates to (i) pay any amounts to any Person or make any economic concessions to any Person or (ii) initiate, or threaten to initiate, any action, proceeding or litigation against any Person. Notwithstanding the foregoing and without limiting other ways in which the Crestwood Member may satisfy its obligations under this Section 6.03(f), the Crestwood Member shall have no further obligations under this Section 6.03(f), if the Crestwood Member offers to contribute the interest in the PRB JV held by an Affiliate of the Crestwood Member to the Company as a Capital Contribution valued at Fair Market Value thereof; provided that if within thirty (30) days of being notified of such offer, the Holdings Member requests that the Crestwood Member make such Capital Contribution, the Crestwood Member shall make such Capital Contribution as soon as possible thereafter in exchange for a number of Common Units equal to the Fair Market Value of such Capital Contribution divided by (i) if such Capital Contribution is made prior to the Conversion, the Common Unit Price (it being understood for the avoidance of doubt that such Capital Contribution shall be taken into account in the determination of the Adjusted Capex Amount) or (ii) if such Capital Contribution is made following the Conversion, the Fair Market Value of a Common Unit.

6.04Indemnification; Limitation of Liability.

(a)Subject to Section 6.04(b), (i) a Member, in its capacity as such, shall have no fiduciary or other duty to the Company, any other Member or any other Person that is a Party or is otherwise bound by this Agreement other than the implied contractual covenant of good faith and fair dealing and (ii) such Member shall not be liable in damages to the Company, any other Member or any other Person that is a Party or is otherwise bound by this Agreement by reason of, or arising from or relating to the operations, business or affairs of, or any action taken or failure to act on behalf of, the Company, except to the extent that it is determined by a final, non-appealable order of a court of competent jurisdiction that any of the foregoing was caused by (x) a breach or violation of the implied contractual covenant of good faith and fair dealing or the duties imposed

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by Section 6.04(b), (y) actual fraud or willful misconduct, or, (z) with respect to any criminal action or proceeding, conduct of a Member that such Member had reasonable cause to believe was unlawful.

(b)Except with respect to the Managing Member’s Right to Compete and the fiduciary duties related thereto, which duties are hereby disclaimed, the Managing Member shall have fiduciary duties of loyalty and care to the Company similar to that of directors and officers of for-profit corporations organized under the General Corporation Law of the State of Delaware.

(c)To the maximum extent permitted by applicable law, but subject to the provisions of this Section 6.04, the Members and the Managing Member (each an “Indemnitee”), each as provided below, will not be liable for, and will be indemnified and held harmless by the Company against, any and all claims, actions, demands, losses, damages, liabilities, costs or expenses, including attorneys’ fees, court costs, and costs of investigation, actually and reasonably incurred by any such Indemnitee (collectively, “Indemnified Losses”) arising from any civil, criminal or administrative proceedings in which such Indemnitee may be involved, as a party or otherwise, by reason of its being a Member or the Managing Member, whether or not it continues to be such at the time any such Indemnified Loss is paid or incurred, except to the extent that any of the foregoing is determined by a final, non-appealable order of a court of competent jurisdiction to (i) with respect to the Managing Member, have been caused by any breach of the duties imposed by Section 6.04(b), (ii) with respect to all Indemnitees, have been caused by a willful breach of the terms of this Agreement or the actual fraud, gross negligence, willful misconduct or bad faith of such persons, or (iii) with respect to criminal matters, have occurred in connection with activity that an Indemnitee had reason to believe was unlawful. IT IS THE EXPRESS INTENT OF THE PARTIES THAT THE FOREGOING INDEMNITY SHALL BE APPLICABLE TO ANY LOSS THAT HAS RESULTED FROM OR IS ALLEGED TO HAVE RESULTED FROM THE ACTIVE OR PASSIVE OR THE SOLE, JOINT OR CONCURRENT ORDINARY NEGLIGENCE OF THE INDEMNITEE.

(d)To the maximum extent permitted by applicable law, expenses incurred by an Indemnitee in defending any proceeding (except a proceeding by or in the right of the Company or brought by any of the Members against such Indemnitee), will be paid by the Company in advance of the final disposition of the proceeding, upon receipt of a written undertaking by or on behalf of such Indemnitee to repay such amount if such Indemnitee is determined pursuant to this Section 6.04 or adjudicated to be ineligible for indemnification, which undertaking will be an unlimited general obligation of the Indemnitee but need not be secured unless so determined by the Managing Member.

(e)Any indemnification pursuant to this Section 6.04 will be made only out of the assets of the Company and will in no event cause any Member to incur any personal liability nor shall it result in any liability of the Members to any third party.

(f)The rights of indemnification provided in this Section 6.04 are in addition to any rights to which an Indemnitee may otherwise be entitled by contract (including advancement of expenses) or as a matter of law.

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6.05No Recourse Against Nonparty Affiliates. All claims, obligations, liabilities, or causes of action (whether in contract or in tort, in law or in equity, or granted by statue) that may be based upon, in respect of, arise under, out or by reason of, be connected with, or relate in any manner to this Agreement, or the negotiation, execution, or performance of this Agreement (including any representation or warranty made in, in connection with, or as an inducement to, this Agreement), may be made only against (and are those solely of) the Parties. No Person who is not a Party, including any director, officer, employee, incorporator, member, partner, manager, stockholder, affiliate, agent, attorney, or representative of, and any financial advisor or lender to, any Party, or any director, officer, employee, incorporator, member, partner, manager, stockholder, affiliate, agent, attorney, or representative of, and any financial advisor or lender to any, of the foregoing (“Nonparty Affiliates”), shall have any liability (whether in contract or in tort, in law or in equity, or granted by statue) for any claims, causes of action, obligations, or liabilities arising under, out of, in connection with, or related in any manner to this Agreement or based on, in respect of, or by reason of this Agreement or its negotiation, execution, performance, or breach, and, to the maximum extent permitted by law, each Party hereby waives and releases all such liabilities, claims, causes of action, and obligations against any such Nonparty Affiliates. Without limiting the foregoing, to the maximum extent permitted by law, (a) each Party hereby waives and releases any and all rights, claims, demands, or causes of action that may otherwise be available at law or in equity, or granted by statute, to avoid or disregard the entity form of a Party or otherwise impose liability of a Party on any Nonparty Affiliate, whether granted by statute or based on theories of equity, agency, control, instrumentality, alter ego, domination, sham, single business enterprise, piercing the veil, unfairness, undercapitalization, or otherwise; and (b) each Party disclaims any reliance upon any Nonparty Affiliates with respect to the performance of this Agreement or any representation or warranty made in, in connection with, or as an inducement to this Agreement.

6.06Initial Budget and Annual Budgets. The Members hereby adopt and approve the Initial Budget, as set forth on Exhibit D as the initial operating budget of the Company and agree that such Initial Budget shall be deemed to be the Annual Budget for the period set forth therein. Subsequent Annual Budgets shall be approved (a) prior to a Conversion, by the Managing Member and (b) after a Conversion, pursuant to Section 6.02(b)(xv). In the case of clause (b) in the preceding sentence, if the Members do not approve any proposed Annual Budget in accordance with Section 6.02(b)(xv) within 30 days after the Company submits such Annual Budget to the Members, the Company shall continue to use the Annual Budget for the previous year, extrapolated to a 12-month budget period if necessary, except that (i) any items of the proposed Annual Budget that previously have been approved by the Crestwood Member and the Holding Member shall be given effect in substitution of the corresponding items in the Annual Budget for the previous year, (ii) any one-time or non-recurring items and the corresponding budget entries therefor shall be deleted, and (iii) all other expenses from the Annual Budget for the previous year shall be increased by 10%.

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ARTICLE VIIRIGHTS OF MEMBERS; CONFIDENTIALITY

7.01Access to Information.

(a)Generally. In addition to the other rights specifically set forth in this Agreement, the Members and Permitted Transferees will have access to all information to which a Member is entitled to have access pursuant to the Act. The Company shall permit the Holdings Member (so long as the Holdings Member is a Member) to send representatives to visit and inspect any of the properties of the Company, including its books of account and other records (and make copies of and take extracts from such books and records), and to discuss all aspects of the Company’s business, affairs, finances, and accounts with the Company’s officers and its independent public accountants, all at such reasonable times during the Company’s usual business hours and as often as the Holdings Member may reasonably request and to consult with and advise management of the Company, upon reasonable notice at reasonable times from time to time, on all matters relating to the operation of the Company.

(b)Jackalope LLC Matters. Upon receipt by the Managing Member, the Managing Member will promptly forward to the Holdings Member all information, reports and other materials, including board materials, documents and presentations, furnished to the Managing Member, or otherwise to the Company in its capacity as a member of Jackalope LLC, including pursuant to Section 2.9 and Section 2.17 of the Jackalope LLC Agreement. In addition, following any failure of the Company to pay any Series A-2 Quarterly Distribution when required to be distributed or the occurrence of a Deficiency Event, the Holdings Member shall be entitled to make inquiries into the operations of Jackalope LLC, including with respect to the books and records required to be kept by Jackalope LLC pursuant to Section 2.9 of the Jackalope LLC Agreement, and the Managing Member on behalf of the Company will make such inquiries and will promptly provide the Holdings Member with all information obtained with respect to such inquiries. Without limiting the foregoing, after a Conversion, the Managing Member shall take all commercially reasonable actions (which for the avoidance of doubt shall not require the Managing Member or the Company to make any payments to any Person) necessary to provide the Holdings Member board observation rights for any meetings among any of the following: (i) the Members (as such term is defined in the Jackalope LLC Agreement) of Jackalope LLC, (ii) the members of the Strategy Committee (as such term is defined in the Jackalope LLC Agreement) or (iii) among directors or managers of Jackalope LLC, if any.

7.02Financial Reports. The Company shall furnish the following to the Holdings Member:

(a)as soon as available, but not later than thirty (30) Business Days after the end of each calendar month financial statements of the Company, including monthly and year-to-date balance sheets, income statements, cash flow statements, statements of members’ equity and a general ledger prepared in accordance with U.S. generally accepted accounting principles (“U.S. GAAP”) applied on a consistent basis;

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(b)as soon as available, but not later than one hundred eighty (180) calendar days after the end of each Fiscal Year (commencing with the Fiscal Year ending December 31, 2013), a consolidated balance sheet of Company and its consolidated Subsidiaries as of December 31 of each Fiscal Year and the related consolidated statements of income, changes in members’ equity and cash flows of Company and its consolidated Subsidiaries for the Fiscal Year then ended, such annual financial reports to include notes and to be in reasonable detail, all prepared in accordance with U.S. GAAP;

(c)solely to the extent available, any audited financial statements of Jackalope LLC;

(d)promptly (but in no event later than two days) after the occurrence of any event that has, or could reasonably be expected to have, individually or in the aggregate, a material adverse effect on the business, results of operations, condition, assets, liabilities, employees, prospects, financial condition or capitalization of the Company, notice of such event together with a summary describing the nature of the event and its impact on the Company;

(e)within 15 days of the formation of any subsidiary company or joint venture in which the Company has Control, the Company shall provide the Holdings Member notice of such formation or acquisition and an updated organizational diagram; provided, however, that the Company’s undertaking any such activity shall still be subject to Section 6.02; and

(f)any other information that the Holdings Member may reasonably request.

7.03Audits. The Holdings Member shall have the right to conduct, or cause to be conducted, audits of the books and records of the Company. The expenses of such audits shall be borne by Holdings Member. No other Member in its capacity as a Member will have the right to conduct, or cause to be conducted, an audit of the books and records of the Company.

7.04Confidentiality. No Party will divulge to any Person any confidential information, paper or document relating to the assets, liabilities, operations, business affairs or any other such information about the Company or any of its Subsidiaries that is not already publicly available or that has not been publicly disclosed pursuant to authorization by the Members, except (a) as required by law or under the terms of a subpoena or order issued by a court of competent jurisdiction or by any applicable governmental body, (b) as required pursuant to an order of a court of competent jurisdiction or (c) to an Entity under 100% common Control with such Member (a “Permitted Affiliate”), provided that, any Party disclosing any such information to a Permitted Affiliate will (i) inform such Permitted Affiliate of the obligations of this Section 7.04 and (ii) be responsible for any breach of this Section 7.04 by any such Permitted Affiliate. The right to maintain the confidentiality of the affairs of the Company in connection with the Company’s business may be enforced by the Company by way of an injunction issued out of any court of competent jurisdiction, and such right will not restrict or take the place of the Company’s rights to money damages, actual and exemplary, for a violation of the provisions of this Section 7.04. Notwithstanding anything to the contrary in this Section 7.04, a Member may disclose information about the Company or any of its Subsidiaries to potential transferees of Units or to such Member’s representatives, agents,

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advisors (including, without limitation, attorneys, accountants, consultants, bankers, and financial advisors) (each, a “Representative”); provided, however, such potential transferee must execute a confidentiality agreement in customary form prior to such disclosure which (A) requires the recipient to keep the information confidential and (B) prohibits the recipient from using the information for any purpose other than evaluating the potential Transfer and any such Representative must be similarly bound with respect to confidentiality and usage. The confidentiality obligations of the Members will survive any termination of the membership of any Member in the Company. Notwithstanding the foregoing or anything else herein to the contrary, the Members (and each affiliate and Person acting on behalf of any Member) agree that each Member (and each employee, representative and other agent of such Member) may disclose to any and all Persons, without limitation of any kind, the transaction’s tax treatment and tax structure (as such terms are used in Sections 6011 and 6112 of the Code and the Treasury Regulations promulgated thereunder) contemplated by this Agreement and all materials of any kind (including opinions or other tax analyses) provided to such Member or such Person relating to such tax treatment and tax structure, except to the extent necessary to comply with any applicable federal or state securities laws.

7.05Press Releases. Neither the Company nor any Party or Affiliate of any Party shall issue, or authorize to be issued, any press release, interview, article or other media release (including an internet posting, web blog or other electronic publication) that makes reference to this Agreement or the transactions contemplated herein, without the prior unanimous written consent of the Members.

ARTICLE VIIITAXES

8.01Tax Returns. The Managing Member will cause to be prepared and filed all necessary federal, state and local tax returns for the Company, and the Managing Member will select an appropriate accounting firm to prepare such tax returns. The Company shall furnish to each Member the Company’s estimated IRS Form 1065 including the Schedules K-1 no later than February 20^th following each Tax Year. The Holdings Member may review and comment on the Company’s draft federal tax return and the Managing Member and the accounting firm preparing such return shall provide the Holdings Member with any supporting information reasonably requested by the Holdings Member for the purpose of reviewing such tax returns and the Managing Member and accounting firm shall consider the Holdings Member’s comments in good faith prior to finalizing such tax return. The Company shall furnish to each Member a final IRS Form 1065, Schedule K-1 with respect to such Member no later than April 15^th following each Tax Year. The Company also shall use reasonable best efforts to timely provide such other information, if any, with respect to the Company as may be reasonably necessary for the preparation of each Member’s, or its direct or indirect owners’, state or local income tax (or information) returns for such Tax Year, in each case at the Member’s expense. Upon the request of the Holdings Member, the Company will furnish to the Holdings Member copies of any and all returns that are actually filed, promptly after their filing.

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8.02Tax Elections.

(a)Elections by the Company. Subject to Sections 6.02(a)(vi), 8.02(b) and 8.03 the Crestwood Member will determine the elections to be made by the Company for tax purposes.

(b)Entity Classification Election. Neither the Company nor any Member may make an election for the Company to be treated as an association taxable as a corporation for U.S. federal income tax purposes, and no provision of this Agreement will be construed to sanction or approve such an election.

8.03Tax Audits. In the event of an audit or inquiry by any taxing authority of tax matters relating to the Company (any such audit or inquiry, a “Tax Proceeding”), the Crestwood Member shall represent the Company as the tax matters partner within the meaning of Section 6231(a)(7) of the Code and as the partnership representative pursuant to 6223(a) of the Code (as amended by the Bipartisan Budget Act of 2015); provided that, in all events, the Crestwood Member shall provide the Holdings Member with prompt notice of any audit or inquiry, shall consult with the Holdings Member on a regular basis regarding any such audit or inquiry, the Holdings Member shall be entitled to attend any meetings or conferences with the Internal Revenue Service (with counsel of its own choosing) relating to the Company or the U.S. federal income tax treatment of any items relating to the Company, all filings, elections, responses and other correspondence with the Internal Revenue Service on behalf of the Company or relating to the U.S. federal income tax treatment of any items relating to the Company shall be jointly approved by the Holdings Member and the Crestwood Member, and the Crestwood Member shall not settle or compromise any Tax Proceeding without the written consent of the Holdings Member, such consent not to be unreasonably withheld, conditioned or delayed. Expenses incurred by the Crestwood Member or the Holdings Member with respect to the matters described in this Section 8.03 shall be borne by the Company. Each Member and former Member, as applicable, agrees to cooperate with the tax matters partner or partnership representative, as applicable, and to do or refrain from doing any or all things reasonably required by the tax matters partner or partnership representative in connection with the conduct of any Tax Proceeding, including, without limitation, filing amended tax returns and paying any tax due by such Member or former Member in accordance therewith. Each Member hereby agrees to indemnify and hold harmless the Company and the other Members from and against any taxes, penalties and interest payable by the Company as a result of a Tax Proceeding with respect to income attributable to such Member (including, without limitation, with respect to any former Member, any taxes allocated to such former Member that are attributable to taxable periods (or portions thereof) during which such former Member was treated as holding Units or any other interest in the Company). The allocation of taxes to each member under the preceding sentence shall be made in consultation with and subject to the consent of the Holdings Member, such consent not to be unreasonably withheld, conditioned or delayed. For the avoidance of doubt, notwithstanding anything to the contrary in this Agreement, the liabilities and obligations of each Member under this Section 8.03 shall survive any deemed Transfer of an interest in the Company by such Member or such Member ceasing to be a Member under this Agreement.

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ARTICLE IXBOOKS, RECORDS, REPORTS, AND BANK ACCOUNTS

9.01Maintenance of Books and Records. The books of account for the Company and other records of the Company will be located at the principal office of the Company or such other place as Managing Member may deem appropriate, and will be maintained on an accrual basis in accordance with the terms of this Agreement, except that the Capital Accounts of the Members will be maintained in accordance with the definition of “Capital Account” in this Agreement.

9.02Reports. The Company will cause to be prepared or delivered such reports as the Managing Member may require and as are required to be prepared and delivered to the Holdings Member pursuant to Section 7.02. The Company will bear the costs of such reports.

9.03Bank Accounts. The Managing Member will cause the Company to establish and maintain one or more separate bank or investment accounts for Company funds in the Company name with such financial institutions and firms as the Managing Member may select and with such signatories thereon as the Managing Member may designate.

ARTICLE XDISSOLUTION, LIQUIDATION AND TERMINATION

10.01Dissolution. The Company will dissolve and its affairs will be wound up upon the first to occur of any of the following:

(a)the unanimous vote of the Holdings Member and the Crestwood Member; or

(b)the occurrence of any other event causing dissolution of the Company under the Act;

provided, however, that upon dissolution pursuant to clause (b) of this Section 10.01, any or all of the remaining Members may elect to continue the business of the Company within 90 days of the occurrence of the event causing such dissolution. The death, resignation, withdrawal, bankruptcy, insolvency or expulsion of any Member will not dissolve the Company.

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

10.02Liquidation and Termination. On dissolution of the Company, the Holdings Member, or, during any Holdings Member Default Period, the Managing Member, may appoint one or more Persons as liquidator(s), which Person or Persons shall be reasonably approved by the Crestwood Member. The liquidator will proceed diligently to wind up the affairs of the Company and make final distributions as provided herein. The costs of liquidation will be borne as a Company expense. Until final distribution, the liquidator will

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continue to operate the Company properties with all of the power and authority of the Members. The steps to be accomplished by the liquidator are as follows:

(a)as promptly as possible after dissolution and again after final liquidation, the liquidator will cause a proper accounting to be made by a recognized firm of certified public accountants of the Company’s assets, liabilities, and operations through the last day of the calendar month in which the dissolution occurs or the final liquidation is completed, as applicable;

(b)the liquidator will pay from Company funds all of the debts and liabilities of the Company (including, without limitation, all expenses incurred in liquidation) or otherwise make adequate provision therefor (including, without limitation, the establishment of a cash escrow fund for contingent liabilities in such amount and for such term as the liquidator may reasonably determine); and

(c)the Company will dispose of all remaining assets as follows:

(i)the liquidator may sell any or all Company property, and any resulting gain or loss from each sale will be computed and allocated to the Members pursuant to Section 5.02; and then pursuant to clause (ii) below:

(ii)thereafter, if any, Company property will be distributed among the Members in accordance with the following:

(A)First, 100% to the Holdings Member and the Crestwood Member, pro rata in accordance with their respective holdings of Deficiency Preferred Units, until (x) the Holdings Member has received an amount so as to result in an IRR to the Holdings Member of *** on the aggregate Deficiency Contributions made by the Holdings Member in respect of such Series B Preferred Units and (y) the Crestwood Member has received an amount so as to result in an IRR to the Crestwood Member of *** on the aggregate Default Contributions made by the Crestwood Member in respect of such Series C Preferred Units;

(B)Second, 100% to the Holdings Member in redemption of the outstanding Series A-2 Preferred Units as follows:

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

(1)at any time prior to the fourth anniversary of the Effective Date, pursuant to Section 4.06(b) in an amount determined as if the Crestwood Member had elected to cause the Company to make such redemption solely for cash in connection with a Company Change of Control;

(2)at any time on or after the fourth anniversary of the Effective Date but prior to the commencement of the Holdings Member Option Period, pursuant to Section 4.06(c) in an amount determined as if the Crestwood

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Member had elected to cause the Company to make such redemption solely for cash; or

(3)at any time after the commencement of the Holdings Member Option Period, pursuant to Section 4.06(e)(i) in an amount determined as if the Crestwood Member had elected to cause the Company to make such redemption solely for cash;

(C)The remainder, if any, 100% to the Common Members, pro rata in proportion to their respective ownership of outstanding Common Units.

(d)All distributions in kind to the Members will be made subject to the liability of each distributee for its allocable share of costs, expenses and liabilities theretofore incurred or for which the Company has committed prior to the date of termination and those costs, expenses and liabilities will be allocated to the distributee pursuant to this Section 10.02.

10.03Cancellation of Filing. On completion of the distribution of Company assets as provided herein, the Company will be terminated, and the Managing Member (or such other Person or Persons as may be required) will cause the cancellation of any other filings previously made on behalf of the Company and will take such other actions as may be necessary to terminate the Company.

ARTICLE XIGENERAL PROVISIONS

11.01Notices. All notices, requests or consents provided for or permitted to be given under this Agreement will be in writing (except as otherwise provided in Section 11.12) and will be given (a) by depositing such writing in the United States mail, addressed to the recipient, postage paid and certified with return receipt requested, (b) by depositing such writing with a reputable overnight courier for next day delivery, (c) by delivering such writing to the recipient in person, by courier, (d) by facsimile transmission or (e) email transmission. A notice, request or consent given under this Agreement will be effective on receipt by the Person to receive it. All notices, requests and consents to be sent to a Member will be sent to or made at the addresses given for that Member on the list attached hereto as Exhibit A or such other address as that Member may specify by notice to the other Members. Any notice, request or consent to the Company also will be given to the Crestwood Member and the Holdings Member. Any notice, request or consent to CEQP will be given to the following address: 811 Main Street, Suite 3400, Houston, Texas 77002, Attention: General Counsel.

11.02Entire Agreement; Third Party Beneficiaries. This Agreement, together with its Exhibits, constitutes the entire agreement of the Parties relating to the Company and supersedes all prior contracts or agreements with respect to the Company, whether oral or written. Nothing in this Agreement, express or implied, is intended to confer upon any Person other than the Parties and their respective successors, personal representatives and permitted assigns, any rights or remedies under or by reason of this Agreement; provided, however, that

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Nonparty Affiliates are intended to be third-party beneficiaries with rights to enforce the provisions of Section 6.05 as though a Party.

11.03Effect of Waiver or Consent. A waiver or consent, express or implied, to or of any breach or default by any Person in the performance by that Person of its obligations with respect to the Company will not constitute a consent or waiver to or of any other breach or default in the performance by that Person of the same or any other obligations of that Person with respect to the Company. Failure on the part of a Person to complain of any act of any Person or to determine any Person to be in default with respect to the Company, irrespective of how long such failure continues, will not constitute a waiver by that Person of its rights with respect to that default until the applicable limitations period has expired.

11.04Amendment or Modification. Except for any amendments to Exhibit A made solely to reflect issuances of additional Units or admission of Members in accordance with this Agreement, which amendments may be made by the Managing Member, this Agreement may be amended or modified from time to time only by a written instrument executed by each of the Crestwood Member and the Holdings Member; provided, however, that following the termination of the Holdings Member as a Member in accordance with this Agreement, the Holdings Member’s consent shall only be required to amend or modify the Surviving Provisions or to otherwise amend or modify the Agreement in a manner that would negatively affect the Holdings Member’s rights under the Surviving Provisions.

11.05Survivability of Terms. The terms and provisions of the obligations or agreements of the Members under Sections 3.07, 3.08, 3.09, 6.04, 6.05, 7.03, 7.04, 7.05, Article VIII and Section 9.01 and Article XI herein shall survive any termination of this Agreement and will be construed as agreements independent of any other provisions of this Agreement.

11.06Binding Effect. Subject to Article III, this Agreement will be binding on and inure to the benefit of the Parties and their respective legal representatives and trustees.

11.07Governing Law; Severability. This Agreement is governed by and will be construed in accordance with the laws of the State of Delaware, excluding any conflict-of-laws rule or principle (whether under the laws of Delaware or any other jurisdiction) that might refer the governance or the construction of this Agreement to the law of another jurisdiction. If any provision of this Agreement or its application to any Person or circumstance is held invalid or unenforceable to any extent, the remainder of this Agreement and the application of such provision to other Persons or circumstances will not be affected thereby, and such provision will be enforced to the greatest extent permitted by law.

11.08Consent to Jurisdiction; Waiver of Jury Trial. THE COMPANY AND THE PARTIES VOLUNTARILY AND IRREVOCABLY SUBMIT TO THE JURISDICTION OF THE FEDERAL COURTS OF THE UNITED STATES OF AMERICA LOCATED IN HARRIS COUNTY, TEXAS, OVER ANY DISPUTE BETWEEN OR AMONG THE PARTIES OR THE COMPANY AND THE PARTIES ARISING OUT OF THIS AGREEMENT, AND THE COMPANY AND EACH PARTY IRREVOCABLY AGREES THAT ALL SUCH CLAIMS IN RESPECT OF SUCH DISPUTE SHALL BE HEARD AND

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DETERMINED IN SUCH COURTS. THE COMPANY AND THE PARTIES HEREBY IRREVOCABLY WAIVE, TO THE FULLEST EXTENT PERMITTED BY LAW, ANY OBJECTION WHICH THEY MAY NOW OR HEREAFTER HAVE TO THE VENUE OF ANY SUCH DISPUTE ARISING OUT OF THIS AGREEMENT BROUGHT IN SUCH COURT OR ANY DEFENSE OF INCONVENIENT FORUM FOR THE MAINTENANCE OF SUCH DISPUTE. THE COMPANY AND EACH PARTY AGREES THAT A JUDGMENT IN ANY SUCH DISPUTE MAY BE ENFORCED IN OTHER JURISDICTIONS BY SUIT ON THE JUDGMENT OR IN ANY OTHER MANNER PROVIDED BY LAW.

EACH OF THE PARTIES HEREBY VOLUNTARILY AND IRREVOCABLY WAIVES TRIAL BY JURY IN ANY DISPUTE OR OTHER PROCEEDING RELATED THERETO BROUGHT IN CONNECTION WITH THIS AGREEMENT.

11.09Further Assurances. In connection with this Agreement and the transactions contemplated thereby, each Party will execute and deliver any additional documents and instruments and perform any additional acts that may be necessary or appropriate to effectuate and perform the provisions of this Agreement and such transactions.

11.10Title to Company Property. All assets shall be deemed to be owned by the Company as an entity, and no Member, individually, shall have any ownership of such property.

11.11Counterparts. This Agreement may be executed in any number of counterparts with the same effect as if all signatories had signed the same document. All counterparts will be construed together and constitute the same instrument.

11.12Electronic Transmissions. Each of the Parties agrees that (a) any signed consent or signed document transmitted by electronic transmission shall be treated in all manner and respects as an original written document, (b) any such consent or document shall be considered to have the same binding and legal effect as an original document and (c) at the request of any Party, any such consent or document shall be re-delivered or re-executed, as appropriate, by the relevant Party or Parties in its original form. Each of the Parties further agrees that they will not raise the transmission of a consent or document by electronic transmission as a defense in any proceeding or action in which the validity of such consent or document is at issue and hereby forever waives such defense. For purposes of this Agreement, the term “electronic transmission” means any form of communication not directly involving the physical transmission of paper, that creates a record that may be retained, retrieved and reviewed by a recipient thereof, and that may be directly reproduced in paper form by such a recipient through an automated process.

11.13Equitable Relief. The Parties hereby acknowledge and agree that the terms of this Agreement are necessary to protect the Company’s and the Members’ legitimate business interests, and that breaches of this Agreement would cause irreparable harm and injury to the Company and the Members, which cannot adequately be remedied through damages at law. Accordingly, the Parties agree that the remedies of the Company and of the Members may include specific performance, a temporary restraining order, preliminary and permanent

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injunctive relief, or any other equitable relief against any threatened or actual breach by a Party without the need to post bond or other security in connection therewith.

[Signature Page Follows]

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IN WITNESS WHEREOF, the Crestwood Member, the Holdings Member, and, solely for the purposes of Section 4.06(g) and Article XI (as well as any other provisions of this Agreement necessary to give meaning to the foregoing), CEQP have executed this Agreement effective as of the Effective Date.

CRESTWOOD:

CRESTWOOD MIDSTREAM PARTNERS LP

By: Crestwood Midstream GP LLC, its general partner

By: /s/ Robert Halpin    

Name: Robert Halpin

Title: Executive Vice President and Chief Financial Officer

CEQP:

CRESTWOOD EQUITY PARTNERS LP

By: Crestwood Equity GP LLC,
its general partner

By: /s/ Robert Halpin    

Name: Robert Halpin

Title: Executive Vice President and Chief Financial Officer

(Amended and Restated Limited Company Agreement of Crestwood Niobrara LLC)

HOLDINGS MEMBER:

CN JACKALOPE HOLDINGS, LLC

By: /s/ Tyson Yates    Name: Tyson Yates
Title: Vice President

(Amended and Restated Limited Company Agreement of Crestwood Niobrara LLC)

SCHEDULE I

Existing Agreements within the Area of Interest

I. Crestwood Member

An Affiliate of Crestwood is a member of Powder River Basin Industrial Complex, LLC (the “PRB JV”), pursuant to the Amended and Restated Limited Liability Company Agreement of the PRB JV, dated as of August 30, 2013 (as amended, the “PRB LLCA”). The PRB JV’s purpose is to develop, design, finance, construct, own operate and maintain a rail terminal in Converse County, Wyoming. The existing system in the PRB JV shall not be subject to the provisions of Section 6.03(b) and any opportunities that are required to be provided to the PRB JV under the PRB LLCA will not be subject to the provisions of Section 6.03(b) unless such opportunities are rejected by the PRB JV.

Exhibit A

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

Members, Classes, Capital Contributions and Units

Member	Initial Capital Contribution		Additional Capital Contributions	Common Units	Series A-2 Preferred Units
CN Jackalope Holdings, LLC Notices to: ***		$175,000,000	- 0 -	- 0 -	175,000,000
Crestwood Midstream Partners LP Notices to: 811 Main St., Suite 3400 Houston, TX 77002 Attn: General Counsel Facsimile: (832) 519-2250		$139,906,373	- 0 -	139,906,373	- 0 -

Exhibit B

Form of Pre-Distribution Certification

[attached]

FORM OF

PRE-DISTRIBUTION CERTIFICATION

This certificate is being executed and delivered pursuant to Section 5.01(b)(i)(D) of that certain Second Amended and Restated Limited Liability Company Agreement of Crestwood Niobrara LLC (the “Company”),dated as of December [28],2017,as amended from time to time in accordance with the terms thereof (the “LLC Agreement”). Capitalized terms used but not otherwise defined herein shall have the respective meanings ascribed to such terms in the LLC Agreement.

WHEREAS,the Managing Member intends to cause the Company on the date hereof to make a distribution of Available Cash in respect of the Fiscal Quarter ended [●],20[●]pursuant to Section 5.01(b) of the LLC Agreement (the “Distribution”).

NOW,THEREFORE,the undersigned,on behalf of the Company and the Managing Member,hereby certify that as of the date hereof,no Material Adverse Change has occurred,nor will any Material Adverse Change occur as a result of the Company’s making the Distribution.

[Signature Page Follows]

IN WITNESS WHEREOF, the undersigned have executed this certificate as [●], 20[●].

MANAGING MEMBER:

CRESTWOOD MIDSTREAM PARTNERS LP

By: Crestwood Midstream GP LLC, its general partner

By:    

Name
Title

COMPANY:

CRESTWOOD NIOBRARA LLC

By: Crestwood Midstream Partners LP, its managing member

By: Crestwood Midstream GP LLC, its general partner

By:    

Name:
Title:

[Signature Page –Pre-Distribution Certificate]

[Signature Page –Pre-Distribution Certificate]

Exhibit C

Sample Calculation of IRR

[***]

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

Exhibit D

Initial Budget

[***]

SPECIFIC TERMS IN THIS EXHIBIT HAVE BEEN REDACTED BECAUSE CONFIDENTIAL TREATMENT OF THOSE TERMS HAS BEEN REQUESTED. THE REDACTED MATERIAL HAS BEEN SEPARATELY SUBMITTED TO THE SECURITIES AND EXCHANGE COMMISSION, AND THE TERMS HAVE BEEN MARKED AT THE APPROPRIATE PLACE WITH THREE ASTERISKS (***).

EX-4.10

Exhibit 4.10

Execution Version

REGISTRATION RIGHTS AGREEMENT

BY AND BETWEEN

CRESTWOOD EQUITY PARTNERS LP

AND

CN JACKALOPE HOLDINGS, LLC

DATED AS OF DECEMBER 28, 2017

Table of Contents

ARTICLE I DEFINITIONS    1

Section 1.01 Definitions    1

Section 1.02 Registrable Securities    4

Section 1.03 Right and Obligations    4

ARTICLE II REGISTRATION RIGHTS    4

Section 2.01 Registration    4

Section 2.02 Piggyback Rights    7

Section 2.03 Demand Rights    8

Section 2.04 Procedures for Underwritten Offering    8

Section 2.05 Sale Procedures    10

Section 2.06 Cooperation by Holders    13

Section 2.07 Restrictions on Public Sale by Holders of Registrable Securities    13

Section 2.08 Expenses    14

Section 2.09 Indemnification    14

Section 2.10 Rule 144 Reporting    17

Section 2.11 Transfer or Assignment of Registration Rights    17

Section 2.12 Limitation on Subsequent Registration Rights    17

Section 2.13 Removal of Legends; Further Assurances    17

ARTICLE III MISCELLANEOUS    18

Section 3.01 Communications    18

Section 3.02 Successor and Assigns    19

Section 3.03 Assignment of Rights    19

Section 3.04 Recapitalization, Exchanges, Etc. Affecting the Units    19

Section 3.05 Aggregation of Restricted Units    19

Section 3.06 Specific Performance    19

Section 3.07 Counterparts    19

Section 3.08 Headings    19

Section 3.09 Governing Law    19

Section 3.10 Severability of Provisions    19

Section 3.11 Entire Agreement    20

Section 3.12 Amendment    20

Section 3.13 No Presumption    20

Section 3.14 Obligations Limited to Parties to Agreement    20

Section 3.15 Interpretation    20

Section 3.16 Equal Treatment of Holders    21

Section 3.17 Blackout Periods    21

i

001039-0016-16618-Active.23857965.9

REGISTRATION RIGHTS AGREEMENT

THIS REGISTRATION RIGHTS AGREEMENT (this “Agreement”) is made and entered into as of December 28, 2017, by and between CRESTWOOD EQUITY PARTNERS LP, a Delaware limited partnership (“Crestwood”), and CN Jackalope Holdings, LLC, a Delaware limited liability company (“Holdings”).

WHEREAS, this Agreement is made in connection with the entry into the Second Amended and Restated Limited Liability Company Agreement of Crestwood Niobrara LLC by and between Holdings, Crestwood Midstream Partners LP, and solely for the purposes of the provisions set forth therein, Crestwood (the “Company Agreement”); and

WHEREAS, Crestwood has agreed to provide the registration and other rights set forth in this Agreement for the benefit of Holdings pursuant to the Company Agreement.

NOW THEREFORE, in consideration of the mutual covenants and agreements set forth herein and for good and valuable consideration, the receipt and sufficiency of which is hereby acknowledged by each party hereto, the parties hereby agree as follows:

ARTICLE IDEFINITIONS

Section 1.01Definitions. Capitalized terms used herein without definition shall have the meanings given to them in the Company Agreement. The terms set forth below are used herein as so defined:

“Affiliate” means, with respect to a specified Person, any other Person, whether now in existence or hereafter created, directly or indirectly controlling, controlled by or under direct or indirect common control with such specified Person. For purposes of this definition, “control” (including, with correlative meanings, “controlling,” “controlled by,” and “under common control with”) means the power to direct or cause the direction of the management and policies of such Person, directly or indirectly, whether through the ownership of voting securities, by contract or otherwise.

“Agreement” has the meaning specified therefor in the recitals hereof.

“Business Day” means any day other than a Saturday, Sunday or legal holiday on which banks in New York City, New York, are authorized or obligated by law to close.

“Commission” means the United States Securities and Exchange Commission.

“Company Agreement” has the meaning specified therefor in the recitals hereof.

“Crestwood” has the meaning specified therefor in the recitals hereof.

“DTC” means The Depository Trust Company, a New York corporation, or its successor.

“EDGAR” means the Electronic Data Gathering, Analysis and Retrieval System of the Commission, or any successor system thereto.

“Effectiveness Period” has the meaning specified therefor in Section 2.01(a).

“Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time, and the rules and regulations of the Commission promulgated thereunder.

“Holder” means the record holder of any Registrable Securities.

“Holder Underwriter Registration Statement” has the meaning specified therefor in Section 2.05(o).

“Holdings” has the meaning specified therefor in the recitals hereof.

“Included Registrable Securities” has the meaning specified therefor in Section 2.02(a).

“Law” means any statute, law, ordinance, regulation, rule, order, code, governmental restriction, decree, injunction or other requirement of law, or any judicial or administrative interpretation thereof, of any governmental authority.

“Liquidated Damages” has the meaning specified therefor in Section 2.01(b).

“Liquidated Damages Multiplier” has the meaning specified therefor in Section 2.01(b).

“Losses” has the meaning specified therefor in Section 2.09(a).

“Managing Underwriter” means, with respect to any Underwritten Offering, the book running lead manager of such Underwritten Offering.

“Parity Securities” has the meaning specified therefor in Section 2.04(b).

“Person” means any individual, corporation, company, voluntary association, partnership, joint venture, trust, limited liability company, unincorporated organization or government or any agency, instrumentality or political subdivision thereof, or any other form of entity.

“Piggyback Opt-out Notice” has the meaning specified therefor in Section 2.02(a).

“Redemption Price” has the meaning specified therefor in Section 2.01(b).

“Redemption Units” means the CEQP Units to be issued to Holdings Member pursuant to Sections 4.06(b), 4.06(c), 4.06(d)(ii) or 4.06(e) of the Company Agreement.

“Registrable Securities” means (i) the Redemption Units and (ii) any CEQP Units issued as payment of Liquidated Damages pursuant to Section 2.01, all of which Registrable Securities are subject to the rights provided herein until such time as such securities cease to be Registrable Securities pursuant to Section 1.02.

“Registration Expenses” has the meaning specified therefor in Section 2.08(b).

“Resale Registration Statement” means a registration statement under the Securities Act to permit the public resale of the Registrable Securities from time to time, including as permitted by Rule 415 under the Securities Act (or any similar provision then in force under the Securities Act).

2

“Securities Act” means the Securities Act of 1933, as amended from time to time, and the rules and regulations of the Commission promulgated thereunder.

“Selling Expenses” has the meaning specified therefor in Section 2.08(b).

“Selling Holder” means a Holder who is selling Registrable Securities pursuant to a registration statement.

“Selling Holder Indemnified Persons” has the meaning specified therefor in Section 2.09(a).

“Target Effective Date” has the meaning specified therefor in Section 2.01(b).

“Trigger Event” means the delivery of (i) a Consideration Election Notice indicating that the Crestwood Member has elected to acquire any or all of the then-outstanding Series A-2 Preferred Units or Series B Preferred Units through the issuance of CEQP Units in accordance with Section 4.06(b) of the Company Agreement; (ii) written notice from the Crestwood Member that it is making an election pursuant to Section 4.06(c)(2) or Section 4.06(c)(3) of the Company Agreement; (iii) written notice from the Holdings Member that it is making an election pursuant to Section 4.06(d)(ii) of the Company Agreement; or (iv) written notice from the Crestwood Member that it is making an election pursuant to Section 4.06(e)(ii) or Section 4.06(e)(iii) of the Company Agreement.

“Underwritten Offering” means an offering (including an offering pursuant to a Resale Registration Statement) in which CEQP Units are sold to an underwriter on a firm commitment basis for reoffering to the public or an offering that is a “bought deal” with one or more investment banks.

“Underwritten Offering Notice” has the meaning specified therefor in Section 2.03.

“Walled Off Person” has the meaning specified therefor in Section 2.07.

“WKSI” means a well-known seasoned issuer (as defined in the rules and regulations of the Commission).

Section 1.02Registrable Securities. Any Registrable Security will cease to be a Registrable Security (a) when a registration statement covering the Registrable Security becomes or is declared effective by the Commission and the Registrable Security has been sold or disposed of pursuant to such effective registration statement; (b) when such Registrable Security has been disposed of pursuant to any section of Rule 144 (or any similar provision then in force) under the Securities Act; (c) when such Registrable Security has been disposed of in a private transaction pursuant to which the transferor’s rights have not been assigned to the transferee in accordance with Section 2.11; (d) when such Registrable Security is held by Crestwood or its Subsidiaries; or (e) the date on which such Registrable Security may be sold pursuant to any section of Rule 144 under the Securities Act (or any similar provision then in force under the Securities Act) without any restriction (including, if the Holder is an Affiliate of Crestwood, restrictions that apply to sales by Affiliates).

Section 1.03Right and Obligations. Except for the rights and obligations under Section 2.09, all rights and obligations of each Holder under this Agreement, and all rights and obligations of Crestwood under this Agreement with respect to such Holders, shall terminate when such Holder is no longer a Holder.

3

ARTICLE II

REGISTRATION RIGHTS

Section 2.01Registration.

(a)Request for Filing and Deadline To Become Effective. As soon as practicable following the occurrence of a Trigger Event, Crestwood shall, within 30 days, prepare and file a Resale Registration Statement under the Securities Act with respect to all of the Registrable Securities. The Resale Registration Statement filed pursuant to this Section 2.01(a) shall be on such appropriate registration form of the Commission that Crestwood is eligible to use, as reasonably selected by Crestwood. Crestwood shall use its commercially reasonable efforts to cause the Resale Registration Statement to become effective as soon as practicable. Crestwood will use its commercially reasonable efforts to cause the Resale Registration Statement filed pursuant to this Section 2.01 to be continuously effective under the Securities Act until all Registrable Securities covered by the Resale Registration Statement have ceased to be Registrable Securities (the “Effectiveness Period”). The Resale Registration Statement when declared effective (including the documents incorporated therein by reference) will comply as to form in all material respects with all applicable requirements of the Securities Act and the Exchange Act and will not contain an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading (and, in the case of any prospectus contained in such Resale Registration Statement, in the light of the circumstances under which a statement is made). As soon as practicable following the date that the Resale Registration Statement becomes effective, but in any event within two Business Days of such date, Crestwood shall provide the Holders with written notice of the effectiveness of the Resale Registration Statement.

(b)Failure To Become Effective. If the Resale Registration Statement required by Section 2.01(a) does not become or is not declared effective on or before the 60th day following the date it is initially filed pursuant to Section 2.01(a) (the “Target Effective Date”), then Crestwood shall pay each Holder (with respect to the Redemption Units of each such Holder), as liquidated damages and not as a penalty, (i) for each non-overlapping 30-day period for the first 60 days following the Target Effective Date, an amount equal to (A) 0.25% times (B) the product of (x) the CEQP Unit Price used to calculate the number of Redemption Units issued following the occurrence of the applicable Trigger Event (the “Redemption Price”) times (y) the number of Redemption Units then held by such Holder that may not otherwise be disposed of pursuant to Rule 144 without any restriction, including, if the Holder is an Affiliate of Crestwood, restrictions that apply to sales by Affiliates (such product of (x) and (y) being the “Liquidated Damages Multiplier”), and (ii) for each non-overlapping 30-day period beginning on the 61st day following the Target Effective Date, with such payment amount increasing by an additional amount equal to 0.25% times the Liquidated Damages Multiplier per non-overlapping 30-day period for each subsequent 60 days (i.e., 0.5% for 61-120 days, 0.75% for 121-180 days, and 1.0% thereafter) up to a maximum amount equal to 1.0% times the Liquidated Damages Multiplier per non-overlapping 30-day period (the “Liquidated Damages”); provided that the aggregate amount of Liquidated Damages payable by Crestwood per Redemption Unit may not exceed 5.0% of the Redemption Price. The Liquidated Damages payable pursuant to the immediately preceding sentence shall be payable within ten Business Days after the end of each such non-overlapping 30-day period. Any Liquidated Damages (including any

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Liquidated Damages payable pursuant to Section 2.01(e)) shall be paid to each Holder in cash; provided, however, that if (1) Crestwood certifies that it is unable to pay Liquidated Damages in cash because such payment will violate a covenant in an existing credit agreement or other indebtedness or (2) the Resale Registration Statement has not become effective by the Target Effective Date solely as a result of or in connection with a position, determination or action of the Commission with respect to the Resale Registration Statement, and the cure for such failure is beyond the control of Crestwood, then Crestwood may, in its sole discretion, pay the Liquidated Damages in kind in the form of the issuance of additional CEQP Units. Upon any issuance of CEQP Units as Liquidated Damages, Crestwood shall (I) prepare and file an amendment to the Resale Registration Statement prior to its effectiveness adding such CEQP Units to such Resale Registration Statement as additional Registrable Securities and (II) prepare and file a supplemental listing application with the NYSE (or such other market on which the Registrable Securities are then listed and traded) to list such additional CEQP Units. The determination of the number of CEQP Units to be paid as Liquidated Damages shall be based upon the CEQP Unit Price, determined as of the date on which the Liquidated Damages payment is due. The payment of Liquidated Damages under this Section 2.01(b) and Section 2.01(e) to a Holder shall cease at such time as the Resale Registration Statement becomes or is declared effective by the Commission or at such time as the securities included on the Resale Registration Statement are no longer Registrable Securities or may be disposed of pursuant to Rule 144 without any restriction (including, if the Holder is an Affiliate of Crestwood, restrictions that apply to sales by Affiliates), and shall be prorated for any period of less than 30 days in which the Liquidated Damages cease.

(c)Waiver of Liquidated Damages. If Crestwood is unable to cause a Resale Registration Statement to become effective by the Target Effective Date as a result of an acquisition, merger, reorganization, disposition or other similar transaction, then Crestwood may request a waiver of the Liquidated Damages, which may be granted by the consent of the Holders of a majority of the outstanding Registrable Securities that have been included on such Resale Registration Statement, in their sole discretion, and such waiver shall apply to all the Holders of Registrable Securities included on such Resale Registration Statement.

(d)Delay Rights. Notwithstanding anything to the contrary contained herein, Crestwood may, upon written notice to any Selling Holder whose Registrable Securities are included in the Resale Registration Statement or any other registration statement pursuant to Section 2.03, suspend such Selling Holder’s use of any prospectus that is a part of the Resale Registration Statement or any other registration statement pursuant to Section 2.03 (in which event the Selling Holder shall discontinue sales of the Registrable Securities pursuant to the such registration statement but may settle any previously made sales of Registrable Securities) if (i) Crestwood is pursuing an acquisition, merger, reorganization, disposition or other similar transaction and Crestwood determines in good faith that Crestwood’s ability to pursue or consummate such a transaction would be materially adversely affected by any required disclosure of such transaction in the Resale Registration Statement or any other registration statement pursuant to Section 2.03 or (ii) Crestwood has experienced some other material non-public event the disclosure of which at such time, in the good faith judgment of Crestwood, would materially adversely affect Crestwood; provided, however, in no event shall the Selling Holders be suspended from selling Registrable Securities pursuant to the Resale Registration Statement or any other registration statement pursuant to Section 2.03 for a

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period that exceeds an aggregate of 60 days in any 180-day period or 105 days in any 365-day period, in each case, exclusive of days covered by any lock-up agreement executed by a Selling Holder in connection with any Underwritten Offering. Upon disclosure of such information or the termination of the condition described above, Crestwood shall provide prompt notice to the Selling Holders whose Registrable Securities are included in the Resale Registration Statement or any other registration statement pursuant to Section 2.03, and shall promptly terminate any suspension of sales it has put into effect and shall take such other reasonable actions to permit registered sales of Registrable Securities as contemplated in this Agreement.

(e)Additional Rights to Liquidated Damages. If (i) the Holders shall be prohibited from selling their Registrable Securities under the Resale Registration Statement as a result of a suspension pursuant to Section 2.01(d) in excess of the periods permitted therein or (ii) the Resale Registration Statement is filed and declared effective but, during the Effectiveness Period, shall thereafter cease to be effective or fail to be usable for its intended purpose without being succeeded within 60 days by a post-effective amendment pursuant thereto, a supplement to the prospectus or a report filed with the Commission pursuant to Section 13(a), 13(c), 14 or 15(d) of the Exchange Act, then until the suspension is lifted or a post-effective amendment, supplement or report is filed with the Commission and declared effective, but not including any day on which a suspension is lifted or such amendment, supplement or report is declared effective, if applicable, Crestwood shall owe the Holder an amount equal to the Liquidated Damages, following the earlier of (A) the date on which the suspension period exceeded the permitted period or (B) the 61st day after the Resale Registration Statement ceased to be effective or failed to be useable for its intended purposes. All of the provisions in Section 2.01(b) with respect to the payment of the Liquidated Damages, including the time period in which payments are due, shall be applicable to the Liquidated Damages payable hereunder. For purposes of this Section 2.01(e), a suspension shall be deemed lifted on the date that notice that the suspension has been lifted is delivered to the Holders pursuant to Section 3.01.

(f)Termination of Rights. Other than as set forth otherwise in this Agreement, a Holder’s rights (and any transferee’s rights pursuant to Section 2.10) under this Section 2.01, including rights to Liquidated Damages (other than Liquidated Damages owing but not yet paid), shall terminate upon the termination of the Effectiveness Period.

Section 2.02Piggyback Rights.

(a)Underwritten Offering Piggyback Rights. If at any time during the Effectiveness Period, Crestwood proposes to file (i) a registration statement other than the Resale Registration Statement contemplated by Section 2.01(a), or (ii) a prospectus supplement to an effective registration statement, so long as Crestwood is a WKSI at such time or, whether or not Crestwood is a WKSI, so long as the Registrable Securities were previously included in the underlying shelf registration statement or are included on an effective Resale Registration Statement, or in any case in which Holders may participate in such offering without the filing of a post-effective amendment, in each case, for the sale of CEQP Units in an Underwritten Offering for its own account and/or another Person, other than (A) a registration relating solely to employee benefit plans, (B) a registration relating solely to a Rule 145 transaction, or (C) a registration on any registration form that does not permit secondary sales, then as soon as practicable following the engagement of

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counsel by Crestwood to prepare the documents to be used in connection with an Underwritten Offering, Crestwood shall give notice (including notification by electronic mail) of such proposed Underwritten Offering to each Holder owning more than $10.0 million of then-outstanding Registrable Securities, calculated on the basis of the Redemption Price, determined as of the date of such notice, and such notice shall offer each such Holder the opportunity to participate in any Underwritten Offering and to include in such Underwritten Offering such number of Registrable Securities (the “Included Registrable Securities”) as each such Holder may request in writing, subject to any registration rights existing prior to the occurrence of a Trigger Event and customary underwriter cutbacks; provided, however, that Crestwood shall not be required to provide such opportunity (I) to any such Holder that does not offer a minimum of $10.0 million of Registrable Securities (based on the Redemption Price), or (II) to such Holders if Crestwood has been advised by the Managing Underwriter that the inclusion of Registrable Securities for sale for the benefit of the Holders will have an adverse effect on the price, timing or distribution of the CEQP Units in the Underwritten Offering, then the amount of Registrable Securities to be offered for the accounts of Holders shall be determined based on the provisions of Section 2.04(b). Any notice required to be provided in this Section 2.02(a) to Holders shall be provided on a Business Day pursuant to Section 3.01 and receipt of such notice shall be confirmed by the Holder. The Holder will have two Business Days (or one Business Day in connection with any overnight or bought Underwritten Offering) after notice has been delivered to request in writing the inclusion of Registrable Securities in the Underwritten Offering. If no written request for inclusion from a Holder is received within the specified time, each such Holder shall have no further right to participate in such Underwritten Offering. If, at any time after giving written notice of its intention to undertake an Underwritten Offering and prior to the closing of such Underwritten Offering, Crestwood shall determine for any reason not to undertake or to delay such Underwritten Offering, Crestwood may, at its election, give written notice of such determination to the Selling Holders and, (x) in the case of a determination not to undertake such Underwritten Offering, shall be relieved of its obligation to sell any Included Registrable Securities in connection with such terminated Underwritten Offering, and (y) in the case of a determination to delay such Underwritten Offering, shall be permitted to delay offering any Included Registrable Securities for the same period as the delay in the Underwritten Offering. Any Selling Holder shall have the right to withdraw such Selling Holder’s request for inclusion of such Selling Holder’s Registrable Securities in such Underwritten Offering by giving written notice to Crestwood of such withdrawal at or prior to the time of pricing of such Underwritten Offering. Any Holder may deliver written notice (a “Piggyback Opt-Out Notice”) to Crestwood requesting that such Holder not receive notice from Crestwood of any proposed Underwritten Offering; provided, however, that such Holder may later revoke any such Piggyback Opt-Out Notice in writing. Following receipt of a Piggyback Opt-Out Notice from a Holder (unless subsequently revoked), Crestwood shall not be required to deliver any notice to such Holder pursuant to this Section 2.02(a) and such Holder shall no longer be entitled to participate in Underwritten Offerings by Crestwood pursuant to this Section 2.02(a). Holdings shall be deemed to have delivered a Piggyback Opt-Out Notice as of the date hereof.

(b)Termination of Piggyback Registration Rights. The piggyback rights under this Section 2.02 will terminate at the earlier of (i) with respect to a Holder, the time at which such Holder and its Affiliates own less than $10.0 million of Registrable Securities (based on the Redemption Price) or (ii) the CEQP Units cease to be Registrable Securities. When a Holder, together

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with any of its Affiliates who are also Holders, owns less than $10.0 million of Registrable Securities that are CEQP Units (based on the Redemption Price), it must promptly notify Crestwood.

Section 2.03Demand Rights. Holdings shall have the right, at any time from time to time, to elect to include, other than pursuant to Section 2.02 of this Agreement, at least an aggregate of $40.0 million of Registrable Securities (calculated based on the product of the CEQP Unit Price times the number of Registrable Securities) under a registration statement pursuant to an Underwritten Offering, pursuant to and subject to the conditions of this Section 2.03 of this Agreement, exercisable by delivery of a written notice to Crestwood (an “Underwritten Offering Notice”); provided, however, that such right shall not be exercised (i) in respect of more than two Underwritten Offeringsor (ii) more than once in any 180 day period, provided further, however, notwithstanding the foregoing, as of any date of determination, the aggregate number of Underwritten Offerings available as of such date shall be increased by one upon each occurrence of redemption of less than all of the Series A-2 Preferred Units then outstanding that are owned by Holdings in which CEQP Units are issued as consideration for all or a portion of such redemption pursuant to Section 4.06(c) of the Company Agreement. Upon the delivery to Crestwood of any Underwritten Offering Notice, Crestwood shall be obligated to retain underwriters in order to permit Holdings to effect such sale through an Underwritten Offering. In connection with any Underwritten Offering under this Section 2.03, Holdings shall be entitled to select the Managing Underwriter or Underwriters for such Underwritten Offering, subject to the consent of Crestwood not to be unreasonably withheld, delayed or conditioned.

Section 2.04Procedures for Underwritten Offering.

(a)General Procedures. Except as otherwise provided in Section 2.03, in connection with any Underwritten Offering under this Agreement, Crestwood shall be entitled to select the Managing Underwriter or Underwriters in its sole discretion. In connection with an Underwritten Offering contemplated by this Agreement in which a Selling Holder participates, each Selling Holder and Crestwood shall be obligated to enter into an underwriting agreement with the Managing Underwriter or Underwriters that contains such representations, covenants, indemnities and other rights and obligations as are customary in underwriting agreements for firm commitment offerings of equity securities. No Selling Holder may participate in an Underwritten Offering unless such Selling Holder agrees to sell its Registrable Securities on the basis provided in such underwriting agreement and completes and executes all questionnaires, powers of attorney, indemnities and other documents reasonably required under the terms of such underwriting agreement. Each Selling Holder may, at its option, require that any or all of the representations and warranties by, and the other agreements on the part of, Crestwood to and for the benefit of such underwriters also be made to and for such Selling Holder’s benefit and that any or all of the conditions precedent to the obligations of such underwriters under such underwriting agreement also be conditions precedent to its obligations. No Selling Holder shall be required to make any representations or warranties to or agreements with Crestwood or the underwriters other than representations, warranties or agreements regarding such Selling Holder, its authority to enter into such underwriting agreement and to sell, and its ownership of the securities being registered on its behalf and its intended method of distribution and any other representation required by Law. If any Selling Holder disapproves of the terms of an Underwritten Offering, such Selling Holder may elect to withdraw therefrom by

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notice to Crestwood and the Managing Underwriter; provided, however, that any such withdrawal must be made no later than the time of pricing of such Underwritten Offering. If all Selling Holders withdraw from an Underwritten Offering prior to the pricing of such Underwritten Offering, the events will not be considered an Underwritten Offering and will not decrease the number of available Underwritten Offerings that Holdings has the right and option to request under Section 2.03. No such withdrawal or abandonment shall affect Crestwood’s obligation to pay Registration Expenses; provided, however, if (i) certain Selling Holders withdraw from an Underwritten Offering after the public announcement at launch of such Underwritten Offering, and (ii) all Selling Holders withdraw from such Underwritten Offering prior to pricing, then the withdrawing Selling Holders shall pay for all reasonable Registration Expenses incurred by Crestwood during the period from the launch of such Underwritten Offering until the time that all Selling Holders withdraw from such Underwritten Offering.

(b)Priority Rights. If the Managing Underwriter or Underwriters of any proposed Underwritten Offering advises Crestwood that the total amount of Registrable Securities that the Selling Holders and any other Persons intend to include in such offering exceeds the number that can be sold in such offering without being likely to have an adverse effect on the price, timing or distribution of the CEQP Units offered or the market for the CEQP Units, then the CEQP Units to be included in such Underwritten Offering shall include the number of Registrable Securities that such Managing Underwriter or Underwriters advises Crestwood can be sold without having such adverse effect, with such number to be allocated (i) first, to Crestwood (other an Underwritten Offering taken pursuant to Section 2.03) and, (ii) second, pro rata among the Selling Holders who have requested participation in such Underwritten Offering and any other holder of securities of Crestwood having rights of registration that are neither expressly senior nor subordinated to the Registrable Securities (the “Parity Securities”). The pro rata allocations for each Selling Holder who has requested participation in such Underwritten Offering shall be the product of (A) the aggregate number of Registrable Securities proposed to be sold in such Underwritten Offering by the Selling Holders multiplied by (B) the fraction derived by dividing (x) the number of Registrable Securities owned by such Selling Holder by (y) the aggregate number of Registrable Securities owned by all Selling Holders plus the aggregate number of Parity Securities owned by all holders of Parity Securities that are participating in the Underwritten Offering.

Section 2.05Sale Procedures. In connection with its obligations under this Article II, Crestwood will, as expeditiously as possible:

(a)prepare and file with the Commission such amendments and supplements to the Resale Registration Statement and the prospectus used in connection therewith as may be necessary to keep the Resale Registration Statement effective for the Effectiveness Period and as may be necessary to comply with the provisions of the Securities Act with respect to the disposition of all Registrable Securities covered by the Resale Registration Statement;

(b)if a prospectus supplement will be used in connection with the marketing of an Underwritten Offering from a registration statement and the Managing Underwriter at any time shall notify Crestwood in writing that, in the sole judgment of such Managing Underwriter, inclusion of detailed information to be used in such prospectus supplement is of material importance to the

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success of the Underwritten Offering of such Registrable Securities, then Crestwood shall use its reasonable best efforts to include such information in such prospectus supplement;

(c)furnish to each Selling Holder (i) as far in advance as reasonably practicable before filing the Resale Registration Statement or any other registration statement contemplated by this Agreement or any supplement or amendment thereto, upon request, copies of reasonably complete drafts of all such documents proposed to be filed (including exhibits and each document incorporated by reference therein to the extent then required by the rules and regulations of the Commission), and provide each such Selling Holder the opportunity to object to any information pertaining to such Selling Holder and its plan of distribution that is contained therein and make the corrections reasonably requested by such Selling Holder with respect to such information prior to filing the Resale Registration Statement or such other registration statement or supplement or amendment thereto, and (ii) such number of copies of the Resale Registration Statement or such other registration statement and the prospectus included therein and any supplements and amendments thereto as such Selling Holder may reasonably request in order to facilitate the public sale or other disposition of the Registrable Securities covered by such Resale Registration Statement or such other registration statement;

(d)if applicable, use its commercially reasonable efforts to register or qualify the Registrable Securities covered by the Resale Registration Statement or any other registration statement contemplated by this Agreement under the securities or blue sky laws of such jurisdictions as the Selling Holders shall reasonably request; provided, however, that Crestwood will not be required to qualify generally to transact business in any jurisdiction where it is not then required to so qualify or to take any action that would subject it to general service of process in any such jurisdiction where it is not then so subject;

(e)promptly notify each Selling Holder, at any time when a prospectus relating thereto is required to be delivered by any of them under the Securities Act, of (i) the filing of the Resale Registration Statement or any other registration statement contemplated by this Agreement or any prospectus or prospectus supplement to be used in connection therewith, or any amendment or supplement thereto, and, with respect to such Resale Registration Statement or any other registration statement or any post-effective amendment thereto, when the same has become effective; and (ii) the receipt of any written comments from the Commission with respect to any filing referred to in clause (i) and any written request by the Commission for amendments or supplements to the Resale Registration Statement or any other registration statement or any prospectus or prospectus supplement thereto;

(f)immediately notify each Selling Holder, at any time when a prospectus relating thereto is required to be delivered under the Securities Act, of (i) the happening of any event as a result of which the prospectus or prospectus supplement contained in the Resale Registration Statement, as then in effect, includes an untrue statement of a material fact or omits to state any material fact required to be stated therein or necessary to make the statements therein not misleading (in the case of any prospectus contained therein, in the light of the circumstances under which a statement is made); (ii) the issuance or express threat of issuance by the Commission of any stop order suspending the effectiveness of the Resale Registration Statement or any other registration

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statement contemplated by this Agreement, or the initiation of any proceedings for that purpose; or (iii) the receipt by Crestwood of any notification with respect to the suspension of the qualification of any Registrable Securities for sale under the applicable securities or blue sky laws of any jurisdiction. Following the provision of such notice, Crestwood agrees to as promptly as practicable amend or supplement the prospectus or prospectus supplement or take other appropriate action so that the prospectus or prospectus supplement does not include an untrue statement of a material fact or omit to state a material fact required to be stated therein or necessary to make the statements therein not misleading in the light of the circumstances then existing and to take such other commercially reasonable action as is necessary to remove a stop order, suspension, threat thereof or proceedings related thereto;

(g)upon request and subject to appropriate confidentiality obligations, furnish to each Selling Holder copies of any and all transmittal letters or other correspondence with the Commission or any other governmental agency or self-regulatory body or other body having jurisdiction (including any domestic or foreign securities exchange) relating to such offering of Registrable Securities;

(h)make available to the appropriate representatives of the Managing Underwriter and Selling Holders access to such information and Crestwood personnel as is reasonable and customary to enable such parties to establish a due diligence defense under the Securities Act; provided, that Crestwood need not disclose any non-public information to any such representative unless and until such representative has entered into a confidentiality agreement with Crestwood;

(i)otherwise use its commercially reasonable efforts to comply with all applicable rules and regulations of the Commission, and make available to its security holders, as soon as reasonably practicable, an earnings statement, which earnings statement shall satisfy the provisions of Section 11(a) of the Securities Act and Rule 158 promulgated thereunder;

(j)cause all such Registrable Securities registered pursuant to this Agreement to be listed on each securities exchange or nationally recognized quotation system on which similar securities issued by Crestwood are then listed;

(k)use its commercially reasonable efforts to cause the Registrable Securities to be registered with or approved by such other governmental agencies or authorities as may be necessary by virtue of the business and operations of Crestwood to enable the Selling Holders to consummate the disposition of such Registrable Securities;

(l)provide a transfer agent and registrar for all Registrable Securities covered by such registration statement not later than the effective date of such registration statement;

(m)enter into customary agreements and take such other actions as are reasonably requested by the Selling Holders or the underwriters, if any, in order to expedite or facilitate the disposition of such Registrable Securities (including, making appropriate officers of Crestwood available to participate in any “road show” presentations before analysts, and other customary marketing activities (including one-on-one meetings with prospective purchasers of the Registrable Securities), provided, however, in the event, Crestwood, using reasonable best efforts, is unable to

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make such appropriate officers available to participate in connection with any “road show” presentations and other customary marketing activities (whether in person or otherwise), Crestwood shall make such appropriate officers available to participate via conference call or other means of communication in connection with no more than one “road show” presentations per Underwritten Offering);

(n)if requested by a Selling Holder, (i) incorporate in a prospectus supplement or post-effective amendment such information as such Selling Holder reasonably requests to be included therein relating to the sale and distribution of Registrable Securities, including information with respect to the number of Registrable Securities being offered or sold, the purchase price being paid therefor and any other terms of the offering of the Registrable Securities to be sold in such offering; and (ii) make all required filings of such prospectus supplement or post-effective amendment after being notified of the matters to be incorporated in such prospectus supplement or post-effective amendment; and

(o)Crestwood agrees that, if any Holder could reasonably be deemed to be an “underwriter,” as defined in Section 2(a)(11) of the Securities Act, in connection with the Resale Registration Statement and any amendment or supplement thereof (a “Holder Underwriter Registration Statement”), then Crestwood will reasonably cooperate with such Holder in allowing such Holder to conduct customary “underwriter’s due diligence” with respect to Crestwood and satisfy its obligations in respect thereof. In addition, at any Holder’s request, Crestwood will furnish to such Holder, on the date of the effectiveness of the Holder Underwriter Registration Statement and thereafter from time to time on such dates as such Holder may reasonably request, (i) a “cold comfort” letter, dated such date, from Crestwood’s independent certified public accountants in form and substance as is customarily given by independent certified public accountants to underwriters in an underwritten public offering, addressed to such Holder, (ii) an opinion, dated as of such date, of counsel representing Crestwood for purposes of the Holder Underwriter Registration Statement, in form, scope and substance as is customarily given in an underwritten public offering, including a standard “10b-5” opinion for such offering, addressed to such Holder and (iii) a standard officer’s certificate from the chief executive officer or chief financial officer, or other officers serving such functions, of the general partner of Crestwood addressed to the Holder; provided, however, that with respect to any placement agent, Crestwood’s obligations with respect to this Section 2.05 shall be limited to one time, with an additional bring-down request within 30 days of the date of such documents. Crestwood will also permit legal counsel to such Holder to review and comment upon any such Holder Underwriter Registration Statement at least five Business Days prior to its filing with the Commission and all amendments and supplements to any such Holder Underwriter Registration Statement with a reasonable number of days prior to their filing with the Commission and not file any Holder Underwriter Registration Statement or amendment or supplement thereto in a form to which such Holder’s legal counsel reasonably objects. Each Selling Holder, upon receipt of notice from Crestwood of the happening of any event of the kind described in Section 2.05(f), shall forthwith discontinue offers and sales of the Registrable Securities until such Selling Holder’s receipt of the copies of the supplemented or amended prospectus contemplated by Section 2.05(f) or until it is advised in writing by Crestwood that the use of the prospectus may be resumed and has received copies of any additional or supplemental filings incorporated by reference in the prospectus, and, if so directed by Crestwood, such Selling Holder will, or will request the Managing

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Underwriter or Underwriters, if any, to deliver to Crestwood (at Crestwood’s expense) all copies in their possession or control, other than permanent file copies then in such Selling Holder’s possession, of the prospectus covering such Registrable Securities current at the time of receipt of such notice. Notwithstanding anything to the contrary in this Section 2.05, Crestwood will not name a Holder as an underwriter as defined in Section 2(a)(11) of the Securities Act in any Resale Registration Statement or Holder Underwriter Registration Statement, as applicable, without such Holder’s consent. If the staff of the Commission requires Crestwood to name any Holder as an underwriter as defined in Section 2(a)(11) of the Securities Act, and such Holder does not consent thereto, then such Holder’s Registrable Securities shall not be included on the Resale Registration Statement or Holder Underwriter Registration Statement, as applicable, such Holder shall no longer be entitled to received Liquidated Damages under this Agreement with respect thereto and Crestwood shall have no further obligations hereunder with respect to Registrable Securities held by such Holder.

Section 2.06Cooperation by Holders. Crestwood shall have no obligation to include Registrable Securities of a Holder in the Resale Registration Statement, or in an Underwritten Offering pursuant to Section 2.02(a), who has failed to timely furnish such information that Crestwood determines, after consultation with its counsel, is reasonably required in order for the registration statement or prospectus supplement, as applicable, to comply with the Securities Act, including the execution of the initial Selling Unitholder Notice and Questionnaire attached as Exhibit A to this Agreement by the date specified thereon.

Section 2.07Restrictions on Public Sale by Holders of Registrable Securities. For so long as any CEQP Units are Registrable Securities, each Holder agrees that it will not sell any CEQP Units or other equity securities of Crestwood for a period of up to 60 days following the pricing date of an Underwritten Offering of equity securities by Crestwood; provided, however, that the duration of the foregoing restrictions shall be no longer than the duration of the shortest restriction imposed by the underwriters on the officers, directors or any Affiliate of Crestwood. In addition, the provisions of this Section 2.07 shall not apply with respect to a Holder that (a) owns less than $10.0 million of Registrable Securities based on the Redemption Price, or (b) has delivered a Piggyback Opt-Out Notice to Crestwood pursuant to Section 2.02(a). Subject to such Holder’s compliance with its obligations under the U.S. federal securities laws and its internal policies: (i) Holder, for purposes hereof, shall not be deemed to include any employees, subsidiaries or Affiliates that are effectively walled off by appropriate “Chinese Wall” information barriers approved by Holder’s legal or compliance department (and thus have not been privy to any information concerning this transaction) (a “Walled Off Person”) and (ii) the foregoing covenants in this paragraph shall not apply to any transaction by or on behalf of Holder that was effected by a Walled Off Person in the ordinary course of trading without the advice or participation of Holder or receipt of confidential or other information regarding this transaction provided by Holder to such entity.

Section 2.08Expenses.

(a)Expenses. Crestwood will pay all reasonable Registration Expenses as determined in good faith by Crestwood. Each Selling Holder shall pay its pro rata share of all Selling Expenses in connection with any sale of its Registrable Securities hereunder. In addition, except as otherwise

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provided in Section 2.09, Crestwood shall not be responsible for legal fees incurred by Holders in connection with the exercise of such Holders’ rights hereunder.

(b)Certain Definitions.

(i)“Registration Expenses” means all expenses incident to Crestwood’s performance under or compliance with this Agreement to effect the registration of Registrable Securities on the Resale Registration Statement pursuant to Section 2.01 and the disposition of such Registrable Securities, including all registration, filing, securities exchange listing and NYSE fees, all registration, filing, qualification and other fees and expenses of complying with securities or blue sky laws, fees of the Financial Industry Regulatory Authority, fees of transfer agents and registrars, all word processing, duplicating and printing expenses, any transfer taxes and the fees and disbursements of counsel and independent public accountants for Crestwood, including the expenses of any special audits or “cold comfort” letters required by or incident to such performance and compliance.

(ii)“Selling Expenses” means all underwriting fees, discounts and selling commissions or similar fees or arrangements allocable to the sale of the Registrable Securities.

Section 2.09Indemnification.

(a)By Crestwood. In the event of a registration of any Registrable Securities under the Securities Act pursuant to this Agreement, Crestwood will indemnify and hold harmless each Selling Holder thereunder, its directors, officers, managers, employees and agents and each Person, if any, who controls such Selling Holder and its directors, officers, employees or agents (collectively, the “Selling Holder Indemnified Persons”), against any losses, claims, damages, expenses or liabilities (including reasonable attorneys’ fees and expenses) (collectively, “Losses”), joint or several, to which such Selling Holder Indemnified Person may become subject under the Securities Act, the Exchange Act or otherwise, insofar as such Losses (or actions or proceedings, whether commenced or threatened, in respect thereof) arise out of or are based upon any untrue statement or alleged untrue statement of any material fact (in the case of any prospectus, in light of the circumstances under which such statement is made) contained in the Resale Registration Statement or any other registration statement contemplated by this Agreement, any preliminary prospectus, prospectus supplement, free writing prospectus or final prospectus contained therein, or any amendment or supplement thereof, or arise out of or are based upon the omission or alleged omission to state therein a material fact required to be stated therein or necessary to make the statements therein (in the case of a prospectus, in light of the circumstances under which they were made) not misleading, and will reimburse each such Selling Holder Indemnified Person for any legal or other expenses reasonably incurred by them in connection with investigating or defending any such Loss or actions or proceedings; provided, however, that Crestwood will not be liable in any such case if and to the extent that any such Loss arises out of or is based upon an untrue statement or alleged untrue statement or omission or alleged omission so made in conformity with information furnished by

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such Selling Holder Indemnified Person in writing specifically for use in the Resale Registration Statement or such other registration statement, or prospectus supplement, as applicable. Such indemnity shall remain in full force and effect regardless of any investigation made by or on behalf of such Selling Holder Indemnified Person, and shall survive the transfer of such securities by such Selling Holder.

(b)By Each Selling Holder. Each Selling Holder agrees severally and not jointly to indemnify and hold harmless Crestwood, the general partner of Crestwood and each of their respective directors, officers, employees and agents and each Person, if any, who controls Crestwood within the meaning of the Securities Act or of the Exchange Act, and its directors, officers, employees and agents, to the same extent as the foregoing indemnity from Crestwood to the Selling Holders, but only with respect to information regarding such Selling Holder furnished in writing by or on behalf of such Selling Holder expressly for inclusion in the Resale Registration Statement or any other registration statement contemplated by this Agreement, any preliminary prospectus, prospectus supplement, free writing prospectus or final prospectus contained therein, or any amendment or supplement thereof; provided, however, that the liability of each Selling Holder shall not be greater in amount than the dollar amount of the proceeds (net of any Selling Expenses) received by such Selling Holder from the sale of the Registrable Securities giving rise to such indemnification.

(c)Notice. Promptly after receipt by an indemnified party hereunder of notice of the commencement of any action, such indemnified party shall, if a claim in respect thereof is to be made against the indemnifying party hereunder, notify the indemnifying party in writing thereof, but the omission so to notify the indemnifying party shall not relieve it from any liability that it may have to any indemnified party other than under this Section 2.09. In any action brought against any indemnified party, it shall notify the indemnifying party of the commencement thereof. The indemnifying party shall be entitled to participate in and, to the extent it shall wish, to assume and undertake the defense thereof with counsel reasonably satisfactory to such indemnified party and, after notice from the indemnifying party to such indemnified party of its election so to assume and undertake the defense thereof, the indemnifying party shall not be liable to such indemnified party under this Section 2.09 for any legal expenses subsequently incurred by such indemnified party in connection with the defense thereof other than reasonable costs of investigation and of liaison with counsel so selected; provided, however, that, (i) if the indemnifying party has failed to assume the defense or employ counsel reasonably acceptable to the indemnified party or (ii) if the defendants in any such action include both the indemnified party and the indemnifying party and counsel to the indemnified party shall have concluded that there may be reasonable defenses available to the indemnified party that are different from or additional to those available to the indemnifying party, or if the interests of the indemnified party reasonably may be deemed to conflict with the interests of the indemnifying party, then the indemnified party shall have the right to select a separate counsel and to assume such legal defense and otherwise to participate in the defense of such action, with the reasonable expenses and fees of such separate counsel and other reasonable expenses related to such participation to be reimbursed by the indemnifying party (provided appropriate documentation for such expense is also submitted with such notice) as incurred; provided, however, that the indemnified party will be required to repay the indemnifying party any amounts paid to it for which it is determined the indemnified party was not otherwise entitled within five calendar

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days of such determination. Notwithstanding any other provision of this Agreement, no indemnifying party shall settle any action brought against any indemnified party with respect to which such indemnified party is entitled to indemnification hereunder without the consent of the indemnified party, unless the settlement thereof imposes no liability or obligation on, and includes a complete and unconditional release from all liability of, the indemnified party.

(d)Contribution. If the indemnification provided for in this Section 2.09 is held by a court or government agency of competent jurisdiction to be unavailable to any indemnified party or is insufficient to hold them harmless in respect of any Losses, then each such indemnifying party, in lieu of indemnifying such indemnified party, shall contribute to the amount paid or payable by such indemnified party as a result of such Loss in such proportion as is appropriate to reflect the relative fault of the indemnifying party on the one hand and of such indemnified party on the other in connection with the statements or omissions that resulted in such Losses, as well as any other relevant equitable considerations; provided, however, that in no event shall such Selling Holder be required to contribute an aggregate amount in excess of the dollar amount of proceeds (net of Selling Expenses) received by such Selling Holder from the sale of Registrable Securities giving rise to such indemnification. The relative fault of the indemnifying party on the one hand and the indemnified party on the other shall be determined by reference to, among other things, whether the untrue or alleged untrue statement of a material fact or the omission or alleged omission to state a material fact has been made by, or relates to, information supplied by such party, and the parties’ relative intent, knowledge, access to information and opportunity to correct or prevent such statement or omission. The parties hereto agree that it would not be just and equitable if contributions pursuant to this paragraph were to be determined by pro rata allocation or by any other method of allocation that does not take account of the equitable considerations referred to herein. The amount paid by an indemnified party as a result of the Losses referred to in the first sentence of this paragraph shall be deemed to include any legal and other expenses reasonably incurred by such indemnified party in connection with investigating or defending any Loss that is the subject of this paragraph. No person guilty of fraudulent misrepresentation (within the meaning of Section 11(f) of the Securities Act) shall be entitled to contribution from any Person who is not guilty of such fraudulent misrepresentation.

(e)Other Indemnification. The provisions of this Section 2.09 shall be in addition to any other rights to indemnification or contribution that an indemnified party may have pursuant to law, equity, contract or otherwise.

Section 2.10Rule 144 Reporting. With a view to making available the benefits of certain rules and regulations of the Commission that may permit the sale of the Registrable Securities to the public without registration, Crestwood agrees to use its commercially reasonable efforts to:

(a)Make and keep public information regarding Crestwood available, as those terms are understood and defined in Rule 144 of the Securities Act, at all times from and after the date hereof;

(b)File with the Commission in a timely manner all reports and other documents required of Crestwood under the Securities Act and the Exchange Act at all times from and after the date hereof; and

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(c)So long as a Holder owns any Registrable Securities, furnish, unless otherwise available at no charge by access electronically to the Commission’s EDGAR filing system, to such Holder forthwith upon request a copy of the most recent annual or quarterly report of Crestwood, and such other reports and documents so filed with the Commission as such Holder may reasonably request in availing itself of any rule or regulation of the Commission allowing such Holder to sell any such securities without registration.

Section 2.11Transfer or Assignment of Registration Rights. The rights to cause Crestwood to register Registrable Securities under this Article II will be transferable or assignable by Holdings to any Holdings Member or to a transferee or assignee of Registrable Securities, but such rights will only be exercisable by such transferee to the extent that (a) such transferee, at the time such transferee seeks to exercise the rights set forth in this Article II holds Registrable Securities with an aggregate value of at least $10.0 million, based on the Redemption Price, (b) Crestwood is given written notice prior to any such transfer or assignment, stating the name and address of each such transferee and identifying the securities that are being transferred or assigned, and (c) each such transferee agrees in writing to undertake responsibility for its portion of the obligations of the applicable transferor under this Agreement.

Section 2.12Limitation on Subsequent Registration Rights. From and after the date hereof, Crestwood shall not, without the prior written consent of the Holders of a majority of the outstanding Registrable Securities, enter into any agreement with any current or future holder of any securities of Crestwood that would allow such current or future holder to require Crestwood to include securities in any registration statement filed by Crestwood on a basis other than pari passu with, or expressly subordinate to, the priority rights set forth in Section 2.04(b) granted to the Holders of Registrable Securities hereunder.

Section 2.13Removal of Legends; Further Assurances. Crestwood will replace any legended certificates with unlegended certificates promptly upon request by any Holder or at any time after such shares cease to be Registrable Securities or are exempt from registration under the Securities Act. At any time after the removal of such legend, Crestwood shall use commercially reasonable efforts to cause such Registrable Securities to be registered in the name of DTC or its nominee, maintained in book entry form on the books of DTC and allowed to be settled through DTC’s regular book-entry settlement services.

ARTICLE IIIMISCELLANEOUS

Section 3.01Communications. All notices and other communications provided for or permitted hereunder shall be made in writing by facsimile, electronic mail, courier service or personal delivery:

(a)if to Holdings, to the address set forth on Exhibit A to the Company Agreement, with a copy to:

Sidley Austin LLP

1000 Louisiana Street, Suite 6000

17

Houston, Texas 77002

Attention: Cliff W. Vrielink

Facsimile: (713) 495-7799

Email: cvrielink@sidley.com

(b)if to a transferee of Holdings, to such Holder at the address provided pursuant to Section 2.11 above; and

(c)if to Crestwood:

Crestwood Midstream Partners LP

811 Main St., Suite 3400

Houston, TX 77002

Attention: Joel Lambert

Facsimile: (832) 519-2250

Email: Joel.Lambert@crestwoodlp.com

with a copy to:

Simpson Thacher & Bartlett LLP

600 Travis Street, Suite 5400

Houston, Texas 77002

Attention: Chris May

Facsimile: (713) 821-5666

Email: cmay@stblaw.com

All such notices and communications shall be deemed to have been received at the time delivered by hand, if personally delivered; when receipt acknowledged, if sent via facsimile or sent via Internet electronic mail; and when actually received, if sent by courier service or any other means.

Section 3.02Successor and Assigns. This Agreement shall inure to the benefit of and be binding upon the successors and assigns of each of the parties, including subsequent Holders of Registrable Securities to the extent permitted herein.

Section 3.03Assignment of Rights. All or any portion of the rights and obligations of Holdings under this Agreement may be transferred or assigned by Holdings in accordance with Section 2.11.

Section 3.04Recapitalization, Exchanges, Etc. Affecting the Units. The provisions of this Agreement shall apply to the full extent set forth herein with respect to any and all units of Crestwood or any successor or assign of Crestwood (whether by merger, consolidation, sale of assets or otherwise) that may be issued in respect of, in exchange for or in substitution of, the Registrable Securities, and shall be appropriately adjusted for combinations, unit splits, recapitalizations and the like occurring after the date of this Agreement.

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Section 3.05Aggregation of Restricted Units. All Registrable Securities held or acquired by Persons who are Affiliates of one another shall be aggregated together for the purpose of determining the availability of any rights and applicability of any obligations under this Agreement.

Section 3.06Specific Performance. Damages in the event of breach of this Agreement by a party hereto may be difficult, if not impossible, to ascertain, and it is therefore agreed that each such Person, in addition to and without limiting any other remedy or right it may have, will have the right to an injunction or other equitable relief in any court of competent jurisdiction, enjoining any such breach, and enforcing specifically the terms and provisions hereof, and each of the parties hereto hereby waives any and all defenses it may have on the ground of lack of jurisdiction or competence of the court to grant such an injunction or other equitable relief. The existence of this right will not preclude any such Person from pursuing any other rights and remedies at law or in equity that such Person may have.

Section 3.07Counterparts. This Agreement may be executed in any number of counterparts and by different parties hereto in separate counterparts, each of which counterparts, when so executed and delivered, shall be deemed to be an original and all of which counterparts, taken together, shall constitute but one and the same Agreement.

Section 3.08Headings. The headings in this Agreement are for convenience of reference only and shall not limit or otherwise affect the meaning hereof.

Section 3.09Governing Law. The Laws of the State of Delaware shall govern this Agreement without regard to principles of conflicts of Laws that would apply the substantive law of some other jurisdiction.

Section 3.10Severability of Provisions. Any provision of this Agreement that is prohibited or unenforceable in any jurisdiction shall, as to such jurisdiction, be ineffective to the extent of such prohibition or unenforceability without invalidating the remaining provisions hereof or affecting or impairing the validity or enforceability of such provision in any other jurisdiction.

Section 3.11Entire Agreement. This Agreement is intended by the parties as a final expression of their agreement and intended to be a complete and exclusive statement of the agreement and understanding of the parties hereto in respect of the subject matter contained herein. There are no restrictions, promises, warranties or undertakings, other than those set forth or referred to herein with respect to the rights granted by Crestwood set forth herein. This Agreement and the Company Agreement supersede all prior agreements and understandings between the parties with respect to such subject matter.

Section 3.12Amendment. This Agreement may be amended only by means of a written amendment signed by Crestwood and the Holders of a majority of the then-outstanding Registrable Securities (or the Holdings Member, to the extent that no Registrable Securities have been issued); provided, however, that, to the extent that any Registrable Securities have been issued, no such amendment shall materially and adversely affect the rights of any Holder hereunder relative to any other Holder without the consent of such affected Holder.

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Section 3.13No Presumption. If any claim is made by a party relating to any conflict, omission, or ambiguity in this Agreement, no presumption or burden of proof or persuasion shall be implied by virtue of the fact that this Agreement was prepared by or at the request of a particular party or its counsel.

Section 3.14Obligations Limited to Parties to Agreement. Each of the parties hereto covenants, agrees and acknowledges that no Person other than Holdings (and its permitted assignees) and Crestwood shall have any obligation hereunder and that, notwithstanding that Holdings is a corporation, no recourse under this Agreement or under any documents or instruments delivered in connection herewith or therewith shall be had against any former, current or future director, officer, employee, agent, general or limited partner, manager, member, stockholder or Affiliate of any Holdings or any former, current or future director, officer, employee, agent, general or limited partner, manager, member, stockholder or Affiliate of any of the foregoing, whether by the enforcement of any assessment or by any legal or equitable proceeding, or by virtue of any applicable Law, it being expressly agreed and acknowledged that no personal liability whatsoever shall attach to, be imposed on or otherwise by incurred by any former, current or future director, officer, employee, agent, general or limited partner, manager, member, stockholder or Affiliate of Holdings or any former, current or future director, officer, employee, agent, general or limited partner, manager, member, stockholder or Affiliate of any of the foregoing, as such, for any obligations of Holdings under this Agreement or any documents or instruments delivered in connection herewith or therewith or for any claim based on, in respect of or by reason of such obligation or its creation, except in each case for any assignee of Holdings hereunder.

Section 3.15Interpretation. Article, Exhibit and Section references in this Agreement are references to the corresponding Article and Section to this Agreement, unless otherwise specified. All references to instruments, documents, contracts and agreements are references to such instruments, documents, contracts and agreements as the same may be amended, supplemented and otherwise modified from time to time, unless otherwise specified. The word “including” shall mean “including but not limited to.” Whenever any determination, consent or approval is to be made or given by Holdings or a Holder under this Agreement, such action shall be in such Person’s sole discretion unless otherwise specified.

Section 3.16Equal Treatment of Holders. Neither Crestwood nor any of its Affiliates shall, directly or indirectly, offer to pay, pay or cause to be paid any consideration, whether by way of interest, fee, payment for the redemptions or exchange of Registrable Securities, or otherwise, to any holder of Registrable Securities for or as an inducement to, or in connection with solicitation of, any consent, waiver or amendment of any terms or provisions of the Registrable Securities or this Agreement or any of the other agreements referred to in this Agreement unless such consideration is offered to all Holders.

Section 3.17Blackout Periods. Upon the written request of Holdings, Crestwood shall promptly, but in no event later than two Business Days following receipt of such request, notify Holdings in writing whether a blackout period is then applicable to Crestwood’s officers and directors, and the duration of any such blackout period, pursuant to Crestwood’s insider trading policy.

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* * * * * *

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IN WITNESS WHEREOF, the parties have executed this Agreement as of the date first written above.

CRESTWOOD EQUITY PARTNERS LP
By:	Crestwood Equity GP LLC, its general partner
By:
	Name:
	Title:

CN JACKALOPE HOLDINGS, LLC
By:
	Name:
	Title:

Signature Page to Registration Rights Agreement

Exhibit A

Selling Unitholder Notice and Questionnaire

Beneficial owners of [Unit Description] that do not complete this Notice and Questionnaire and deliver it to us as provided below will not be named as selling unitholders in resale registration statements that may be filed by [Issuer] with the Securities and Exchange Commission.

Beneficial owners are encouraged to complete and deliver this Notice and Questionnaire as promptly as practicable after their acquisition of Registrable Securities, and in any case no later than [•], so that such beneficial owners may be named. Please see the fax, email and other contact information on the signature page below.

Certain legal consequences arise from being named a selling unitholder. Beneficial owners are advised to consult their own securities law counsel regarding being named or not being named a selling unitholder in the registration statement.

Notice

The undersigned beneficial owner (the “Selling Unitholder”) of [Unit Description] (“Units”) in [Issuer] (the “Partnership”) acquired in a private placement by the Partnership (such Units, the “Registrable Securities”) hereby gives notice to the Partnership of its intention to sell or otherwise dispose of Registrable Securities beneficially owned by it and listed below in Item 3 (unless otherwise specified under Item 3) pursuant to a registration statement to be filed by the Partnership (the “Resale Registration Statement”) with the Securities and Exchange Commission. The undersigned, by signing and returning this Notice and Questionnaire, understands that it will be bound by the terms and conditions of this Notice and Questionnaire and the Registration Rights Agreement, including the indemnification provisions thereof.

The undersigned hereby provides the following information to the Partnership and represents and warrants that such information is accurate and complete as of the date hereof and undertakes to provide the Partnership with updates of this in formation.

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Questionnaire

1.	(a) Full legal name of Selling Unitholder:
	(b)	Full legal name of the broker-dealer or other third party through which Registrable Securities listed in Item (3) below are held:

(c) Full legal name of the Depository Trust Company participant (if applicable and if not the same as (b) above) through which Registrable Securities listed in (3) below are held:

(d) Full legal name of the Depository Trust Company participant (if applicable and if not the same as (b) above) through which Registrable Securities listed in (3) below are held:

2. Address for Notices to Selling Unitholder:

Email:

Telephone, including area code:

Fax, including area code:

Contact Person:

3. Ownership of Registrable Securities and Other Securities:

Number of Registrable Securities Beneficially Owned:

Unless otherwise indicated in the space provided below, all Registrable Securities listed in response to Item (3) above will be included in the Resale Registration Statement. If the undersigned does not wish all such Registrable Securities to be so included, please indicate below the number of units to be included:

A “beneficial owner” of a security includes:

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(1) Any person who, directly or indirectly, through any contract, arrangement, understanding, relationship, or otherwise has or shares:

(a) voting power which includes the power to vote, or to direct the voting of, such security; and/or,

(b) investment power which includes the power to dispose, or to direct the disposition of, such security;

(2) Any person who, directly or indirectly, creates or uses a trust, proxy, power of attorney, pooling arrangement or any other contract, arrangement, or device with the purpose or effect of divesting such person of beneficial ownership of a security or preventing the vesting of such beneficial ownership as part of a plan or scheme to evade the reporting requirements of

section 13(d) or (g) of the Securities Exchange Act of 1934, as amended; and

(3) Any person who has the right to acquire “beneficial ownership” (defined by reference to paragraph (1) above) of such security within 60 days, including but not limited to any right to acquire: (a) through the exercise of any option, warrant or right; (b) through the conversion of a security; (c) pursuant to the power to revoke a trust, discretionary account, or similar arrangement; or (d) pursuant to the automatic termination of a trust, discretionary account or similar arrangement; provided, however, any person who acquires a security or power specified in clauses (a), (b) or (c) above, with the purpose or effect of changing or influencing the control of the issuer, or in connection with or as a participant in any transaction having such purpose or effect, immediately upon such acquisition shall be deemed to be the beneficial owner of the securities which may be acquired through the exercise or conversion of such security or power.

4. Ownership of Other Securities Owned by the Selling Unitholder:

Except as set forth below in this Item (4), the undersigned is not the beneficial or registered owner of any securities of the Partnership other than the Registrable Securities listed above in Item (3).

(a)	Number of Other Securities of the Partnership beneficially owned by the Selling Unitholder:
(b)	CUSIP No(s).of such other Partnership securities beneficially owned:

5. Voting or Investment Power Over the Selling Unitholder:

A-3

(a)	Names of natural persons or entities who have sole or shared investment power over the Registrable Securities and other securities owned by the Selling Unitholder. For purposes of this Item 5, “voting power” includes the power to vote or direct the voting of such securities, and “investment power” includes the power to dispose or direct the disposition of such securities.
(b)	Describe whether the natural persons or entities named in Item 5(a) have sole voting or investment power over the Registrable Securities and other securities owned by the Selling Unitholder.

6. Relationships with the Partnership:

Except as set forth below, neither the undersigned nor any of its affiliates, officers, directors or principal equity holders (5% or more) has held any position or office or has had any other material relationship with the Partnership (or its predecessors or affiliates) during the past three years.

State any exceptions here:

7. FINRA Relationships

(a) Are you (i) a FINRA Member (see definition below), (ii) a Controlling (see definition below) shareholder of a FINRA Member, (iii) a Person Associated with a Member of FINRA (see definition below), or (iv) an Underwriter or a Related Person (see definition below) with respect to the proposed offering; or (b) do you own any shares of common stock or other securities of any FINRA Member not purchased in the open market; or (c) have you made any outstanding subordinated loans to any FINRA Member?

¨ Yes ¨ No

If yes, please describe below:

FINRA Member. The term “FINRA member” means either any broker or dealer admitted to membership in the Financial Industry Regulatory Authority, formerly known as the National Association of Securities Dealers, Inc. (“FINRA”). (FINRA Manual, Bylaws Article I, Definitions)

Control. The term “control” (including the terms “controlling,” “controlled by” and “under common control with”) means the possession, direct or indirect, of the power, either individually or with others, to direct or cause the direction of the management and policies of a person, whether through the ownership of voting securities, by contract, or otherwise. (Rule 405 under the Securities Act of 1933, as amended)

Person Associated with a Member of FINRA. The term “person associated with a member of FINRA” means every sole proprietor, partner, officer, director, branch manager or executive representative of any FINRA Member, or any natural person occupying a similar status or performing similar functions, or any natural person engaged in the investment banking or securities business who is directly or indirectly controlling or controlled by a

A-4

FINRA Member, whether or not such person is registered or exempt from registration with FINRA pursuant to its bylaws. (FINRA Manual, Bylaws Article 1, Definitions)

Underwriter or a Related Person. The term “underwriter or a related person” means, with respect to a proposed offering, underwriters, underwriters’ counsel, financial consultants and advisors, finders, members of the selling or distribution group, and any and all other persons associated with or related to any of such persons. (FINRA Interpretation)

(b) Have you provided any consulting or other services to the Partnership?

¨ Yes ¨ No

If yes, please provide a detailed description of such services, a statement as to all cash or non-cash compensation received in return for such services, and copies of all agreements or correspondence governing or describing such services:

(c) Do you have any oral or written agreements with any FINRA Member or any person associated with a member of FINRA (see definition below) concerning the disposition of your securities of the Partnership?

¨ Yes ¨ No

If yes, please describe:

8. If you are a FINRA Member or an affiliate of a FINRA Member (i.e. if you answered “yes” to Question 7(a) above), please answer the following questions:

A-5

(a) Do you currently have any plans to acquire, receive, distribute, trade, sell or otherwise participate, in any capacity, in the distribution of the Units to be registered or have you had any discussions, formal or informal, regarding the potential for such an arrangement?

¨ Yes ¨ No

If yes, please provide complete details of any and all items of value received or to be received by FINRA Members and/or affiliates thereof in connection with such sales:

(b) Have you provided or will you be providing any investment banking, commercial banking and/or financial advisory services to the Partnership during the 180-day period preceding the filing of this offering with the SEC or the 90-days following effectiveness of this offering?

¨ Yes ¨ No

(c) If yes, please provide the complete details of such services and any compensation received or to be received for such services:

9. Plan of distribution:

Except as set forth below, the undersigned (including its donees or pledgees) intends to distribute the Registrable Securities listed above in Item (3) pursuant to the Resale Registration Statement only as follows (if at all): Such Registrable Securities may be sold from time to time directly by the undersigned or alternatively through underwriters or broker-dealers or agents. If the Registrable Securities are sold through underwriters or broker-dealers, the Selling Unitholder will be responsible for underwriting discounts or commissions or agents’ commissions and their professional fees. Such Registrable Securities may be sold in one or more transactions at fixed prices, at prevailing market prices at the time of sale, at varying prices determined at the time of sale, or at negotiated prices. Such sales may be effected in transactions (which may involve block transactions) (i) on any national securities exchange or quotation service on which the Registrable Securities may be listed or quoted at the time of sale, (ii) in the over-the-counter market, (iii) in transactions otherwise than on such exchanges or services or in the over-the-counter market or (iv) through the writing of options. In connection with the sales of Registrable Securities or otherwise, the undersigned may enter into hedging transactions with broker-dealers, which may in turn engage in short sales of Registrable Securities in the course of hedging positions they assume. The undersigned may also sell Registrable Securities short and deliver Registrable Securities to close out short positions, or loan or pledge Registrable Securities to broker-dealers that in turn may sell such securities. The Selling Unitholder may pledge or grant a security interest in some or all of the Registrable Securities owned by it and, if it defaults in the performance of its secured obligations, the pledgees or secured parties may offer and sell the Registrable Securities from time to time. The Selling Unitholder also may transfer and donate

A-6

Registrable Securities in other circumstances in which case the transferees, donees, pledgees or other successors in interest will be the Selling Unitholder for purposes of the prospectus.

State any exceptions here:

Note: In no event will such method(s) of distribution take the form of an underwritten offering of the Registrable Securities without the prior agreement of the Partnership.

The undersigned acknowledges that it understands its obligation to comply with the provisions of the Securities Exchange Act of 1934, as amended, and the rules thereunder relating to stock manipulation, particularly Regulation M thereunder (or any successor rules or regulations) and the provisions of the Securities Act relating to prospectus delivery, in connection with any offering of Registrable Securities pursuant to the Resale Registration Statement. The undersigned agrees that neither it nor any person acting on its behalf will engage in any transaction in violation of such provisions.

The Selling Unitholder hereby acknowledges its obligations under the Registration Rights Agreement to indemnify and hold harmless certain persons set forth therein.

In accordance with the undersigned’s obligation under the Registration Rights Agreement to provide such information as may be required by law for inclusion in the Resale Registration Statement, the undersigned agrees to promptly notify the Partnership of any inaccuracies or changes in the information provided herein that may occur subsequent to the date hereof at any time while the Resale Registration Statement remains effective.

All notices hereunder and pursuant to the Registration Rights Agreement shall be made in writing at the address set forth below.

By signing below, the undersigned consents to the disclosure of the information contained herein in its answers to items (1) through (9) above and the inclusion of such information in the Resale Registration Statement and the related prospectus. The undersigned understands that such information will be relied upon by the Partnership in connection with the preparation or amendment of the Resale Registration Statement and the related prospectus.

By signing below, the undersigned agrees that if the Partnership notifies the undersigned that the Resale Registration Statement is not available, the undersigned will suspend use of the prospectus until receipt of notice from the Partnership that the prospectus is again available.

A-7

*********

A-8

IN WITNESS WHEREOF, the undersigned, by authority duly given, has caused this Notice and Questionnaire to be executed and delivered either in person or by its duly authorized agent.

Name of Holder: 

Signature of Authorized Signatory of Holder:

Name of Authorized Signatory:

Title of Authorized Signatory:

Dated:

Signature Page of Notice and Questionnaire

PLEASE RETURN THE COMPLETED AND EXECUTED

NOTICE AND QUESTIONNAIRE:

(1) by fax or email by [•] to:

[Issuer]

Simpson Thacher & Bartlett LLP

600 Travis Street, Suite 5400

Houston, Texas 77002

Attention: Chris May

Facsimile: (713) 821-5666

Email: cmay@stblaw.com

and (2) return the original, executed notice and questionnaire to the same at the address above.

EX-10.2

Exhibit 10.2

OMNIBUS AMENDMENT TO

EMPLOYMENT AGREEMENTS

THIS OMNIBUS AMENDMENT (the “Omnibus Amendment”) to the EMPLOYMENT AGREEMENTS effective January 21, 2014, by and between Crestwood Operations LLC (“the Employer”) and each of Robert G. Phillips (“Phillips”), Robert Halpin (“Halpin”), Steven Dougherty (“Dougherty”), Joel Lambert (“Lambert”) and William H. Moore (“Moore” and, together with Phillips, Halpin, Dougherty and Lambert, the “Employees”), is made and entered into as of February 22, 2018 (the “Omnibus Amendment Date”).

W I T N E S S E T H

WHEREAS, the Employer and Phillips are parties to that certain Employment Agreement effective as of January 21, 2014 (as amended, the “Phillips Employment Agreement”);

WHEREAS, the Employer and Halpin are parties to that certain Employment Agreement effective as of January 21, 2014 (as amended, the “Halpin Employment Agreement”);

WHEREAS, the Employer and Dougherty are parties to that certain Employment Agreement effective as of January 21, 2014 (as amended, the “Dougherty Employment Agreement”);

WHEREAS, the Employer and Lambert are parties to that certain Employment Agreement effective as of January 21, 2014 (as amended, the “Lambert Employment Agreement”);

WHEREAS, the Employer and Moore are parties to that certain Employment Agreement effective as of January 21, 2014 (as amended, the “Moore Employment Agreement” and, together with the Phillips Employment Agreement, the Halpin Employment Agreement, the Dougherty Employment Agreement, the Lambert Employment Agreement, the “Employment Agreements”);

WHEREAS, the parties wish to amend the Employment Agreements to reflect certain changes to be made with respect to the terms and conditions of each Employees employment.

NOW THEREFORE, in consideration of the mutual covenants set forth in this Omnibus Amendment and the Employment Agreements, the Employer and Employees agree as follows:

Amendments to Employment Agreements

1.Effective as of the Omnibus Amendment Date, each of the Employment Agreements (other than the Moore Employment Agreement) is hereby amended by deleting the last three sentences of Section 2.2 in each such Employment Agreement.

2.Effective as of the Omnibus Amendment Date, each of the Employment Agreements is hereby amended by inserting a new Section 2.7 in each such Employment Agreement, to be and read as follows (to be amended only as identified for each respective Employment Agreement):

With respect to the Phillips Employment Agreement

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2.7    If, on or before July 1, 2019, there is a Change in Control (as defined below), the Partnership shall issue 150,000 restricted units to Employee, which amount shall be fully vested on their issuance date.

With respect to the Halpin Employment Agreement

2.7    If, on or before July 1, 2019, there is a Change in Control (as defined below), the Partnership shall issue 100,000 restricted units to Employee, which amount shall be fully vested on their issuance date.

With respect to the Dougherty Employment Agreement

2.7    If, on or before July 1, 2019, there is a Change in Control (as defined below), the Partnership shall issue 75,000 restricted units to Employee, which amount shall be fully vested on their issuance date.

With respect to the Lambert Employment Agreement

2.7    If, on or before July 1, 2019, there is a Change in Control (as defined below), the Partnership shall issue 75,000 restricted units to Employee, which amount shall be fully vested on their issuance date.

With respect to the Moore Employment Agreement

2.7    If, on or before July 1, 2019, there is a Change in Control (as defined below), the Partnership shall issue 75,000 restricted units to Employee, which amount shall be fully vested on their issuance date.

3.    Effective as of the Omnibus Amendment Date, each of the Employment Agreements (other than the Phillips Employment Agreement) is hereby amended by inserting a new Section 3.3(b)(iv) to be and read as follows:

(iv)    If Employee’s employment is terminated during the period beginning three months prior to a Change in Control and ending twelve months after a Change in Control, then the severance amount payable under Section 3.3(b)(i) above shall be increased by changing the reference to “two (2) times” to instead read “three (3) times”.

4.    Effective as of the Omnibus Amendment Date, each of the Employment Agreements is hereby amended by inserting the following at the end of Section 3.3(b) to be and read as follows:

For purposes of this Agreement only, the term “Change in Control” means the occurrence of an event described in paragraphs 1, 2 or 3 below:

2

1.    Crestwood Equity GP LLC (the “General Partner”) ceases to be directly or indirectly controlled by FR XI CMP Holdings LLC, a Delaware limited liability company (the “Fund”) or one or more of its Affiliates (defined below);

2.    The consummation of a reorganization, merger or consolidation of Crestwood Equity Partners LP (the “Partnership”) or sale or other disposition of all or substantially all of the consolidated assets of the Partnership (a “Partnership Transaction”) immediately after which the voting power of the equity securities of the Partnership outstanding immediately prior to such Partnership Transaction do not continue to represent (either by remaining outstanding or by being converted into equity securities having voting power in the entity surviving, resulting from, or succeeding to all or substantially all of the Partnership’s consolidated assets as a result of such Partnership Transaction or any parent of such entity) at least 50% of the combined voting power of the then outstanding equity securities of (A) the entity surviving, resulting from, or succeeding to all or substantially all of the Partnership’s consolidated assets as a result of such Partnership Transaction or (B) any parent of any such entity (including, without limitation, an entity which as a result of such transaction owns the Partnership or all or substantially all of the Partnership’s assets either directly or through one or more subsidiaries); or

3.    The occurrence of any of the following events while the General Partner is controlled by the Fund or one or more Affiliates of the Fund:

(A)    Any individual, entity or group (within the meaning of Section 13(d)(3) or 14(d)(2) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”)) is or becomes the beneficial owner (within the meaning of Rule 13d-3 promulgated under the Exchange Act) of 50% or more of the combined voting power of the then-outstanding voting securities of Crestwood Holdings LLC (“Holdings”); provided, however, that the following acquisitions will not constitute a Change in Control: (i) any acquisition of voting securities of the Company by First Reserve Corporation, or any investment fund over which it maintains voting control, or (ii) any acquisition of voting securities by Robert G. Phillips, or their respective successors, assigns, designees, heirs, beneficiaries, trusts, estates or controlled affiliates;

(B)    A majority of the Board of Directors of the General Partner ceases to be comprised of Incumbent Directors;

(C)    The consummation of a reorganization, merger or consolidation of Holdings or sale or other disposition of all or substantially all of the consolidated assets of Holdings (each, a “Business Combination Transaction”) immediately after which the voting securities of Holdings outstanding immediately prior to such Business Combination Transaction do not continue to represent (either by remaining outstanding or by being converted into equity securities having voting power in the entity surviving, resulting from, or succeeding to all or substantially all of Holdings’ consolidated assets as a result of such Business Combination Transaction or any

3

parent of such entity) at least 50% of the combined voting power of the then outstanding equity securities having voting power in (i) the entity surviving, resulting from, or succeeding to all or substantially all of Holdings’ consolidated assets as a result of such Business Combination Transaction or (ii) any parent of any such entity (including, without limitation, an entity which as a result of such transaction owns Holdings or all or substantially all of Holdings’ assets, either directly or through one or more subsidiaries; or

(D)    The General Partner, or one or more Affiliates of Holdings, ceases to be the general partner of the Partnership.

For purposes of this provision, (i) the term “Affiliate” means, with respect to any individual or a corporation, limited liability company, partnership, joint venture, trust, unincorporated organization, association, government agency or political subdivision thereof or other entity (a “Person”), any other Person that directly or indirectly through one or more intermediaries controls, is controlled by or is under common control with, the Person in question; and (ii) the term “Incumbent Director” means an individual who, as of the Effective Date, is a director of an entity described in this definition, and any individual who becomes a director of such entity subsequent to such date whose election, nomination for election by the entity’s equity holders, or appointment, was approved by a vote of a majority of the then Incumbent Directors (either by a specific vote or by approval of the proxy statement of the applicable entity in which such person is named as a nominee for director, without objection to such nomination). For purposes of this provision, the term “control” means the possession, direct or indirect, of the power to direct or cause the direction of the management and policies of a Person, whether through ownership of voting securities, by contract or otherwise.

5.    Effective as of the Omnibus Amendment Date, the definition of “Non-Compete Period” set forth in Section 4.1 of each of the Employment Agreements is hereby amended to be and read as follows: “a period of twelve (12) months following the Termination Date." In addition, the phrase “during the eighteen-month period” in Section 4.1 of each of the Employment Agreements is hereby deleted and replaced with the phrase “during the twelve-month period”.     

6.    Each of the Employment Agreements remains and continues in full force and effect in accordance with the provisions thereof, as amended by this Omnibus Amendment, and each of the Employment Agreements as amended shall be read and taken and construed as one and the same instrument, respectively.

7.    This Omnibus Amendment may be executed in one or more counterparts, each of which shall be deemed to be an original but all of which together shall constitute one and the same instrument.

[SIGNATURE PAGE FOLLOWS]

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IN WITNESS WHEREOF, the Parties hereto have executed this Omnibus Amendment effective as of the Amendment Date.

EMPLOYER:

CRESTWOOD OPERATIONS LLC

By:

Name:

Title:

PARTNERSHIP:

CRESTWOOD EQUITY PARTNERS LP

BY: CRESTWOOD EQUITY GP LLC, its General Partner

By:

Name:

Title:

EMPLOYEES:

/s/ Robert G. Phillips                    

Robert G. Phillips

/s/ Robert Halpin                    

Robert Halpin

/s/ Steven Dougherty                    

Steven Dougherty

/s/ Joel Lambert                        

Joel Lambert

/s/ William H. Moore                        

William H. Moore

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EX-12.1

Exhibit 12.1

CRESTWOOD EQUITY PARTNERS LP

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(in millions, except for ratio)

	For the Years Ended December 31,
	2017			2016			2015			2014			2013
Earnings:
Pre-tax (loss) income from continuing operations before adjustment for non-controlling interest and equity earnings (including amortization of excess cost of equity investment) per statements of income	$	(215.2	)	$	(223.3	)	$	(2,305.1	)	$	(9.3	)	$	(49.6	)
Add:
Fixed charges	123.3			149.5			166.4			148.7			86.7
Amortized capitalized interest	0.5			0.4			0.4			0.2			0.1
Distributed income of equity investees	47.7			39.0			—			—			—
Less:
Capitalized interest	(2.9		)	(0.7		)	(2.5		)	(7.7		)	(3.4		)
Distributions to non-controlling interest	(15.2		)	(15.2		)	(11.3		)	—			—
Non-controlling interest in pre-tax income of subsidiary with no fixed charges(1)	—			—			—			(16.8		)	(4.9		)
Total earnings available for fixed charges	$	(61.8	)	$	(50.3	)	$	(2,152.1	)	$	115.1		$	28.9
Fixed charges:
Interest and debt expense	102.3			125.8			142.6			134.8			81.3
Interest component of rent	5.8			8.5			12.5			13.9			5.4
Distributions to non-controlling interest	15.2			15.2			11.3			—			—
Total fixed charges	$	123.3		$	149.5		$	166.4		$	148.7		$	86.7
Ratio of earnings to fixed charges(2)(3)	—			—			—			—			—

(1) For the years ended December 31, 2014 and 2013, dividend requirement of preferred securities issued by our consolidated subsidiary was paid in units and therefore were not considered a fixed charge for purposes of this computation.

(2) For purposes of computing the ratio of earnings to fixed charges, "earnings" consists of pretax income from continuing operations before adjustment for non-controlling interest and income from equity investee plus fixed charges (excluding capitalized interest) and amortized capitalized interest. "Fixed charges" represents interest expensed and capitalized, amortization of debt costs, an estimate of the interest within rental expense, and preferred security dividend requirements of consolidated subsidiaries.

(3) Earnings for the years ended December 31, 2017, 2016, 2015, 2014 and 2013 were inadequate to cover fixed charges by approximately $185.1 million, $199.8 million,$2,318.5 million, $33.6 million and $57.8 million.

EX-12.2

Exhibit 12.2

CRESTWOOD MIDSTREAM PARTNERS LP

COMPUTATION OF RATIO OF EARNINGS TO FIXED CHARGES

(in millions, except for ratio)

	For the Years Ended December 31,
	2017			2016			2015			2014			2013
Earnings:
Pre-tax (loss) income from continuing operations before adjustment for non-controlling interest and equity earnings (including amortization of excess cost of equity investment) per statements of income	$	(223.3	)	$	(229.0	)	$	(1,410.6	)	$	15.6		$	(11.7	)
Add:
Fixed charges	123.3			149.5			156.8			132.8			80.5
Amortized capitalized interest	0.5			0.4			0.4			0.2			0.1
Distributed income of equity investees	47.7			39.0			—			—			—
Less:
Capitalized interest	(2.9		)	(0.7		)	(2.5		)	(7.5		)	(3.4		)
Distributions to non-controlling interest	(15.2		)	(15.2		)	(11.3		)	—			—
Non-controlling interest in pre-tax income of subsidiary with no fixed charges(1)	—			—			—			(16.8		)	(4.9		)
Total earnings available for fixed charges	$	(69.9	)	$	(56.0	)	$	(1,267.2	)	$	124.3		$	60.6
Fixed charges:
Interest and debt expense	102.3			125.8			133.0			118.9			75.1
Interest component of rent	5.8			8.5			12.5			13.9			5.4
Distributions to non-controlling interest	15.2			15.2			11.3			—			—
Total fixed charges	$	123.3		$	149.5		$	156.8		$	132.8		$	80.5
Ratio of earnings to fixed charges(2)(3)	—			—			—			—			—

(1) For the years ended December 31, 2014 and 2013, dividend requirement of preferred securities issued by our consolidated subsidiary was paid in units and therefore were not considered a fixed charge for purposes of this computation.

(2) For purposes of computing the ratio of earnings to fixed charges, "earnings" consists of pretax income from continuing operations before adjustment for non-controlling interest and income from equity investee plus fixed charges (excluding capitalized interest) and amortized capitalized interest. "Fixed charges" represents interest expensed and capitalized, amortization of debt costs, an estimate of the interest within rental expense, and preferred security dividend requirements of consolidated subsidiaries.

(3) Earnings for the years ended December 31, 2017, 2016, 2015, 2014 and 2013 were inadequate to cover fixed charges by approximately $193.2 million, $205.5 million, $1,424.0 million, $8.5 million and $19.9 million.

EX-21.1

Exhibit 21.1

List of Subsidiaries of CRESTWOOD EQUITY PARTNERS LP AS OF FEBRUARY 12, 2018

Name	Jurisdiction
Arlington Storage Company, LLC	Delaware
Arrow Field Services, LLC	Delaware
Arrow Midstream Holdings, LLC	Delaware
Arrow Pipeline, LLC	Delaware
Arrow Water, LLC	Delaware
CEQP Finance Corp.	Delaware
CMLP Tres Manager LLC	Delaware
CMLP Tres Operator LLC	Delaware
Cowtown Gas Processing Partners L.P.	Texas
Cowtown Pipeline Partners L.P.	Texas
CPB Member LLC	Delaware
CPB Operator LLC	Delaware
CPB Subsidiary Holdings LLC	Delaware
CPB Water LLC	Delaware
Crestwood Appalachia Pipeline LLC	Texas
Crestwood Arkansas Pipeline LLC	Texas
Crestwood Canada Company	Nova Scotia
Crestwood Crude Logistics LLC	Delaware
Crestwood Crude Services LLC	Delaware
Crestwood Crude Terminals LLC	Delaware
Crestwood Crude Transportation LLC	Delaware
Crestwood Dakota Pipelines LLC	Delaware
Crestwood Delaware Basin LLC	Delaware
Crestwood Energy Services LLC	Delaware
Crestwood Gas Marketing LLC	Delaware
Crestwood Gas Services GP LLC	Delaware
Crestwood Gas Services Operating GP LLC	Delaware
Crestwood Gas Services Operating LLC	Delaware
Crestwood Infrastructure Holdings LLC	Delaware
Crestwood Marcellus Midstream LLC	Delaware
Crestwood Marcellus Pipeline LLC	Delaware
Crestwood Midstream Finance Corp.	Delaware
Crestwood Midstream GP LLC	Delaware
Crestwood Midstream Operations LLC	Delaware
Crestwood Midstream Partners LP	Delaware
Crestwood New Mexico Pipeline LLC	Texas
Crestwood Niobrara LLC	Delaware
Crestwood Ohio Midstream Pipeline LLC	Delaware
Crestwood Operations LLC	Delaware

Crestwood Panhandle Pipeline LLC	Texas
Crestwood Partners LLC	Delaware
Crestwood Permian Basin Holdings LLC	Delaware
Crestwood Permian Basin LLC	Delaware
Crestwood Pipeline and Storage Northeast LLC	Delaware
Crestwood Pipeline East LLC	Delaware
Crestwood Pipeline LLC	Texas
Crestwood Sales & Service Inc.	Delaware
Crestwood Services LLC	Delaware
Crestwood Storage Inc.	Delaware
Crestwood Transportation LLC	Delaware
Crestwood West Coast LLC	Delaware
E. Marcellus Asset Company, LLC	Delaware
Finger Lakes LPG Storage, LLC	Delaware
FR-Crestwood Management Co-Investment LLC	Delaware
IPCH Acquisition Corp.	Delaware
Jackalope Gas Gathering Services, L.L.C.	Oklahoma
Powder River Basin Industrial Complex, LLC	Delaware
Stagecoach Gas Services LLC	Delaware
Stagecoach Operating Services LLC	Delaware
Stagecoach Pipeline & Storage Company LLC	New York
Stellar Propane Service, LLC	Delaware
Tres Palacios Gas Storage LLC	Delaware
Tres Palacios Holdings LLC	Delaware
Tres Palacios Midstream, LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-8 No. 333-201534);

(2) Registration Statement (Form S-8 No. 333-148619);

(3) Registration Statement (Form S-8 No. 333-131767);

(4) Registration Statement (Form S-8 No. 333-83872);

(5) Registration Statement (Form S-3ASR No. 333-194777);

(6) Registration Statement (Form S-3 No. 333-210146);

(7) Registration Statement (Form S-3 No.  333-217062); and

(8) Registration Statement (Form S-3ASR No. 333-217061)

of our reports dated February 23, 2018, with respect to the consolidated financial statements and schedules of Crestwood Equity Partners LP and the effectiveness of internal control over financial reporting of Crestwood Equity Partners LP included in this Annual Report (Form 10-K) of Crestwood Equity Partners LP for the year ended December 31, 2017.

/s/ Ernst & Young LLP

Houston, Texas

February 23, 2018

EX-23.2

Exhibit 23.2

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-3 No. 333-197327);

(2) Registration Statement (Form S-3 No. 333-194778);

(3) Registration Statement (Form S-3 No. 333-185946);

(4) Registration Statement (Form S-8 No. 333-178659); and

(5) Registration Statement (Form S-3ASR No. 333-194776)

of our report dated February 23, 2018, with respect to the consolidated financial statements of Crestwood Midstream Partners LP included in this Annual Report (Form 10-K) of Crestwood Midstream Partners LP for the year ended December 31, 2017.

/s/ Ernst & Young LLP

Houston, Texas

February 23, 2018

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Robert G. Phillips, certify that:

1. I have reviewed this annual report on Form 10-K of Crestwood Equity Partners LP (the “registrant”);

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

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

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

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

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

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

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

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

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

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

Date: February 23, 2018

/s/ Robert G. Phillips

Robert G. Phillips

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Robert T. Halpin, certify that:

1. I have reviewed this annual report on Form 10-K of Crestwood Equity Partners LP (the “registrant”);

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

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

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

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

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

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

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

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

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

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

Date: February 23, 2018

/s/ Robert T. Halpin

Robert T. Halpin

Executive Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, Robert G. Phillips, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 23, 2018

/s/ Robert G. Phillips

Robert G. Phillips

Chairman, President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, Robert T. Halpin, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 23, 2018

/s/ Robert T. Halpin

Robert T. Halpin

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification of the Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350

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

In connection with the Annual Report of Crestwood Equity Partners LP (the “Company”) on Form 10-K for the period ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert G. Phillips, Chief Executive Officer of Crestwood Equity Partners LP, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

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

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

	/s/ Robert G. Phillips
February 23, 2018	Robert G. Phillips Chief Executive Officer

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

EX-32.2

Exhibit 32.2

Certification of the Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350

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

In connection with the Annual Report of Crestwood Equity Partners LP (the “Company”) on Form 10-K for the period ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert T. Halpin, Chief Financial Officer of Crestwood Equity Partners LP, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

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

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

	/s/ Robert T. Halpin
February 23, 2018	Robert T. Halpin Chief Financial Officer

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

EX-32.3

Exhibit 32.3

Certification of the Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350

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

In connection with the Annual Report of Crestwood Midstream Partners LP (the “Company”) on Form 10-K for the period ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert G. Phillips, Chief Executive Officer of Crestwood Midstream Partners LP, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

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

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

	/s/ Robert G. Phillips
February 23, 2018	Robert G. Phillips Chief Executive Officer

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

EX-32.4

Exhibit 32.4

Certification of the Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350

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

In connection with the Annual Report of Crestwood Midstream Partners LP (the “Company”) on Form 10-K for the period ended December 31, 2017, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert T. Halpin, Chief Financial Officer of Crestwood Equity Partners LP, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

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

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

	/s/ Robert T. Halpin
February 23, 2018	Robert T. Halpin Chief Financial Officer

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

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Document and Entity Information - USD ($) $ in Billions	12 Months Ended
	Dec. 31, 2017	Feb. 12, 2018	Jun. 30, 2017
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Trading Symbol	CEQP
Entity Registrant Name	Crestwood Equity Partners LP
Entity Central Index Key	0001136352
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Entity Common Stock, Shares Outstanding		71,231,599
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 1.1
CMLP
Entity Information [Line Items]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2017
Document Fiscal Period Focus	FY
Entity Registrant Name	Crestwood Midstream Partners LP
Entity Central Index Key	0001304464
Current Fiscal Year End Date	--12-31
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		0
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$ 0.0

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Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Assets
Cash	$ 1.3	$ 1.6
Accounts receivable, less allowance for doubtful accounts	442.7	289.8
Inventory	68.4	66.0
Assets from price risk management activities	7.2	6.3
Prepaid expenses and other current assets	10.9	9.7
Total current assets	530.5	373.4
Property, plant and equipment	2,285.2	2,555.4
Less: accumulated depreciation and depletion	464.4	457.8
Property, plant and equipment, net	1,820.8	2,097.6
Intangible assets	788.8	898.6
Less: accumulated amortization	191.6	241.2
Intangible assets, net	597.2	657.4
Goodwill	147.6	199.0
Investments in unconsolidated affiliates	1,183.0	1,115.4
Other assets	5.8	6.1
Total assets	4,284.9	4,448.9
Current liabilities:
Accounts payable	349.4	217.2
Accrued expenses and other liabilities	105.9	90.5
Liabilities from price risk management activities	48.9	28.6
Current portion of long-term debt	0.9	1.0
Total current liabilities	505.1	337.3
Long-term debt, less current portion	1,491.3	1,522.7
Other long-term liabilities	104.7	44.6
Deferred income taxes	3.3	5.3
Commitments and contingencies (Note 15)
Partners’ capital:
Partners' capital	1,393.5	1,782.0
Preferred units	612.0	564.5
Total CEQP/CMLP partners’ capital	2,005.5	2,346.5
Interest of non-controlling partners in subsidiaries	175.0	192.5
Total partners’ capital	2,180.5	2,539.0
Total liabilities and partners’ capital	4,284.9	4,448.9
CMLP
Assets
Cash	1.0	1.3
Accounts receivable, less allowance for doubtful accounts	442.6	289.8
Inventory	68.4	66.0
Assets from price risk management activities	7.2	6.3
Prepaid expenses and other current assets	10.9	9.7
Total current assets	530.1	373.1
Property, plant and equipment	2,615.3	2,885.5
Less: accumulated depreciation and depletion	607.8	587.1
Property, plant and equipment, net	2,007.5	2,298.4
Intangible assets	773.3	883.1
Less: accumulated amortization	177.6	230.2
Intangible assets, net	595.7	652.9
Goodwill	147.6	199.0
Investments in unconsolidated affiliates	1,183.0	1,115.4
Other assets	2.4	1.8
Total assets	4,466.3	4,640.6
Current liabilities:
Accounts payable	346.8	214.5
Accrued expenses and other liabilities	104.7	87.9
Liabilities from price risk management activities	48.9	28.6
Current portion of long-term debt	0.9	1.0
Total current liabilities	501.3	332.0
Long-term debt, less current portion	1,491.3	1,522.7
Other long-term liabilities	102.6	42.0
Deferred income taxes	0.7	0.7
Partners’ capital:
Total CEQP/CMLP partners’ capital	2,195.4	2,550.7
Interest of non-controlling partners in subsidiaries	175.0	192.5
Total partners’ capital	2,370.4	2,743.2
Total liabilities and partners’ capital	$ 4,466.3	$ 4,640.6

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Allowance for doubtful accounts	$ 2.4	$ 1.9
Limited partners' units, issued	70,721,563	69,499,741
Limited partners' units, outstanding	70,721,563	69,499,741
Preferred units, issued	71,257,445	66,533,415
Preferred units, outstanding	71,257,445	66,533,415
CMLP
Allowance for doubtful accounts	$ 2.4	$ 1.9

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Gathering and processing	$ 1,369.1	$ 825.5	$ 1,051.2
Marketing, supply and logistics	2,093.1	1,144.3	857.5
Total product revenue	3,462.2	1,969.8	1,908.7
Gathering and processing	317.3	290.7	325.9
Storage and transportation	37.2	165.3	266.3
Marketing, supply and logistics	62.4	92.1	128.0
Related party (Note 16)	1.8	2.6	3.9
Total services revenues	418.7	550.7	724.1
Total revenues	3,880.9	2,520.5	2,632.8
Costs of product/services sold (exclusive of items shown separately below):
Product costs	3,309.5	1,851.9	1,780.0
Product costs - related party (Note 16)	15.3	17.7	28.9
Service costs	49.9	55.5	74.6
Total costs of products/services sold	3,374.7	1,925.1	1,883.5
Expenses:
Operations and maintenance	136.0	158.1	190.2
General and administrative	96.5	88.2	116.3
Depreciation, amortization and accretion	191.7	229.6	300.1
Total expenses	424.2	475.9	606.6
Loss on long-lived assets, net	(65.6)	(65.6)	(821.2)
Goodwill impairment	(38.8)	(162.6)	(1,406.3)
Loss on contingent consideration	(57.0)	0.0	0.0
Operating income (loss)	(79.4)	(108.7)	(2,084.8)
Earnings (loss) from unconsolidated affiliates, net	47.8	31.5	(60.8)
Interest and debt expense, net	(99.4)	(125.1)	(140.1)
Gain (loss) on modification/extinguishment of debt	(37.7)	10.0	(20.0)
Other income, net	1.3	0.5	0.6
Loss before income taxes	(167.4)	(191.8)	(2,305.1)
(Provision) benefit for income taxes	0.8	(0.3)	1.4
Net loss	(166.6)	(192.1)	(2,303.7)
Net income (loss) attributable to non-controlling partners	(25.3)	(24.2)	636.8
Net income (loss) attributable to parent	(191.9)	(216.3)	(1,666.9)
Net income attributable to preferred units	62.5	28.7	6.2
Net loss attributable to partners	(254.4)	(245.0)	(1,673.1)
Common unitholders’ interest in net loss	$ (254.4)	$ (245.0)	$ (1,673.1)
Net loss per limited partner unit:
Basic (dollars per unit)	$ (3.64)	$ (3.55)	$ (54.00)
Diluted (dollars per unit)	$ (3.64)	$ (3.55)	$ (54.00)
Weighted-average limited partners’ units outstanding (in thousands):
Basic (units)	69,839	69,017	30,983
Dilutive units (units)	0	0	0
Diluted (units)	69,839	69,017	30,983
CMLP
Revenues:
Gathering and processing	$ 1,369.1	$ 825.5	$ 1,051.2
Marketing, supply and logistics	2,093.1	1,144.3	857.5
Total product revenue	3,462.2	1,969.8	1,908.7
Gathering and processing	317.3	290.7	325.9
Storage and transportation	37.2	165.3	266.3
Marketing, supply and logistics	62.4	92.1	128.0
Related party (Note 16)	1.8	2.6	3.9
Total services revenues	418.7	550.7	724.1
Total revenues	3,880.9	2,520.5	2,632.8
Costs of product/services sold (exclusive of items shown separately below):
Product costs	3,309.5	1,851.9	1,780.0
Product costs - related party (Note 16)	15.3	17.7	28.9
Service costs	49.9	55.5	74.6
Total costs of products/services sold	3,374.7	1,925.1	1,883.5
Expenses:
Operations and maintenance	136.0	155.0	188.7
General and administrative	93.1	85.6	105.6
Depreciation, amortization and accretion	202.7	240.5	278.5
Total expenses	431.8	481.1	572.8
Loss on long-lived assets, net	(65.6)	(65.6)	(227.8)
Goodwill impairment	(38.8)	(162.6)	(1,149.1)
Loss on contingent consideration	(57.0)	0.0	0.0
Operating income (loss)	(87.0)	(113.9)	(1,200.4)
Earnings (loss) from unconsolidated affiliates, net	47.8	31.5	(60.8)
Interest and debt expense, net	(99.4)	(125.1)	(130.5)
Gain (loss) on modification/extinguishment of debt	(37.7)	10.0	(18.9)
Other income, net	0.8	0.0	0.0
(Provision) benefit for income taxes	0.0	0.0	0.0
Net loss	(175.5)	(197.5)	(1,410.6)
Net income (loss) attributable to non-controlling partners	(25.3)	(24.2)	(23.1)
Net income (loss) attributable to parent	(200.8)	(221.7)	(1,433.7)
Net income attributable to preferred units	0.0	0.0	23.1
Net loss attributable to partners	$ (200.8)	$ (221.7)	$ (1,456.8)

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Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement of Comprehensive Income [Abstract]
Net loss	$ (166.6)	$ (192.1)	$ (2,303.7)
Change in fair value of Suburban Propane Partners, L.P. units	(0.8)	0.8	(2.7)
Comprehensive loss	(167.4)	(191.3)	(2,306.4)
Comprehensive income (loss) attributable to non-controlling partners	(25.3)	(24.2)	636.8
Comprehensive loss attributable to Crestwood Equity Partners LP	$ (192.7)	$ (215.5)	$ (1,669.6)

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Consolidated Statement of Partners' Capital - USD ($) $ in Millions	Total	CMLP	Common Unit Capital	Common Unit Capital CMLP	Preferred Units	Preferred Units CMLP	Limited Partners	Limited Partners CMLP	Non-Controlling Partners	Non-Controlling Partners CMLP	Partners' Capital [Member]	Preferred Units, Class A	Preferred Units, Class A Preferred Units	Preferred Units, Class A Limited Partners	Preferred Units, Class A Non-Controlling Partners	Subordinated units	Common units	Preferred Units
Common Unit, Outstanding																400,000	18,200,000
Preferred units, outstanding																		0
Partners' Capital Account, Units, Acquisitions																	49,900,000	59,300,000
Balance at the beginning of the period at Dec. 31, 2014	$ 5,584.5	$ 5,320.4			$ 0.0	$ 447.7	$ 776.2	$ 4,701.0	$ 4,808.3	$ 171.7
Increase (Decrease) in Partners' Capital [Roll Forward]
Unit-based compensation charges	19.7	18.1			0.0	0.0	5.7	18.1	14.0	0.0
Partners' Capital Account, Units, Unit-based Compensation																	100,000
Taxes paid for unit-based compensation vesting	(3.7)	(2.1)			0.0	0.0	(1.6)	(2.1)	(2.1)	0.0
Distributions to partners	(405.7)	(819.5)			0.0	0.0	(171.5)	(808.2)	(234.2)	(11.3)
Issuance of CMLP Class A preferred units		58.8				58.8		0.0		0.0
Partners' Capital Account, Exchanges and Conversions	0.0	0.0			529.6	(529.6)	3,294.8	529.6	(3,824.4)	0.0
Issuance of preferred equity of subsidiary												$ 58.8	$ 0.0	$ 0.0	$ 58.8
Change in fair value of Suburban Propane Partners, LP units	(2.7)				0.0		(2.7)		0.0
Other	(0.3)				0.0		(0.2)		(0.1)
Net loss	(2,303.7)	(1,410.6)			6.2	23.1	(1,673.1)	(1,456.8)	(636.8)	23.1
Balance at the end of the period at Dec. 31, 2015	2,946.9	3,165.1			535.8	0.0	2,227.6	2,981.6	183.5	183.5
Common Unit, Outstanding																400,000	68,200,000
Preferred units, outstanding																		60,700,000
Increase (Decrease) in Partners' Capital [Roll Forward]
Preferred units, issued													1,400,000
Unit-based compensation charges	19.2	19.2			0.0	0.0	19.2	19.2	0.0	0.0
Partners' Capital Account, Units, Unit-based Compensation																	900,000
Taxes paid for unit-based compensation vesting	(0.8)	(0.8)			0.0	0.0	(0.8)	(0.8)	0.0	0.0
Distributions to partners	(235.0)	(242.8)			0.0	0.0	(219.8)	(227.6)	(15.2)	(15.2)
Issuance of CMLP Class A preferred units		0.0
Preferred Stock Dividends, Shares																		5,800,000
Change in fair value of Suburban Propane Partners, LP units	0.8				0.0		0.8		0.0
Net loss	(192.1)	(197.5)			28.7	0.0	(245.0)	(221.7)	24.2	24.2
Balance at the end of the period at Dec. 31, 2016	$ 2,539.0	2,743.2			564.5	0.0	1,782.0	2,550.7	192.5	192.5
Common Unit, Outstanding																400,000	69,100,000
Preferred units, outstanding	66,533,415																	66,500,000
Increase (Decrease) in Partners' Capital [Roll Forward]
Preferred units, issued	66,533,415
Proceeds from the issuance of common units			$ 15.2		0.0				0.0		$ 15.2
Noncontrolling Interest, Decrease from Redemptions or Purchase of Interests	$ 0.0	(202.7)	0.0		0.0				(202.7)	(202.7)	(202.7)
Partners' Capital Account, Units, Sold in Public Offering	633,271																600,000
Unit-based compensation charges	$ 25.5	25.5			0.0	0.0	25.5	25.5	0.0	0.0
Partners' Capital Account, Units, Unit-based Compensation																	800,000
Taxes paid for unit-based compensation vesting	(5.5)	(5.5)			0.0	0.0	(5.5)	(5.5)	0.0	0.0
Shares Paid for Tax Withholding for Share Based Compensation																	(200,000)
Distributions to partners	(197.8)	(189.2)			(15.0)	0.0	(167.6)	(174.0)	(15.2)	(15.2)
Issuance of CMLP Class A preferred units		0.0
Issuance of preferred equity of subsidiary	0.0	175.0	0.0		0.0				175.0	175.0	175.0
Preferred Stock Dividends, Shares																		4,800,000
Change in fair value of Suburban Propane Partners, LP units	(0.8)				0.0		(0.8)		0.0
Other		(0.4)	$ (0.9)	$ (0.5)	0.0	0.0			0.1	0.1	$ (0.8)
Net loss	(166.6)	(175.5)			62.5	0.0	(254.4)	(200.8)	25.3	25.3
Balance at the end of the period at Dec. 31, 2017	$ 2,180.5	$ 2,370.4			$ 612.0	$ 0.0	$ 1,393.5	$ 2,195.4	$ 175.0	$ 175.0
Common Unit, Outstanding																400,000	70,300,000
Preferred units, outstanding	71,257,445																	71,300,000
Increase (Decrease) in Partners' Capital [Roll Forward]
Preferred units, issued	71,257,445

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating activities
Net loss	$ (166.6)	$ (192.1)	$ (2,303.7)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion	191.7	229.6	300.1
Amortization of debt-related deferred costs	7.2	6.9	8.9
Market adjustment on interest rate swaps	0.0	0.0	(0.5)
Unit-based compensation charges	25.5	19.2	19.7
Loss on long-lived assets, net	(65.6)	(65.6)	(821.2)
Goodwill impairment	38.8	162.6	1,406.3
Loss on contingent consideration	57.0	0.0	0.0
(Gain) loss on modification/extinguishment of debt	37.7	(10.0)	20.0
(Earnings) loss from unconsolidated affiliates, net, adjusted for cash distributions received	(0.1)	7.6	73.6
Deferred income taxes	(2.1)	(3.1)	(3.6)
Other	0.9	1.9	0.7
Changes in operating assets and liabilities:
Accounts receivable	(170.7)	(76.9)	119.7
Inventory	(9.9)	(22.5)	2.0
Prepaid expenses and other current assets	1.8	9.2	1.8
Accounts payable, accrued expenses and other liabilities	140.1	74.6	(128.0)
Reimbursements of property, plant and equipment	19.6	26.0	73.3
Change in price risk management activities, net	19.4	47.5	29.2
Net cash provided by operating activities	255.9	346.1	440.7
Investing activities
Acquisitions, net of cash acquired	0.0	(7.2)	0.0
Purchases of property, plant and equipment	(188.4)	(100.7)	(182.7)
Investment in unconsolidated affiliates	(58.0)	(12.4)	(42.0)
Capital distributions from unconsolidated affiliates	59.9	14.8	9.3
Net proceeds from sale of assets	225.2	972.7	2.7
Net cash provided by (used in) investing activities	38.7	867.2	(212.7)
Financing activities
Proceeds from the issuance of long-term debt	2,838.6	1,565.3	4,261.8
Payments on long-term debt	(2,913.9)	(2,536.3)	(4,113.0)
Payments on capital leases	(2.7)	(1.9)	(2.2)
Payments for debt-related deferred costs	(1.0)	(3.5)	(17.3)
Financing fees paid for early debt redemption	0.0	0.0	(13.6)
Payments for Repurchase of Redeemable Noncontrolling Interest	(202.7)	0.0	0.0
Distributions to partners	(167.6)	(219.8)	(171.5)
Distributions paid to non-controlling partners	(15.2)	(15.2)	(234.2)
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	15.0	0.0	0.0
Net proceeds from issuance of preferred equity of subsidiary	(175.0)	0.0	0.0
Taxes paid for unit-based compensation vesting	(5.5)	(0.8)	(3.8)
Net proceeds from issuance of common units	15.2	0.0	0.0
Other	(0.1)	0.0	(1.3)
Net cash used in financing activities	(294.9)	(1,212.2)	(236.3)
Net change in cash	(0.3)	1.1	(8.3)
Cash at beginning of period	1.6	0.5	8.8
Cash at end of period	1.3	1.6	0.5
Supplemental disclosure of cash flow information
Cash paid during the period for interest	95.1	121.5	129.0
Cash paid during the period for income taxes	3.1	1.4	4.7
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	(20.4)	(10.5)	(14.1)
Preferred Units, Class A
Financing activities
Net proceeds from issuance of preferred equity of subsidiary	0.0	0.0	(58.8)
CMLP
Operating activities
Net loss	(175.5)	(197.5)	(1,410.6)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion	202.7	240.5	278.5
Amortization of debt-related deferred costs	7.2	6.9	8.1
Unit-based compensation charges	25.5	19.2	18.1
Loss on long-lived assets, net	(65.6)	(65.6)	(227.8)
Goodwill impairment	38.8	162.6	1,149.1
Loss on contingent consideration	57.0	0.0	0.0
(Gain) loss on modification/extinguishment of debt	37.7	(10.0)	18.9
(Earnings) loss from unconsolidated affiliates, net, adjusted for cash distributions received	(0.1)	7.6	73.6
Deferred income taxes	0.0	0.2	(0.3)
Other	0.9	1.9	0.7
Changes in operating assets and liabilities:
Accounts receivable	(170.5)	(76.9)	119.4
Inventory	(9.9)	(22.5)	2.1
Prepaid expenses and other current assets	1.8	7.5	3.7
Accounts payable, accrued expenses and other liabilities	142.0	75.2	(119.8)
Reimbursements of property, plant and equipment	19.6	26.0	73.3
Change in price risk management activities, net	19.4	47.5	29.2
Net cash provided by operating activities	262.2	353.8	471.8
Investing activities
Acquisitions, net of cash acquired	0.0	(7.2)	0.0
Purchases of property, plant and equipment	(188.4)	(100.7)	(182.7)
Investment in unconsolidated affiliates	(58.0)	(12.4)	(41.8)
Capital distributions from unconsolidated affiliates	59.9	14.8	9.3
Net proceeds from sale of assets	225.2	972.7	2.7
Net cash provided by (used in) investing activities	38.7	867.2	(212.5)
Financing activities
Proceeds from the issuance of long-term debt	2,838.6	1,565.3	3,490.1
Payments on long-term debt	(2,913.9)	(2,536.1)	(2,960.9)
Payments on capital leases	(2.7)	(1.9)	(2.2)
Payments for debt-related deferred costs	(1.0)	(3.5)	(17.3)
Financing fees paid for early debt redemption	0.0	0.0	(13.6)
Payments for Repurchase of Redeemable Noncontrolling Interest	(202.7)	0.0
Distributions to partners	(189.2)	(242.8)	(819.5)
Net proceeds from issuance of preferred equity of subsidiary	(175.0)	0.0	0.0
Issuance of CMLP Class A preferred units	0.0	0.0	58.8
Taxes paid for unit-based compensation vesting	(5.5)	(0.8)	(2.1)
Other	0.2	0.0	(0.1)
Net cash used in financing activities	(301.2)	(1,219.8)	(266.8)
Net change in cash	(0.3)	1.2	(7.5)
Cash at beginning of period	1.3	0.1	7.6
Cash at end of period	1.0	1.3	0.1
Supplemental disclosure of cash flow information
Cash paid during the period for interest	95.1	121.5	118.2
Cash paid during the period for income taxes	0.6	0.7	0.6
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$ (20.4)	$ (10.5)	$ (14.1)

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Organization and Description of Business

12 Months Ended

Dec. 31, 2017

Disclosure Partnership Organization And Basis Of Presentation Narrative [Abstract]

Organization and Description of Business

Organization and Description of Business

The accompanying notes to the consolidated financial statements apply to Crestwood Equity Partners LP (the Company, Crestwood Equity or CEQP) and Crestwood Midstream Partners LP (Crestwood Midstream or CMLP) unless otherwise indicated.

Organization

Crestwood Equity Partners LP. CEQP is a publicly-traded (NYSE: CEQP) Delaware limited partnership formed in March 2001. Crestwood Equity GP LLC, which is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), owns our non-economic general partnership interest. Crestwood Holdings, which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve), also owns approximately 25% of Crestwood Equity’s common units and all of its subordinated units.

Crestwood Midstream Partners LP. Crestwood Equity owns a 99.9% limited partnership interest in Crestwood Midstream and Crestwood Gas Services GP LLC (CGS GP), a wholly-owned subsidiary of Crestwood Equity, owns a 0.1% limited partnership interest in Crestwood Midstream. Crestwood Midstream GP LLC, a wholly-owned subsidiary of Crestwood Equity, owns the non-economic general partnership interest of Crestwood Midstream.

The diagram below reflects a simplified version of our ownership structure as of December 31, 2017:

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

Description of Business

Crestwood Equity develops, acquires, owns or controls, and operates primarily fee-based assets and operations within the energy midstream sector. We provide broad-ranging infrastructure solutions across the value chain to service premier liquids-rich natural gas and crude oil shale plays across the United States. We own and operate a diversified portfolio of crude oil and natural gas gathering, processing, storage and transportation assets and connect fundamental energy supply with energy demand across North America. Crestwood Equity is a holding company and all of its consolidated assets are owned by or through its wholly-owned subsidiary, Crestwood Midstream.

Our financial statements reflect three operating and reporting segments described below.

• Gathering and Processing: our gathering and processing (G&P) operations provide gathering and transportation services (natural gas, crude oil and produced water) and processing, treating and compression services (natural gas) to producers in unconventional shale plays and tight-gas plays in North Dakota, West Virginia, Texas, New Mexico, Wyoming and Arkansas. This segment primarily includes (i) our operations that own crude oil, rich and dry gas gathering systems, produced water gathering systems and processing plants in the Bakken, Marcellus, Barnett and Fayetteville Shale plays; and (ii) joint ventures that own rich and dry gas gathering systems and processing plants in the Delaware Permian and Powder River Basin (PRB) Niobrara Shale plays.

• Storage and Transportation: our storage and transportation (S&T) operations provide crude oil and natural gas storage and transportation services to producers, utilities and other customers. This segment primarily includes (i) our integrated crude oil loading, storage and pipeline terminal located in the heart of the Bakken and Three Forks Shale oil-producing areas in Williams County, North Dakota (the COLT Hub); and (ii) joint ventures that own regulated natural gas storage and transportation facilities in New York and Pennsylvania, natural gas storage facilities in Texas and a crude-by-rail terminal in Wyoming.

• Marketing, Supply and Logistics: our marketing, supply and logistics (MS&L) operations provide NGL and crude oil storage, marketing and transportation services to producers, refiners, marketers and other customers. This segment primarily includes (i) our fleet of rail and rolling stock, which includes our rail-to-truck NGL terminals located in Florida, Nevada, New Jersey, New York, Rhode Island and Wyoming, our truck terminal located in Utah, and our truck maintenance facilities located in Indiana, Mississippi, New Jersey and Ohio; (ii) our West Coast processing and fractionation operations located in California; (iii) our Bath and Seymour NGL storage facilities located in New York and Indiana; and (iv) our crude oil and produced water transportation assets.

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Basis of Presentation and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements are prepared in accordance with GAAP and include the accounts of all consolidated subsidiaries after the elimination of all intercompany accounts and transactions. Certain amounts in prior periods have been reclassified to conform to the current year presentation, none of which impacted our previously reported net income, earnings per unit or partners’ capital. 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.

In September 2015, Crestwood Midstream merged with a wholly-owned subsidiary of CEQP, with Crestwood Midstream surviving as a wholly-owned subsidiary of CEQP (the Simplification Merger), and CEQP contributed 100% of its interest in Crestwood Operations LLC (Crestwood Operations) to Crestwood Midstream. As a result of this transaction, Crestwood Midstream controls the operating and financial decisions of Crestwood Operations. Crestwood Midstream accounted for this transaction as a reorganization of entities under common control and the accounting standards related to such transactions requires Crestwood Midstream to record the assets and liabilities of Crestwood Operations at CEQP’s carrying value and retroactively adjust Crestwood Midstream’s historical results to reflect the operations of Crestwood Operations as being acquired on June 19, 2013, the date in which Crestwood Midstream and Crestwood Operations came under common control. Prior to the Simplification Merger, Crestwood Equity consolidated the results of Crestwood Operations in its financial statements and as such, this transaction had no impact on its historical financial statements.

Significant Accounting Policies

Principles of Consolidation

We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination to consolidate or apply the equity method of accounting to an entity can also require us to evaluate whether that entity is considered a variable interest entity (VIE). This evaluation, along with the determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions or activities of an entity and in the case of a VIE, are not the primary beneficiary. We use the cost method of accounting where we are unable to exert significant influence over the entity.

All of our consolidated entities and equity method investments are not VIEs except for our investment in Crestwood Permian Basin Holdings LLC (Crestwood Permian). In October 2016, Crestwood Infrastructure Holdings LLC (Crestwood Infrastructure), our wholly-owned subsidiary, and an affiliate of First Reserve formed a joint venture, Crestwood Permian, to fund and own the Nautilus gathering system and other potential investments in the Delaware Permian. Crestwood Permian is a VIE because it did not have sufficient equity at risk to fund its activities at its inception (i.e., the construction of the Nautilus gathering system) without additional capital contributions from us and First Reserve, and CEQP has provided a guarantee to a third party that requires CEQP to fund 100% of the costs to build the Nautilus gathering system (which is currently estimated to cost approximately $180 million) if Crestwood Permian fails to do so. We account for our investment in Crestwood Permian as an equity method investment because we are not the primary beneficiary of the VIE as of December 31, 2017 and 2016. See Note 6 for a further discussion of our investment in Crestwood Permian.

On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico Pipeline LLC (Crestwood New Mexico), our wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New Mexico. This contribution was treated as a transaction between entities under common control (because of our relationship with First Reserve), and accordingly we deconsolidated Crestwood New Mexico and our investment in Crestwood Permian was increased by the historical book value of these assets of approximately $69.4 million. Crestwood New Mexico was previously included in our G&P segment. The deconsolidation of Crestwood New Mexico was not material to our consolidated financial statements as of and for the year ended December 31, 2017.

On June 3, 2016, our wholly-owned subsidiary, Crestwood Pipeline and Storage Northeast LLC (Crestwood Northeast) and Con Edison Gas Pipeline and Storage Northeast, LLC (CEGP), a wholly-owned subsidiary of Consolidated Edison, Inc. (Consolidated Edison), formed the Stagecoach Gas Services LLC (Stagecoach Gas) joint venture, to own and further develop our natural gas storage and transportation business located in the Northeast (the NE S&T assets). We contributed to the joint venture the entities owning the NE S&T assets, CEGP contributed $975 million in exchange for a 50% equity interest in Stagecoach Gas, and Stagecoach Gas distributed to us the net cash proceeds received from CEGP. The assets contributed to the joint venture were previously included in our S&T segment.

We deconsolidated the NE S&T assets as a result of the contribution of these assets to Stagecoach Gas and began accounting for our 50% equity interest in Stagecoach Gas under the equity method of accounting. The deconsolidation of our NE S&T assets resulted in a decrease of $1,127.6 million in property, plant and equipment, net, $8.5 million of intangible assets, net and $11.2 million of other assets and (liabilities), net. For a discussion of the decrease in goodwill associated with this joint venture transaction, see “Goodwill” below. See Note 6 for a further discussion of our investment in Stagecoach Gas.

Use of Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these consolidated financial statements. Actual results can differ from those estimates.

Cash

We consider all highly liquid investments with an original maturity of less than three months to be cash.

Inventory

Inventory for our marketing, supply and logistics operations are stated at the lower of cost or market and cost is computed predominantly using the average cost method. Our inventory consists primarily of crude oil and NGLs of approximately $67.9 million and $56.7 million at December 31, 2017 and 2016.

Property, Plant and Equipment

Property, plant and equipment is recorded at is original cost of construction or, upon acquisition, at the fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and interest. We capitalize major units of property replacements or improvement and expense minor items. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Gathering systems and pipelines	15 - 20
Facilities and equipment	3 - 25
Buildings, rights-of-way and easements	1 - 40
Office furniture and fixtures	5 - 10
Vehicles	5

We depleted salt deposits included in our property, plant and equipment utilizing the unit of production method prior to their sale in December 2017.

We evaluate our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset, which is typically based on discounted cash flow projections using assumptions as to revenues, costs and discount rates typical of third party market participants, which is a Level 3 fair value measurement.

During 2017 and 2015, we recorded the following impairments of our property, plant and equipment and we reflected these impairments in loss on long-lived assets in our consolidated statements of operations. We did not record impairments of our property, plant and equipment during the year ended December 31, 2016.

• During 2017, we incurred $81.4 million of impairments of our property, plant and equipment related to our MS&L West Coast operations, which resulted from decreasing the forecasted cash flows to be generated by those operations. The fair value of our property, plant and equipment related to our West Coast operation was $66.4 million as of December 31, 2017. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future.

• During 2015, we incurred $8.5 million of impairments of our property, plant and equipment related to our Granite Wash gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our major customer of those assets declared bankruptcy and ceased substantial drilling in the Granite Wash in the near future given current and future anticipated market conditions related to natural gas and NGLs.

• During 2015, Crestwood Equity incurred a $354.4 million impairment of its property, plant and equipment related to its Barnett gathering and processing operations, which resulted from the actions of our primary customer in the Barnett Shale, Quicksilver Resources, Inc. (Quicksilver), related to its filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015. Crestwood Midstream did not record an impairment of its property, plant and equipment related to its gathering and processing assets in the Barnett Shale as the sum of the undiscounted cash flows expected to result from the use of the assets and their eventual disposition exceeded the carrying value of the property, plant and equipment by over 30%. As a result, Crestwood Midstream’s property, plant and equipment exceeds Crestwood Equity’s property, plant and equipment related to its gathering and processing assets in the Barnett Shale.

• During 2015, we incurred $61.9 million and $45.7 million of impairments of property, plant and equipment related to our Fayetteville and Haynesville gathering and processing operations, respectively, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas.

• During 2015, we incurred a $31.2 million impairment of our property, plant and equipment related to our Watkins Glen development project in our marketing, supply and logistics operations, which resulted from continued delays and uncertainties in the permitting of our proposed NGL storage facility.

At December 31, 2017, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 12% discount rate and projected cash flows, which is a Level 3 fair value measurement. At December 31, 2015, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 15% discount rate and projected cash flows, which is a Level 3 fair value measurement. Projected cash flows of our property, plant and equipment are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, constructions costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Identifiable Intangible Assets

Our identifiable intangible assets consist of customer accounts, covenants not to compete, trademarks and certain revenue contracts. Customer accounts, covenants not to compete, trademarks and certain of our revenue contracts have arisen from acquisitions. We amortize certain of our revenue contracts based on the projected cash flows associated with these contracts if the projected cash flows are readily determinable, otherwise we amortize our revenue contracts on a straight-line basis.  We recognize acquired intangible assets separately if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

During 2017, 2016 and 2015, we recorded the following impairments of our intangible assets and we reflected these impairments in loss on long-lived assets in our consolidated statements of operations:

• During 2017, we fully impaired $0.8 million of intangible assets related to our MS&L West Coast operations, which resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future.

• During 2016, we incurred a $31.4 million impairment of intangible assets related to our MS&L Trucking operations, which resulted from the impact of increased competition on our Trucking business and the loss of several key customer relationships that were acquired in 2013 to which the intangible assets related.

• During 2015, Crestwood Equity fully impaired $238.9 million of its intangible assets related to its Barnett gathering and processing operations, which resulted from the actions of our primary customer in the Barnett Shale, Quicksilver, related to filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015.

• During 2015, we fully impaired $70.9 million and $6.0 million of intangible assets related to our Fayetteville and Haynesville gathering and processing operations, respectively, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas.

At December 31, 2016, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 19% discount rate and projected cash flows, which is a Level 3 fair value measurement. At December 31, 2015, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 15% discount rate and projected cash flows, which is a Level 3 fair value measurement. Projected cash flows of our intangible assets are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:

	Weighted-Average Life (years)
Customer accounts and revenue contracts	20
Trademarks	6 - 8

Assets Held for Sale

We classify assets (or groups of assets) to be disposed of as held for sale when specific criteria have been met. Assets classified as held for sale are recorded at the lower of the carrying value or the estimated fair value less cost to sell of those assets. The fair value is based on the consideration to be received, which is a Level 3 fair value measurement. We cease depreciation and amortization of the assets in the period they are considered held for sale. We classified approximately $3.0 million of property, plant and equipment related to our Marcellus gathering and processing assets as assets held for sale (which is included in prepaid expenses and other current assets) on our consolidated balance sheet at their fair value at December 31, 2017. In addition, we recorded a loss on long-lived assets of approximately $2.5 million during the year ended December 31, 2017 related to these assets. The sale is contingent upon customary approvals and satisfaction of certain other closing conditions, which we believe is probable at December 31, 2017.

Goodwill

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

We estimate the fair value of our reporting units based on a number of factors, including discount rates, projected cash flows and the potential value we would receive if we sold the reporting unit. We also compare the total fair value of our reporting units to our overall enterprise value, which considers the market value for our common and preferred units. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our reporting units (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our customers, such as their future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. If the assumptions embodied in the projections prove inaccurate, we could incur a future impairment charge. In addition, the use of the income approach to determine the fair value of our reporting units (see further discussion of the use of the income approach below) could result in a different fair value if we had utilized a market approach, or a combination thereof.

We acquired substantially all of our reporting units in 2013, 2012 and 2011, which required us to record the assets, liabilities and goodwill of each of those reporting units at fair value on the date they were acquired. As a result, any level of decrease in the forecasted cash flows of these businesses or increases in the discount rates utilized to value those businesses from their respective acquisition dates would likely result in the fair value of the reporting unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill is impaired.

Current commodity prices are significantly lower compared to commodity prices during 2014, and that decrease has adversely impacted forecasted cash flows, discount rates and stock/unit prices for most companies in the midstream industry, including us. As a result, we recorded goodwill impairments on several of our reporting units during 2017, 2016 and 2015. At December 31, 2017, our accumulated goodwill impairments at CEQP and CMLP were approximately $1,656.5 million and $1,399.3 million, respectively. During 2017, we adopted the provisions of ASU 2017-04, Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which allows companies to apply a single test to determine if goodwill is impaired and the amount of any impairment, which is reflected in our 2017 goodwill impairments. The following table summarizes the goodwill of our various reporting units (in millions):

	Goodwill Impairments during the Year Ended December 31, 2015		Goodwill at January 1, 2016		Goodwill Impairments during the Year Ended December 31, 2016		Other				Goodwill at December 31, 2016		Impact of Sale of US Salt				Goodwill Impairments during the Year Ended December 31, 2017		Goodwill at December 31, 2017
G&P
Fayetteville	$	72.5	$	—	$	—	$	—			$	—	$	—			$	—	$	—
Marcellus	—		8.6		8.6		—				—		—				—		—
Arrow	—		45.9		—		—				45.9		—				—		45.9
S&T
Northeast Storage and Transportation	—		726.3		—		(726.3		)	(1)	—		—				—		—
COLT	623.4		44.9		44.9		—				—		—				—		—
MS&L																			—
West Coast	85.9		—		—		2.4			(2)	2.4		—				2.4		—
Supply and Logistics	99.0		167.2		65.5		—				101.7		—				—		101.7
Storage and Terminals	53.7		50.5		14.1		—				36.4		—				36.4		—
US Salt	—		12.6		—		—				12.6		(12.6		)	(3)	—		—
Trucking	148.4		29.5		29.5		—				—		—				—		—
Watkins Glen	66.2		—		—		—				—		—				—		—
Total CMLP	$	1,149.1	$	1,085.5	$	162.6	$	(723.9	)		$	199.0	$	(12.6	)		$	38.8	$	147.6
Barnett (G&P)	257.2		—		—		—				—		—				—		—
Total CEQP	$	1,406.3	$	1,085.5	$	162.6	$	(723.9	)		$	199.0	$	(12.6	)		$	38.8	$	147.6

(1) Reflects impact of the deconsolidation of our NE S&T assets in June 2016.

(2) In December 2016, we acquired four NGL terminals for our MS&L segment for approximately $7.2 million with total goodwill of approximately $2.4 million. This acquisition was not material to our consolidated financial statements as of and for the year ended December 31, 2016.

(3) In December 2017, we sold 100% of our equity interests in US Salt to an affiliate of Kissner Group Holdings LP.

The goodwill impairments recorded during 2017 related to our MS&L West Coast and Storage and Terminals operations. The goodwill impairment related to our MS&L West Coast operations resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for gathering, processing and logistics services from our West Coast operations to remain relatively flat over the past several years. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. The goodwill impairment related to our MS&L Storage and Terminals operations resulted from decreasing forecasted cash flows to be generated by those operations. During 2017, we experienced NGL market headwinds in the Northeast with NGL exports and other market dynamics causing price differentials to narrow between purchasing NGLs in the summer (which are then stored in our NGL facilities) and selling NGLs in the winter. These dynamics also caused the rates that we are able to charge for storing NGLs in our facilities to decline from their historical levels. Although our MS&L Storage and Terminals operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the decrease that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. We utilized the income approach to determine the fair value of our reporting units given the limited availability of comparable market-based transactions during 2017, and we utilized discount rates ranging from 10% to 12% in applying the income approach to determine the fair value of our reporting units with goodwill as of December 31, 2017, which is a Level 3 fair value measurement.

The goodwill impairments recorded during 2016 related to our G&P Marcellus operations, our MS&L Supply and Logistics and Storage and Terminals operations, our S&T COLT operations and our MS&L Trucking operations. The 2016 goodwill impairments on our Marcellus, Supply and Logistics, and Storage and Terminals operations primarily resulted from increasing the discount rates utilized in determining the fair value of those reporting units considering the significant decrease in the market price of our common units during the first quarter of 2016 and the continued decrease in commodity prices and its impact on the midstream industry and our customers. The 2016 goodwill impairments on our COLT and Trucking operations also resulted from those factors, but in addition they were impacted by (i) the expiration of two key crude-by-rail loading contracts during the fourth quarter of 2016, and the impact of those expirations on our projected future cash flows from our COLT operations; and (ii) the continued impact of increased competition on our Trucking business, a change in management in late 2016, and the planned downsizing of the excess capacity in our trucking fleet and operations and the impact that these had on our projected future cash flows from our Trucking operations. Although certain of these operations experienced increases in their operating results from 2013 to 2016, we decreased the cash flow forecasts for those businesses from the expectations when they were acquired in 2012 and 2013 based on our current assessment of the impact that the prolonged low commodity price environment is expected to have on demand for future services provided by those operations. We utilized the income approach to determine the fair value of our reporting units given the limited availability of comparable market-based transactions during 2016, and we utilized discount rates ranging from 10% to 19% in applying the income approach to determine the fair value of our reporting units with goodwill as of December 31, 2016, which is a Level 3 fair value measurement.

The goodwill impairments recorded during 2015 primarily resulted from decreasing forecasted cash flows and increasing the discount rates utilized in determining the fair value of the reporting units considering the continued decrease in commodity prices and its impact on the midstream industry and our customers. We utilized the income approach to determine the fair value of our reporting units given the limited availability of comparable market-based transactions during 2015, and we utilized discount rates ranging from 9% to 12% in 2015 in applying the income approach to determine the fair value of our reporting units with goodwill as of December 31, 2015.

In addition to the goodwill impairments recorded by Crestwood Midstream as reflected in the table above, Crestwood Equity recorded a goodwill impairment of its Barnett reporting unit of approximately $257.2 million in 2015. The impairment primarily resulted from increasing the discount rate utilized in determining the fair value of the reporting unit, considering the actions of its primary customer in the Barnett Shale during 2015, Quicksilver, related to its filing for protection under Chapter 11 of the U.S. Bankruptcy Code in March 2015.

Investment in Unconsolidated Affiliates

Equity method investments in which we exercise significant influence, but do not control and are not the primary beneficiary, are accounted for using the equity method of accounting. Differences in the basis of investments and the separate net asset values of the investees, if any, are amortized into net income or loss over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill. We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, or if we decide to sell an investment in unconsolidated affiliate, we adjust the carrying values of the asset downward, if necessary, to their estimated fair values.

During 2015, we recorded a $51.4 million and $23.4 million impairment of our Jackalope Gas Gathering Services, L.L.C. (Jackalope) and Powder River Basin Industrial Complex, LLC (PRBIC) equity method investments, respectively, as a result of decreasing forecasted cash flows and increasing the discount rates utilized in determining the fair value of the equity method investments considering the continued decrease in commodity prices and its impact on the midstream industry and our equity method investments’ customers, which is a Level 3 fair value measurement. We did not record impairments of our equity method investments during the years ended December 31, 2017 and 2016.

We estimated the fair value of our equity method investments at December 31, 2015 based on projected cash flows, a 15.5% discount rate and the potential value we would receive if we sold the equity method investment. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our equity method investments (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our equity method investments’ customers, such as future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Asset Retirement Obligations

An asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. We record a liability for legal or contractual obligations to retire our long-lived assets associated with our facilities and right-of-way contracts we hold. We record a liability in the period the obligation is incurred and estimable. An ARO is initially recorded at its estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the fair value of the liability as a result of the passage of time, which we record as depreciation, amortization and accretion expense on our consolidated statements of operations. The fair value of certain AROs could not be determined as the settlement dates (or range of dates) associated with these assets were not estimable. At December 31, 2017 and 2016, our AROs were reflected in other long-term liabilities on our consolidated balance sheets. See Note 5 for a further discussion of our AROs.

Deferred Financing Costs

Deferred financing costs represent costs associated with obtaining long-term financing and are amortized over the term of the

related debt using a method which approximates the effective interest method and has a weighted average life of five years. At December 31, 2017 and 2016, our net deferred financing costs were reflected as a reduction of long-term debt on our consolidated balance sheets.

Revenue Recognition

We gather, process, treat, compress, store, transport and sell various commodities (including crude oil, natural gas, NGLs and water) pursuant to fixed-fee and percent-of-proceeds contracts. Under certain of those contracts in our G&P operations and our MS&L operations, we take title to the underlying commodity. We classify the revenues associated with the products to which we take title as product revenues and all other revenues as service revenues in our consolidated statement of operations.

We recognize revenues for these services and products when all of the following criteria are met:

• services have been rendered or products delivered or sold;

• persuasive evidence of an exchange arrangement exists;

• the price for services is fixed or determinable; and

• collectability is reasonably assured.

We record deferred revenue when we receive amounts from our customers but have not met the criteria listed above. We recognize deferred revenue in our consolidated statements of operations when the criteria has been met and all services have been rendered. At December 31, 2017 and 2016, we had deferred revenue of approximately $0.6 million and $7.5 million, which is reflected in accrued expenses and other liabilities on our consolidated balance sheets.

Credit Risk and Concentrations

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.

Income Taxes

Crestwood Equity is a master limited partnership and Crestwood Midstream is a limited partnership. Partnerships are generally not subject to federal income tax, although publicly-traded partnerships are treated as corporations for federal income tax purposes and therefore are subject to federal income tax, unless the partnership generates at least 90% of its gross income from qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a partnership for federal income tax purposes. We satisfy the qualifying income requirement and are treated as a partnership for federal and state income tax purposes. Our consolidated earnings are included in the federal and state income tax returns of our partners. However, legislation in certain states allows for taxation of partnerships, and as such, certain state taxes have been included in our accompanying financial statements as income taxes due to the nature of the tax in those particular states as discussed below. In addition, federal and state income taxes are provided on the earnings of the subsidiaries incorporated as taxable entities. We are required to recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax basis of assets and liabilities using expected rates in effect for the year in which the differences are expected to reverse.

We are responsible for the Texas Margin tax computed on the Texas franchise tax returns. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Environmental Costs and Other Contingencies

We recognize liabilities for environmental and other contingencies when there is an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of range is accrued.

We record liabilities for environmental contingencies at their undiscounted amounts on our consolidated balance sheets as accrued expenses and other liabilities when environmental assessments indicate that remediation efforts are probable and costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors. These estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and recognize a current period charge in operations and maintenance expenses when clean-up efforts do not benefit future periods.

We evaluate potential recoveries of amounts from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet.

Price Risk Management Activities

We utilize certain derivative financial instruments to (i) manage our exposure to commodity price risk, specifically, the related change in the fair value of inventory, as well as the variability of cash flows related to forecasted transactions; (ii) ensure the availability of adequate physical supply of commodity; and (iii) manage our exposure to the interest rate risk associated with fixed and variable rate borrowings. We record all derivative instruments on the balance sheet at their fair values as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded through current earnings.

We did not have any derivatives identified as fair value hedges or cash flow hedges for accounting purposes during the years ended December 31, 2017, 2016 or 2015.

Unit-Based Compensation

Long-term incentive awards are granted under the Crestwood Equity incentive plan. Unit-based compensation awards consist of restricted units that are valued at the closing market price of CEQP’s common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. We generally recognize the expense associated with the award over the vesting period on a straight line basis. Effective January 1, 2017, we adopted the provisions of ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of the accounting for share-based payment award transactions, including the classification of awards as either equity or liabilities and the presentation on the statement of cash flows. The adoption of this accounting standard did not have a material impact on our consolidated financial statements.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2017, the following accounting standards had not yet been adopted by us:

Revenue. In May 2014, the FASB issued ASU 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 utilized the modified retrospective method to adopt the provisions of this standard effective January 1, 2018. Upon adoption of the standard we began classifying certain capital expenditure reimbursements from our customers as deferred revenue rather than as reductions of property, plant and equipment in our consolidated financial statements.  We reclassified approximately $69.1 million of these net reimbursements to net deferred revenue on January 1, 2018, which primarily resulted in approximately $20.0 million cumulative effect of accounting change being recorded as an increase to partners' capital on January 1, 2018.  In addition, the standard requires us to begin classifying service revenues on certain of our gathering and processing contracts as reductions of costs of product sold prospectively beginning January 1, 2018.

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which revises the accounting for leases by requiring certain leases to be recognized as assets and liabilities on the balance sheet, and requiring companies to disclose additional information about their leasing arrangements. We expect to adopt the provisions of this standard effective January 1, 2019 and are currently evaluating the impact that this standard will have on our consolidated financial statements.

Cash Flows. In August 2016, the FASB issued ASU 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain cash receipts and cash payments are presented and classified in the statement of cash flows. We adopted the provisions of this standard effective January 1, 2018, and the adoption of this standard did not have a material impact on our consolidated financial statements.

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Divestitures

12 Months Ended

Dec. 31, 2017

Business Combinations [Abstract]

Acquisitions

Divestiture

In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP, for net proceeds of approximately $223.6 million. The sale of US Salt resulted in a decrease of $157.4 million of property, plant and equipment, net, $12.6 million of goodwill, $5.8 million of intangible assets and $14.2 million of other assets and liabilities, net. During the year ended December 31, 2017, we recognized a gain of approximately $33.6 million from the sale, which was included in gain (loss) on long-lived assets in our consolidated statement of operations. As part of the US Salt divestiture, we retained all surface and sub-surface rights necessary to place the Watkins Glen NGL storage development project into service once we receive all required regulatory approvals. US Salt was previously included in our MS&L segment.

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Certain Balance Sheet Information

12 Months Ended

Dec. 31, 2017

Balance Sheet Related Disclosures [Abstract]

Certain Balance Sheet Information

Certain Balance Sheet Information

Property, Plant and Equipment

Property, plant and equipment of the following at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Gathering systems and pipelines and related assets	$	678.0	$	639.4	$	820.9	$	782.3
Facilities and equipment	1,141.4		1,328.3		1,326.5		1,513.4
Buildings, land, rights-of-way, storage rights and easements	319.1		315.4		322.8		319.1
Vehicles	37.3		45.7		35.5		44.0
Construction in process	87.5		85.9		87.5		85.9
Salt deposits	—		120.5		—		120.5
Office furniture and fixtures	21.9		20.2		22.1		20.3
	2,285.2		2,555.4		2,615.3		2,885.5
Less: accumulated depreciation and depletion	464.4		457.8		607.8		587.1
Total property, plant and equipment, net	$	1,820.8	$	2,097.6	$	2,007.5	$	2,298.4

Depreciation. CEQP’s depreciation expense totaled $135.9 million, $154.8 million and $195.1 million for the years ended December 31, 2017, 2016 and 2015. CMLP’s depreciation expense totaled $150.0 million, $168.9 million and $186.7 million for the years ended December 31, 2017, 2016 and 2015. Depletion expense at both CEQP and CMLP totaled $0.7 million for each of the years ended December 31, 2017, 2016 and 2015.

Capitalized Interest. During the years ended December 31, 2017, 2016 and 2015, CEQP and CMLP capitalized interest of $2.9 million, $0.7 million and $2.5 million related to certain expansion projects.

Gain (Loss) on Long-Lived Assets. During the year ended December 31, 2017, we recorded a gain of approximately $33.6 million on the sale of our 100% interest in US Salt. In addition, we recorded a loss of approximately $14.4 million during the year ended December 31, 2017, related to the retirement and/or disposition of certain of our Marcellus and Arrow gathering and processing assets.

Intangible Assets

Intangible assets consisted of the following at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Customer accounts	$	438.9	$	541.9	$	438.9	$	541.9
Covenants not to compete	—		1.0		—		1.0
Gas gathering, compression and processing contracts	325.2		325.2		325.2		325.2
Trademarks	24.7		30.5		9.2		15.0
	788.8		898.6		773.3		883.1
Less: accumulated amortization	191.6		241.2		177.6		230.2
Total intangible assets, net	$	597.2	$	657.4	$	595.7	$	652.9

The following table summarizes total accumulated amortization of our intangible assets at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Customer accounts	$	89.8	$	162.4	$	89.8	$	162.4
Gas gathering, compression and processing contracts	82.0		63.2		82.0		63.2
Trademarks	19.8		15.6		5.8		4.6
Total accumulated amortization	$	191.6	$	241.2	$	177.6	$	230.2

Crestwood Equity’s amortization expense related to its intangible assets for the years ended December 31, 2017, 2016 and 2015, was approximately $53.7 million, $72.5 million and $102.8 million. Crestwood Midstream’s amortization expense related to its intangible assets for the years ended December 31, 2017, 2016 and 2015 was approximately $50.6 million, $69.3 million and $89.6 million.

Estimated amortization of our intangible assets for the next five years is as follows (in millions):

	CEQP		CMLP
Year Ending December 31,
2018	$	43.4	$	42.0
2019	41.7		41.7
2020	41.7		41.7
2021	41.7		41.7
2022	41.7		41.7

Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Accrued expenses	$	56.6	$	46.5	$	55.5	$	45.1
Accrued property taxes	4.8		4.2		4.8		4.2
Accrued natural gas purchases	—		4.9		—		4.9
Income tax payable	0.3		1.6		0.3		0.4
Interest payable	20.3		22.8		20.3		22.8
Accrued additions to property, plant and equipment	22.3		1.7		22.2		1.7
Capital leases	1.0		1.3		1.0		1.3
Deferred revenue	0.6		7.5		0.6		7.5
Total accrued expenses and other liabilities	$	105.9	$	90.5	$	104.7	$	87.9

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

Asset Retirement Obligations

We have legal obligations associated with our facilities and right-of-way contracts we hold. Where we can reasonably estimate the asset retirement obligation, we accrue a liability based on an estimate of the timing and amount of settlement. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations.

The following table presents the changes in the net asset retirement obligations for the years ended December 31, 2017 and 2016 (in millions):

	December 31,
	2017			2016
Net asset retirement obligation at January 1	$	27.8		$	26.4
Liabilities incurred	—			1.0
Liabilities settled	(1.2		)	(1.2		)
Accretion expense	1.4			1.6
Change in estimate	(0.5		)	—
Net asset retirement obligation at December 31	$	27.5		$	27.8

We did not have any material assets that were legally restricted for use in settling asset retirement obligations as of December 31, 2017 and 2016.

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Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

Investments in Unconsolidated Affiliates

Net Investments and Earnings (Loss)

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

	Ownership Percentage			Investment					Earnings (Loss) from Unconsolidated Affiliates
	December 31,			December 31,					Year Ended December 31,
	2017			2017		2016			2017		2016				2015
Stagecoach Gas Services LLC	50.00	%		$	849.8	$	871.0		$	25.3	$	15.9			$	—
Jackalope Gas Gathering Services, L.L.C.	50.00	%	(1)	184.9		197.2			10.5		20.8				(43.4		)	(3)
Crestwood Permian Basin Holdings LLC	50.00	%		102.0		(0.5		)	8.4		(0.5		)		—
Tres Palacios Holdings LLC	50.01	%		37.8		39.0			2.2		(0.3		)		2.5
Powder River Basin Industrial Complex, LLC(2)	50.01	%		8.5		8.7			1.4		(4.4		)	(3)	(19.9		)	(3)
Total				$	1,183.0	$	1,115.4		$	47.8	$	31.5			$	(60.8	)

(1) Excludes non-controlling interest related to our investment in Jackalope. See Note 12 for a further discussion of our non-controlling interest related to our investment in Jackalope.

(2) During the year ended December 31, 2015, we recorded additional equity earnings of approximately $3.2 million related to a gain associated with the adjustment of our member’s capital account by our equity investee.

(3) During the year ended December 31, 2016, we recorded a reduction of our equity earnings from PRBIC of approximately $5.8 million related to impairments recorded by our equity investee. During the year ended December 31, 2015, we recorded impairments of our PRBIC and Jackalope equity investments of approximately $23.4 million and $51.4 million. For a further discussion of these impairments, see Note 2.

Description of Investments

Crestwood Permian Basin Holdings LLC

In October 2016, Crestwood Infrastructure, our wholly-owned subsidiary, and an affiliate of First Reserve formed a joint venture, Crestwood Permian, to fund and own the Nautilus gathering system (described below) and other potential investments in the Delaware Permian. As part of this transaction, we transferred to the Crestwood Permian joint venture 100% of the equity interest of Crestwood Permian Basin LLC (Crestwood Permian Basin), which owns the Nautilus gathering system. We manage and account for our 50% ownership interest in Crestwood Permian, which is a VIE, under the equity method of accounting as we exercise significant influence, but do not control Crestwood Permian and we are not its primary beneficiary due to First Reserve’s rights to exercise control over the entity.

Crestwood Permian Basin has a long-term agreement with SWEPI LP (SWEPI), a subsidiary of Royal Dutch Shell plc, to construct, own and operate a natural gas gathering system (the Nautilus gathering system) in SWEPI’s operated position in the Delaware Permian. SWEPI has dedicated to Crestwood Permian Basin approximately 100,000 acres and gathering rights for SWEPI’s gas production across a large acreage position in Loving, Reeves and Ward Counties, Texas. Crestwood Permian Basin provides gathering, dehydration, compression and liquids handling services to SWEPI on a fixed-fee basis. In conjunction with the Crestwood Permian Basin’s agreement with SWEPI, Crestwood Permian granted Shell Midstream Partners L.P. (Shell Midstream), a subsidiary of Royal Dutch Shell plc, an option to purchase up to 50% equity interest in Crestwood Permian Basin. In October 2017, Shell Midstream exercised its option and purchased a 50% equity interest in Crestwood Permian Basin from Crestwood Permian for approximately $37.9 million in cash. Crestwood Permian distributed to us approximately $18.9 million of the cash proceeds received.

CEQP issued a guarantee in conjunction with the Crestwood Permian Basin gas gathering agreement with SWEPI described above, under which CEQP has agreed to fund 100% of the costs to build the Nautilus gathering system (which is currently estimated to cost $180 million, of which approximately $84.3 million has been spent through December 31, 2017) if Crestwood Permian fails to do so. We do not believe this guarantee is probable of resulting in future losses based on our assessment of the nature of the guarantee, the financial condition of the guaranteed party and the period of time that the guarantee has been outstanding, and as a result, we have not recorded a liability on our balance sheet at December 31, 2017 and 2016.

On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico, our wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New Mexico. This contribution was treated as a transaction between entities under common control (because of our relationship with First Reserve), and accordingly we deconsolidated Crestwood New Mexico and our investment in Crestwood Permian was increased by the historical book value of these assets of approximately $69.4 million. In conjunction with this contribution, First Reserve has agreed to contribute to Crestwood Permian the first $151 million of capital costs required to fund the expansion of the Delaware Basin assets, which includes a new processing plant located in Orla, Texas and associated pipelines (Orla processing plant).

Stagecoach Gas Services LLC

On June 3, 2016, Crestwood Northeast and CEGP formed Stagecoach Gas to own and further develop our NE S&T assets. During 2016, we contributed to Stagecoach Gas the entities owning the NE S&T assets. Additionally, CEGP contributed $975 million to Stagecoach Gas in exchange for a 50% equity interest in Stagecoach Gas, and Stagecoach Gas distributed to us the cash proceeds received (net of approximately $3 million of cash transferred to the joint venture) from CEGP. We deconsolidated the NE S&T assets as a result of this transaction discussed above and began accounting for our 50% equity interest in Stagecoach Gas under the equity method of accounting. We recognized a loss of approximately $32.4 million on the deconsolidation of the NE S&T assets.

Pursuant to the Stagecoach Gas limited liability company agreement, we may be required to make payments of up to $57 million to CEGP after December 31, 2020 if certain criteria are not met by Stagecoach Gas by December 31, 2020, including achieving certain performance targets on growth capital projects. These growth capital projects depend on the construction of other third-party expansion projects, and during 2017, those third-party projects experienced regulatory and other delays that caused Stagecoach Gas to delay its growth capital projects. Although Stagecoach Gas anticipates that these growth capital projects will be constructed in the future, it does not expect that these projects will produce meaningful operating results prior to December 31, 2020. As a result, at December 31, 2017, we recorded a liability of $57 million for this obligation, which is reflected in other long-term liabilities on our consolidated balance sheet and in loss on contingent consideration in our consolidated income statement for the year ended December 31, 2017.

Jackalope Gas Gathering Services, L.L.C.

Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, owns a 50% ownership interest in Jackalope which we account for under the equity method of accounting. Williams Partners LP operates and owns the remaining 50% interest in Jackalope. Crestwood Niobrara manages the commercial operations of the Jackalope system.

Tres Palacios Holdings LLC

Crestwood Midstream owns a 50.01% ownership interest in Tres Palacios Holdings LLC (Tres Holdings) and is the operator of Tres Palacios Gas Storage LLC (Tres Palacios) and its assets. Brookfield Infrastructure Group owns the remaining 49.99% ownership interest in Tres Holdings. We account for our investment in Tres Holdings under the equity method of accounting.

Powder River Basin Industrial Complex, LLC

Crestwood Crude Logistics LLC (Crude Logistics), our consolidated subsidiary, owns a 50% ownership interest in PRBIC which we account for under the equity method of accounting. Twin Eagle Powder River Basin, LLC owns the remaining 50% ownership interest in PRBIC.

Summarized Financial Information of Unconsolidated Affiliates

Below is summarized financial information for our significant unconsolidated affiliates (in millions; amounts represent 100% of unconsolidated affiliate information):

Financial Position Data

	December 31,
	2017										2016
	Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity		Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity
Stagecoach(1)	$	55.1	$	1,765.4	$	7.0	$	1.4	$	1,812.1	$	57.0	$	1,807.6	$	6.0	$	4.1	$	1,854.5
Other(2)(3)	81.3		801.1		53.4		93.6		735.4		50.4		708.5		23.2		74.4		661.3
Total	$	136.4	$	2,566.5	$	60.4	$	95.0	$	2,547.5	$	107.4	$	2,516.1	$	29.2	$	78.5	$	2,515.8

(1) As of December 31, 2017, our equity in the underlying net assets of Stagecoach Gas exceeded our investment balance by approximately $51.4 million. This excess amount is entirely attributable to goodwill and, as such, is not subject to amortization. Our Stagecoach Gas investment is included in our storage and transportation segment.

(2) Includes our Jackalope, Tres Holdings, PRBIC and Crestwood Permian investments. As of December 31, 2017, our equity in the underlying net assets of Jackalope, Tres Holdings, PRBIC and Crestwood Permian exceeded our investment balance by approximately $0.7 million, $26.5 million, $6.4 million and $11.6 million, respectively. Our Tres Holdings and PRBIC investments are included in our storage and transportation segment and our Jackalope and Crestwood Permian investments are included in our gathering and processing segment.

(3) On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico. This contribution was treated as a transaction between entities under common control (because of our relationship with First Reserve) and the accounting standards related to such transactions requires Crestwood Permian to record the assets and liabilities of Crestwood New Mexico at our historical book value. The difference between our equity in Crestwood New Mexico’s net assets and our investment balance is not subject to amortization.

Operating Results Data

	Year Ended December 31,
	2017						2016						2015
	Operating Revenues		Operating Expenses		Net  Income		Operating Revenues		Operating Expenses		Net  Income		Operating Revenues		Operating Expenses		Net  Income
Stagecoach	$	168.6	$	77.7	$	91.1	$	99.3	$	44.1	$	55.3	$	—	$	—	$	—
Other(1)	181.8		143.6		38.9		127.6		113.9		13.5		104.7		79.5		24.9
Total	$	350.4	$	221.3	$	130.0	$	226.9	$	158.0	$	68.8	$	104.7	$	79.5	$	24.9

(1) Includes our Jackalope, Tres Holdings, PRBIC and Crestwood Permian equity investments. We amortize the excess basis in certain of our equity investments as an increase in our earnings from unconsolidated affiliates. We recorded amortization of the excess basis in our Jackalope equity investment of less than $0.1 million for both the years ended December 31, 2017 and 2016, and $3.0 million for the year ended December 31, 2015, which we amortize over the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake). We recorded amortization of the excess basis in our Tres Holdings equity investment of approximately $1.3 million for each of the years ended December 31, 2017, 2016 and 2015, which we amortize over the life of Tres Palacios’ sublease agreement. We recorded amortization of the excess basis in our PRBIC equity investment of approximately $0.6 million and $1.6 million for the years ended December 31, 2017 and 2016, which we amortize over the life of PRBIC’s property, plant and equipment and its agreement with Chesapeake.

Distributions and Contributions

	Distributions						Contributions
	Year Ended December 31,						Year Ended December 31,
	2017		2016		2015		2017		2016		2015
Stagecoach Gas	$	47.3	$	16.0	$	—	$	0.8	$	—	$	—
Jackalope(1)	26.3		27.4		12.5		3.5		1.4		25.4
Tres Holdings(2)	9.0		8.5		7.4		5.6		11.0		5.7
PRBIC(1)	1.6		2.0		1.9		—		—		10.7
Crestwood Permian(3)	23.4		—		—		117.5		—		—
Total	$	107.6	$	53.9	$	21.8	$	127.4	$	12.4	$	41.8

(1) Jackalope and PRBIC are required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. We

received a cash distribution of $7.4 million from Jackalope in January 2018, and we received a cash distribution of $0.3 million from PRBIC in February

2018.

(2) 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.

(3) On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico at our historical book value of

approximately $69.4 million. This contribution was treated as a non-cash transaction between entities under common control.

Stagecoach Gas. Stagecoach Gas is required, within 30 days following the end of each quarter, to distribute 65% and 35% of its available cash (as defined in its limited liability company agreement) to CEGP and us, respectively. Because our ownership and distribution percentages differ, we determine the equity earnings from Stagecoach Gas using the Hypothetical Liquidation at Book Value (HLBV) method. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that we would receive if Stagecoach Gas were to liquidate all of its assets, as valued in accordance with GAAP, and distribute that cash to the members. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is our share of the earnings or losses from the equity investment for the period, which approximates how earnings are allocated under the terms of the limited liability company agreement. In January 2018, we received a cash distribution from Stagecoach Gas of approximately $11.3 million.

Crestwood Permian. Crestwood Permian is required, within 30 days following the end of each quarter to distribute 100% of its available cash (as defined in its limited liability company agreement) to its members based on their respective ownership percentages. Pursuant to Crestwood Permian's limited liability company agreement, we will receive 100% of Crestwood New Mexico's available cash (as defined in the limited liability company agreement) until the earlier of the Orla processing plant in-service date or June 30, 2018, at which time the distributions will be based on the members respective ownership percentages. Because our ownership and distribution percentages will differ during this period, equity earnings from Crestwood Permian is determined using the HLBV method. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that we would receive if Crestwood Permian were to liquidate all of its assets, as valued in accordance with GAAP, and distribute that cash to the members. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is our share of the earnings or losses from the equity investment for the period, which approximates how earnings are allocated under the terms of the limited liability company agreement. In January 2018, we received a cash distribution from Crestwood Permian of approximately $4.3 million.

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Risk Management

12 Months Ended

Dec. 31, 2017

Risk Management - Notional Amounts and Terms of Companys Derivative Financial Instruments [Abstract]

Risk Management

Risk Management

We are exposed to certain market risks related to our ongoing business operations. These risks include exposure to changing commodity prices. We utilize derivative instruments to manage our exposure to fluctuations in commodity prices, which is discussed below. Additional information related to our derivatives is discussed in Note 2 and Note 8.

Commodity Derivative Instruments and Price Risk Management

Risk Management Activities

We sell NGLs and crude oil 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 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 years ended December 31, 2017, 2016 and 2015, the impact to our consolidated statements of operations related to our commodity-based derivatives reflected in costs of product/services sold was a loss of $31.2 million, a loss of $7.8 million and a gain of $18.9 million, respectively. 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:

	December 31, 2017		December 31, 2016
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (MMBbls)	15.3	17.5	13.1	15.1
Natural gas (MMcf)	780	660	—	—

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 34 months or less; however, 88% of the contracted volumes will be delivered or settled 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 our price risk management activities are 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 credit-risk-related contingent features that were in a liability position at December 31, 2017 and 2016, was $28.9 million and $13.9 million. At December 31, 2017 and 2016, we posted less than $0.1 million of collateral for our commodity derivative instruments with credit-risk-related contingent features. In addition, at December 31, 2017 and 2016, we had a New York Mercantile Exchange (NYMEX) related net derivative asset position of $27.2 million and $14.3 million, for which we posted $5.6 million and $4.2 million of cash collateral in the normal course of business. At December 31, 2017 and 2016, we also received collateral of $3.7 million and $4.3 million in the normal course of business. All collateral amounts have been netted against the asset or liability with the respective counterparty and are reflected in our consolidated balance sheets as assets and liabilities from price risk management activities.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2017

Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]

Fair Value Measurements

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, Accounts Receivable and Accounts Payable

As of December 31, 2017 and 2016, the carrying amounts of cash, accounts receivable and accounts payable approximate fair value based on the short-term nature of these instruments.

Credit Facility

The fair value of the amounts outstanding under our CMLP credit facility approximates the carrying amounts as of December 31, 2017 and 2016, due primarily to the variable nature of the interest rate of the instrument, 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 (reduced for deferred financing costs associated with the respective notes) and fair value of our senior notes (in millions):

	December 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2020 Senior Notes	$	—	$	—	$	340.6	$	350.2
2022 Senior Notes	$	—	$	—	$	429.3	$	447.3
2023 Senior Notes	$	692.1	$	728.8	$	690.6	$	722.6
2025 Senior Notes	$	492.3	$	517.9	$	—	$	—

Financial Assets and Liabilities

As of December 31, 2017 and 2016, 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, and NGLs. Our derivative instruments consist of forwards, swaps, futures, physical exchanges and options.

Our derivative instruments that are traded on the NYMEX 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 financial instruments that were accounted for at fair value on a recurring basis at December 31, 2017 and 2016 (in millions):

	December 31, 2017
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Recorded in Balance Sheet
Assets
Assets from price risk management	$	1.1	$	102.2	$	—	$	103.3	$	(74.6	)	$	(21.5	)	$	7.2
Suburban Propane Partners, L.P. units(2)	3.5		—		—		3.5		—			—			3.5
Total assets at fair value	$	4.6	$	102.2	$	—	$	106.8	$	(74.6	)	$	(21.5	)	$	10.7
Liabilities
Liabilities from price risk management	$	1.4	$	118.2	$	—	$	119.6	$	(74.6	)	$	3.9		$	48.9
Total liabilities at fair value	$	1.4	$	118.2	$	—	$	119.6	$	(74.6	)	$	3.9		$	48.9
	December 31, 2016
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Recorded in Balance Sheet
Assets
Assets from price risk management	$	0.6	$	84.4	$	—	$	85.0	$	(67.8	)	$	(10.9	)	$	6.3
Suburban Propane Partners, L.P. units(2)	4.3		—		—		4.3		—			—			4.3
Total assets at fair value	$	4.9	$	84.4	$	—	$	89.3	$	(67.8	)	$	(10.9	)	$	10.6
Liabilities
Liabilities from price risk management	$	2.7	$	90.2	$	—	$	92.9	$	(67.8	)	$	3.5		$	28.6
Total liabilities at fair value	$	2.7	$	90.2	$	—	$	92.9	$	(67.8	)	$	3.5		$	28.6

(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) Amount is reflected in other assets on CEQP’s consolidated balance sheets.

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Long-Term Debt

12 Months Ended

Dec. 31, 2017

Text Block [Abstract]

Long-Term Debt

Long-Term Debt

Long-term debt consisted of the following at December 31, 2017 and 2016, (in millions):

	December 31,
	2017		2016
Credit Facility	$	318.2	$	77.0
2020 Senior Notes	—		338.8
Fair value adjustment of 2020 Senior Notes	—		1.8
2022 Senior Notes	—		436.4
2023 Senior Notes	700.0		700.0
2025 Senior Notes	500.0		—
Other	2.4		3.7
Less: deferred financing costs, net	28.4		34.0
Total debt	1,492.2		1,523.7
Less: current portion	0.9		1.0
Total long-term debt, less current portion	$	1,491.3	$	1,522.7

Credit Facility

Crestwood Midstream’s amended and restated senior secured credit agreement (the CMLP Credit Agreement) provides for a five-year $1.5 billion revolving credit facility (the CMLP Credit Facility), which expires in September 2020 and is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The CMLP Credit Facility allows Crestwood Midstream to increase its available borrowings under the facility by $350.0 million, subject to lender approval and the satisfaction of certain other conditions, as described in the CMLP Credit Agreement. The CMLP Credit Facility also includes a sub-limit of up to $25.0 million for same-day swing line advances and a sub-limit up to $350.0 million for letters of credit. Subject to limited exception, the CMLP Credit Facility is guaranteed and secured by substantially all of the equity interests and assets of Crestwood Midstream’s subsidiaries, except for Crestwood Niobrara, Crestwood Infrastructure, PRBIC, Crestwood Northeast and Tres Holdings and their respective subsidiaries. The Company also guarantees Crestwood Midstream’s payment obligations under its $1.5 billion credit agreement.

Prior to amending and restating its credit agreement in September 2015, Crestwood Midstream had a five-year $1.0 billion senior secured revolving credit facility, which would have expired October 2018. In conjunction with the closing of the Simplification Merger, Crestwood Midstream borrowed approximately $720.0 million under the CMLP Credit Facility on September 30, 2015 to (i) repay all borrowings outstanding under the $1.0 billion credit facility; (ii) fund a distribution to the Company of approximately $378.3 million for purposes of repaying (or, if applicable, satisfying and discharging) substantially all of the Company’s outstanding indebtedness as discussed above; and (iii) pay merger-related fees and expenses. We recognized a loss on extinguishment of debt of approximately $1.8 million for the year ended December 31, 2015 in conjunction with amending and restating the CMLP Credit Agreement.

Borrowings under the CMLP Credit Facility (other than the swing line loans) bear interest at either:

• the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) Wells Fargo Bank’s prime rate; or (iii) the Eurodollar Rate adjusted for certain reserve requirements plus 1%; plus a margin varying from 0.75% to 1.75% depending on Crestwood Midstream’s most recent consolidated total leverage ratio; or

• the Eurodollar Rate, adjusted for certain reserve requirements plus a margin varying from 1.75% to 2.75% depending on Crestwood Midstream’s most recent consolidated total leverage ratio.

Swing line loans bear interest at the Alternate Base Rate as described above. The unused portion of the CMLP Credit Facility is subject to a commitment fee ranging from 0.30% to 0.50% according to its most recent consolidated total leverage ratio. Interest on the Alternate Base Rate loans is payable quarterly, or if the adjusted Eurodollar Rate applies, interest is payable at certain intervals selected by Crestwood Midstream.

At December 31, 2017, Crestwood Midstream had $499.3 million of available capacity under its credit facility considering the most restrictive covenants in its credit agreement. At December 31, 2017 and 2016, Crestwood Midstream’s outstanding standby letters of credit were $52.2 million and $64.0 million. Interest rates under the CMLP Credit Facility were between 3.94% and 6.00% at December 31, 2017 and 3.21% and 5.25% at December 31, 2016. The weighted-average interest rate on outstanding borrowings as of December 31, 2017 and 2016 was 4.11% and 3.23%.

The CMLP Credit Facility contains various covenants and restrictive provisions that limit our ability to, among other things, (i) incur additional debt; (ii) make distributions on or redeem or repurchase units; (iii) make certain investments and acquisitions; (iv) incur or permit certain liens to exist; (v) merge, consolidate or amalgamate with another company; (vi) transfer or dispose of assets; and (vii) incur a change in control at either Crestwood Equity or Crestwood Midstream, including an acquisition of Crestwood Holdings’ ownership of Crestwood Equity’s general partner by any third party, including Crestwood Holdings’ debtors under an event of default of their debt since Crestwood Equity’s non-economic general partner interest is pledged as collateral under that debt.

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 5.50 to 1.0, a consolidated EBITDA to consolidated interest expense ratio (as defined in its credit agreement) of not less than 2.50 to 1.0, and a senior secured leverage ratio (as defined in its credit agreement) of not more than 3.75 to 1.0. At December 31, 2017, the net debt to consolidated EBITDA was approximately 4.14 to 1.0, the consolidated EBITDA to consolidated interest expense was approximately 4.14 to 1.0, and the senior secured leverage ratio was 0.86 to 1.0.

If Crestwood Midstream fails to perform its obligations under these and other covenants, the lenders’ credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the CMLP Credit Facility could be declared immediately due and payable. The CMLP Credit Facility also has cross default provisions that apply to any of its other material indebtedness.

Senior Notes

2020 Senior Notes. The 6.0% Senior Notes due 2020 (the 2020 Senior Notes) were scheduled to mature on December 15, 2020, and interest was payable semi-annually in arrears on June 15 and December 15 of each year. The fair value adjustment was being amortized over the remaining life of the 2020 Senior Notes.

2022 Senior Notes. The 6.125% Senior Notes due 2022 (the 2022 Senior Notes) were scheduled to mature on March 1, 2022, and interest was payable semi-annually on March 1 and September 1 of each year.

2023 Senior Notes. The 6.25% Senior Notes due 2023 (the 2023 Senior Notes) mature on April 1, 2023, and interest is payable semi-annually in arrears on April 1 and October 1 of each year.

In March 2016, Crestwood Midstream filed a registration statement with the SEC under which it offered to exchange the 2023 Senior Notes for any and all outstanding 2023 Senior Notes. Crestwood Midstream completed the exchange offer in July 2016. The terms of the exchange notes are substantially identical to the terms of the 2023 Senior Notes, except that the exchange notes are freely tradable.

2025 Senior Notes. In March 2017, Crestwood Midstream issued $500 million of 5.75% unsecured senior notes due 2025 (the 2025 Senior Notes) in a private offering. The 2025 Senior Notes will mature on April 1, 2025, and interest is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2017. The net proceeds from this offering of approximately $492 million were used to repay amounts outstanding under the 2020 Senior Notes and the 2022 Senior Notes as discussed below.

In May 2017, Crestwood Midstream filed a registration statement with the SEC under which is offered to exchange new senior notes for any and all outstanding 2025 Senior Notes. Crestwood Midstream completed the exchange offer in July 2017. The terms of the exchange notes are substantially identical to the terms of the 2025 Senior Notes, except that the exchange noted are freely tradable.

In general, each series of Crestwood Midstream’s senior notes are fully and unconditionally guaranteed, joint and severally, on a senior unsecured basis by Crestwood Midstream’s domestic restricted subsidiaries (other than Finance Corp., which has no assets). The indentures contain customary release provisions, such as (i) disposition of all or substantially all the assets of, or the capital stock of, a guarantor subsidiary to a third person if the disposition complies with the indentures; (ii) designation of a guarantor subsidiary as an unrestricted subsidiary in accordance with its indentures; (iii) legal or covenant defeasance of a series of senior notes, or satisfaction and discharge of the related indenture; and (iv) guarantor subsidiary ceases to guarantee any other indebtedness of Crestwood Midstream or any other guarantor subsidiary, provided it no longer guarantees indebtedness under the CMLP Credit Facility.

The indentures restricts the ability of Crestwood Midstream and its restricted subsidiaries to, among other things, sell assets; redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; create or incur certain liens; enter into agreements that restrict distributions or other payments to Crestwood Midstream from its restricted subsidiaries; consolidate, merge or transfer all or substantially all of their assets; engage in affiliate transactions; create unrestricted subsidiaries; and incur a change in control at either Crestwood Equity or Crestwood Midstream, including an acquisition of Crestwood Holdings’ ownership of Crestwood Equity’s general partner by any third party including Crestwood Holdings’ debtors under an event of default of their debt since Crestwood Equity’s non-economic general partner interest is pledged as collateral under that debt. These restrictions are subject to a number of exceptions and qualifications, and many of these restrictions will terminate when the senior notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Rating Services and no default or event of default (each as defined in the respective indentures) under the indentures has occurred and is continuing.

At December 31, 2017, Crestwood Midstream was in compliance with the debt covenants and restrictions in each of its credit agreements discussed above.

Crestwood Midstream’s Credit Facility and its respective senior notes are secured by its assets and liabilities of the guarantor subsidiaries. Accordingly, such assets are only available to the creditors of Crestwood Midstream. Crestwood Equity had restricted net assets of approximately $2,195.4 million as of December 31, 2017.

Repayments.During the year ended December 31, 2017, Crestwood Midstream paid approximately $349.9 million and $457.8 million to purchase, redeem and/or cancel all of the principal amount outstanding under the 2020 Senior Notes and 2022 Senior Notes, respectively. Crestwood Midstream funded the repayments with a combination of net proceeds from the issuance of the 2025 Senior Notes described above and borrowings under the credit facility. In conjunction with these note repayments, Crestwood Midstream (i) recognized a loss on extinguishment of debt of approximately $37.7 million during the year ended December 31, 2017 (including the write off of approximately $6.8 million of deferred financing costs associated with the 2022 Senior Notes); and (ii) paid $5.1 million and $1.0 million of accrued interest on the 2020 Senior Notes and 2022 Senior Notes, respectively, on the date they were tendered.

In June 2016, Crestwood Midstream paid approximately $312.9 million to purchase and cancel approximately $161.2 million and $163.6 million of the principal amount outstanding under the 2020 Senior Notes and 2022 Senior Notes, respectively, utilizing a portion of the proceeds received from Stagecoach Gas, as further discussed in Notes 2 and 6. During the year ended December 31, 2016, Crestwood Midstream recognized a gain on extinguishment of debt of approximately $10.0 million in conjunction with the early tender of these notes. Crestwood Midstream also paid $4.5 million and $2.6 million of accrued interest on the 2020 Senior Notes and 2022 Senior Notes, respectively, on the date they were tendered.

In April 2015, we retired our $350 million7.75% Senior Notes due 2019 for approximately $364.1 million, including accrued interest of $0.5 million and a call premium of $13.6 million. In conjunction with the redemption of these notes, we recorded a loss on extinguishment of debt of approximately $17.1 million during the year ended December 31, 2015.

Other Obligations

Our non-interest bearing obligations due under noncompetition agreements consist of agreements between Crestwood Midstream and sellers of certain companies acquired in 2014 with payments due through 2022 and imputed interest ranging from 5.02% to 6.75%. Non-interest bearing obligations consisted of $2.7 million and $4.2 million in total payments due under agreements, less unamortized discount based on imputed interest of $0.3 million and $0.5 million at December 31, 2017 and 2016, respectively.

Maturities

The aggregate maturities of principal amounts on our outstanding long-term debt and other notes payable as of December 31, 2017 for the next five years and in total thereafter are as follows (in millions):

2018	$	0.9
2019	0.9
2020	318.4
2021	0.2
2022	0.2
Thereafter	1,200.0
Total debt	$	1,520.6

Residual Value Guarantee

In 2012, Crestwood Equity entered into a support agreement with Suburban Propane Partners, L.P. (SPH) pursuant to which Crestwood Equity is obligated to provide contingent, residual support of approximately $497 million of aggregate principal amount of the 7.5% senior unsecured notes due 2018 of SPH and Suburban Energy Finance Corp. (collectively, the SPH Issuers) or any permitted refinancing thereof. Under the support agreement, in the event the SPH Issuers fail to pay any principal amount of the supported debt when due, Crestwood Equity will pay the holders of the supported debt, or the SPH Issuers for the benefit of the holders of the supported debt, an amount up to the principal amount of the supported debt that the SPH Issuers have failed to pay. Crestwood Equity has no obligation to make a payment under the support agreement with respect to any accrued and unpaid interest or any redemption premium or other costs, fees, expenses, penalties, charges or other amounts of any kind that shall be due to the noteholders by the SPH Issuers, whether on or related to the supported debt or otherwise. The support agreement terminates on the earlier of the date the supported debt is extinguished or on the maturity date of supported debt or any permitted refinancing thereof. We believe the probability of any future payment on this residual value guarantee is remote.

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Earnings Per Limited Partner Unit

12 Months Ended

Dec. 31, 2017

Earnings Per Share [Abstract]

Earnings Per Limited Partner Unit

Earnings Per Limited Partner Unit

Our net income (loss) attributable to Crestwood Equity is allocated to the subordinated and limited partner unitholders based on their ownership percentage after giving effect to net income attributable to the preferred units. We calculate basic net income per limited partner unit using the two-class method. Diluted net income per limited partner unit is computed using the treasury stock method, which considers the impact to net income attributable to Crestwood Equity and limited partner units from the potential issuance of limited partner units.

We exclude potentially dilutive securities from the determination of diluted earnings per unit (as well as their related income statement impacts) when their impact on net income attributable to Crestwood Equity per limited partner unit is anti-dilutive. During the years ended December 31, 2017, 2016 and 2015, we excluded a weighted-average of 7,007,917, 6,433,127 and 1,547,060 common units (representing preferred units), a weighted-average of 438,789 common units in all periods (representing subordinated units), and a weighted-average of 7,146,663, 7,548,624 and 2,760,794 common units (representing Crestwood Niobrara’s preferred units). See Note 12 for additional information regarding the potential conversion of our preferred units and Crestwood Niobrara’s preferred units to common units.

CEQP Reverse Split. On October 22, 2015, the board of directors of CEQP’s general partner approved a 1-for-10 reverse split on our common units, effective after the market closed on November 23, 2015. The units began trading on a split-adjusted basis on November 24, 2015. Pursuant to the reverse split, common unit holders received one common unit for every 10 common units owned with substantially the same terms and conditions of the common units prior to the reverse split.

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Income Taxes

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The (provision) benefit for income taxes for the years ended December 31, 2017, 2016, and 2015 consisted of the following (in millions):

	CEQP									CMLP
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017 (1)		2016			2015
Current:
Federal	$	(1.1	)	$	(3.2	)	$	(1.6	)	$	—	$	—		$	—
State	(0.2		)	(0.2		)	(0.6		)	—		0.2			(0.3		)
Total current	(1.3		)	(3.4		)	(2.2		)	—		0.2			(0.3		)
Deferred:
Federal	2.1			3.0			2.9			—		—			—
State	—			0.1			0.7			—		(0.2		)	0.3
Total deferred	2.1			3.1			3.6			—		(0.2		)	0.3
(Provision) benefit for income taxes	$	0.8		$	(0.3	)	$	1.4		$	—	$	—		$	—

(1) For the year ended December 31, 2017, our benefit for income taxes was not material to CMLP’s consolidated statement of operations.

The effective rate differs from the statutory rate for the years ended December 31, 2017, 2016 and 2015, primarily due to the partnerships not being treated as a corporation for federal income tax purposes as discussed in Note 2.

Deferred income taxes related to CEQP’s wholly owned subsidiaries, IPCH Acquisition Corp., and Crestwood Gas Services GP LLC and our Texas Margin tax reflect the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes. For the year ended December 31, 2017, we decreased our net deferred tax liability by $1.3 million to reflect the reduction of corporate tax rates under the Tax Cuts and Jobs Act.

Components of our deferred income taxes at December 31, 2017 and 2016 are as follows (in millions).

	CEQP						CMLP
	December 31,						December 31,
	2017			2016			2017			2016
Deferred tax asset:
Basis difference in stock of company	$	0.2		$	0.2		$	—		$	—
Total deferred tax asset	0.2			0.2			—			—
Deferred tax liability:
Basis difference in stock of acquired company	(3.5		)	(5.5		)	(0.7		)	(0.7		)
Total deferred tax liability	(3.5		)	(5.5		)	(0.7		)	(0.7		)
Net deferred tax liability	$	(3.3	)	$	(5.3	)	$	(0.7	)	$	(0.7	)

Uncertain Tax Positions. We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Such tax positions, if any, would be recorded as a tax benefit or expense in the current year. We believe that there were no uncertain tax positions that would impact our results of operations for the years ended December 31, 2017, 2016 and 2015 and that no provision for income tax was required for these consolidated financial statements. However, our conclusions regarding the evaluation of uncertain tax positions are subject to review and may change based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof.

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Partners' Capital

12 Months Ended

Dec. 31, 2017

Partners' Capital [Abstract]

Partners' Capital

Partners’ Capital

Simplification Merger. As discussed in Note 1, on September 30, 2015, we completed the Simplification Merger. As part of the merger consideration, Crestwood Midstream’s common and preferred unitholders (other than Crestwood Equity and its subsidiaries) received 2.75 common or preferred units of CEQP for each common or preferred unit of CMLP held upon completion of the merger.

Prior to the Simplification Merger, CEQP indirectly owned a non-economic general partnership interest in Crestwood Midstream and 100% of its IDRs. Crestwood Midstream was also a publicly-traded limited partnership with common units listed on the NYSE. However, as a result of our completion of the Simplification Merger on September 30, 2015, Crestwood Midstream’s common units ceased to be listed on the NYSE, its IDRs were eliminated and Crestwood Midstream became a wholly-owned subsidiary of CEQP.

Preferred Units

Pursuant to Crestwood Midstream’s agreements with a group of investors, including Magnetar Financial, affiliates of GSO Capital Partners LP and GE Energy Financial Services (the Class A Purchasers), Crestwood Midstream agreed to sell to the Class A Purchasers and the Class A Purchasers agreed to purchase from Crestwood Midstream up to $500 million of Class A Preferred Units (CMLP Preferred Units) at a fixed price of $25.10 per unit on or before September 30, 2015. In August 2015, the Class A Purchasers acquired from Crestwood Midstream the remaining $60.0 million of CMLP Preferred Units for net proceeds of approximately $58.8 million after deducting transaction fees and offering expenses.

As discussed above, in conjunction with the closing of the Simplification Merger, 21,580,244 of CMLP Preferred Units were exchanged for 59,345,672 new preferred units of CEQP (the Preferred Units) with substantially similar terms and conditions to those of the CMLP Preferred Units and as a result, Crestwood Equity classified the new preferred units as a component of partners’ capital as of December 31, 2015. Because the fair value of the preferred units was materially equivalent immediately before and after the exchange, Crestwood Equity recorded CEQP’s preferred units at Crestwood Midstream’s historical book value.

Subject to certain conditions, the holders of the Preferred Units will have the right to convert Preferred Units into (i) common units on a 1-for-10 basis, or (ii) a number of common units determined pursuant to a conversion ratio set forth in our partnership agreement upon the occurrence of certain events, such as a change in control. The Preferred Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each Preferred Units entitled to one vote for each common unit into which such Preferred Unit is convertible, except that the Preferred Units are entitled to vote as a separate class on any matter on which all unit holders are entitled to vote that adversely affects the rights, powers, privileges or preferences of the Preferred Units in relation to CEQP’s other securities outstanding.

Common Units

On August 4, 2017, we entered into an equity distribution agreement with certain financial institutions (each, a Manager), under which we may offer and sell from time to time through one or more of the Managers, common units having an aggregate offering price of up to $250 million. Common units sold pursuant to this at-the-market (ATM) equity distribution program are issued under a registration statement that became effective on April 12, 2017. We will pay the Managers an aggregate fee of up to 2.0% (which totaled $0.3 million during the year ended December 31, 2017) of the gross sales price per common unit sold under our ATM equity distribution program. The table below shows the units issued and the net proceeds from the issuances:

Issuance Dates	Common Units	Net Proceeds(1) (in millions)
Third Quarter 2017	437,518	$	10.6
Fourth Quarter 2017	195,753	4.6
Total 2017	633,271	$	15.2

(1) The net proceeds from sales under the ATM program are used for general partnership purposes, which may include debt repayments and capital expenditures.

Distributions

Crestwood Equity

Description. Crestwood Equity makes quarterly distributions to its partners within approximately 45 days after the end of each quarter in an aggregate amount equal to its available cash for such quarter. Available cash generally means, with respect to each quarter, all cash on hand at the end of the quarter less the amount of cash that the general partner determines in its reasonable discretion is necessary or appropriate to:

• provide for the proper conduct of its business;

• comply with applicable law, any of its debt instruments, or other agreements; or

• provide funds for distributions to unitholders for any one or more of the next four quarters;

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. The amount of cash CEQP has available for distribution depends primarily upon its cash flow (which consists of the cash distributions it receives in connection with its ownership of Crestwood Midstream).

Limited Partners. A summary of CEQP’s limited partner quarterly cash distributions for the years ended December 31, 2017, 2016 and 2015 is presented below:

Record Date	Payment Date	Per Unit Rate		Cash Distributions  (in millions)
2017
February 7, 2017	February 14, 2017	$	0.60	$	41.8
May 8, 2017	May 15, 2017	$	0.60	41.8
August 7, 2017	August 14, 2017	$	0.60	41.8
November 7, 2017	November 14, 2017	$	0.60	42.2
				$	167.6
2016
February 5, 2016	February 12, 2016	$	1.375	$	95.6
May 6, 2016	May 13, 2016	$	0.60	41.4
August 5, 2016	August 12, 2016	$	0.60	41.4
November 7, 2016	November 14, 2016	$	0.60	41.4
				$	219.8
2015
February 6, 2015	February 13, 2015	$	1.375	$	25.8
May 8, 2015	May 15, 2015	$	1.375	25.7
August 7, 2015	August 14, 2015	$	1.375	25.7
November 6, 2015	November 13, 2015	$	1.375	94.3
				$	171.5

On February 14, 2018, we paid a distribution of $0.60 per limited partner unit to unitholders of record on February 7, 2018 with respect to the fourth quarter of 2017.

Preferred Unit Holders. The holders of our Preferred Units are entitled to receive fixed quarterly distributions of $0.2111 per unit. Through the quarters ending September 30, 2017 (the Initial Distribution Period), distributions on the Preferred Units could be made in additional Preferred Units, cash, or a combination thereof, at our election. Through and for the quarter ended June 30, 2017, we paid distributions on our Preferred Units through the issuance of additional Preferred Units. The number of units distributed was calculated as the fixed quarterly distribution of $0.2111 per unit divided by the cash purchase price of $9.13 per unit. We accrued the fair value of such distribution at the end of the quarterly period and adjusted the fair value of the distribution on the date the additional Preferred Units were distributed. Distributions on the Preferred Units following the Initial Distribution Period will be paid in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units; and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to our Preferred Unit holders. If we fail to pay the full amount payable to our Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.2567 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if we fail to pay in full any Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

During the year ended December 31, 2017, 2016 and 2015, we issued 4,724,030, 5,815,170 and 1,372,573 Preferred Units to our preferred unit holders in lieu of paying quarterly cash distributions of $43.1 million, $53.0 million and $12.5 million. In November 2017, we made a cash distribution to our preferred unit holders of approximately $15.0 million for the quarter ended September 30, 2017. On February 14, 2018, we made a cash distribution of approximately $15.0 million to our preferred unit holders for the quarter ended December 31, 2017.

On June 9, 2016, Crestwood Equity filed a shelf registration statement with the SEC under which holders of the Preferred Units may sell the common units into which the Preferred Units are convertible. The registration statement became effective on June 15, 2016. Crestwood Equity registered 7,290,552 common units under the registration statement.

Crestwood Midstream

Description. Prior to the completion of the Simplification Merger, Crestwood Midstream’s partnership agreement required the partnership 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 applicable record date. The general partner was not entitled to distributions on its non-economic general partner interest.

In conjunction with the Simplification Merger, Crestwood Midstream amended and restated its partnership agreement. In accordance with the partnership agreement, Crestwood Midstream’s general partner may, from time to time, cause Crestwood Midstream to make cash distributions at the sole discretion of the general partner.

General Partner. During the year ended December 31, 2015, Crestwood Midstream paid cash distributions to its general partner (representing IDRs and distributions related to common units held by the general partner) of approximately $31.4 million.

On September 30, 2015, Crestwood Midstream made a distribution of approximately $378.3 million to CEQP for purposes of repaying substantially all of its outstanding indebtedness. The distribution was funded with borrowings under the CMLP Credit Facility. In addition, during the years ended December 31, 2017, 2016 and 2015, Crestwood Midstream made distributions of $174.0 million, $227.6 million and $175.6 million, which represented net amounts due to Crestwood Midstream related to cash advances to CEQP for its general corporate activities.

Limited Partners. The following table presents quarterly cash distributions paid to Crestwood Midstream’s limited partners (excluding distributions paid to its general partner on its common units held) during the year ended December 31, 2015.

Record Date	Payment Date	Per Unit Rate		Cash Distributions (in millions)
2015
February 6, 2015	February 13, 2015	$	0.41	$	74.3
May 8, 2015	May 15, 2015	$	0.41	74.3
August 7, 2015	August 14, 2015	$	0.41	74.3
				$	222.9

Class A Preferred Unit Holders. Prior to the Simplification Merger, Crestwood Midstream’s partnership agreement required Crestwood Midstream to make quarterly distributions to its Class A Preferred Unit holders. The holders of the Preferred Units were entitled to receive fixed quarterly distributions of $0.5804 per unit. For the 12 quarters following the quarter ended June 30, 2014 (the Initial Distribution Period), distributions on our Preferred Units could be made in additional Preferred Units, cash, or a combination thereof, at our election. If Crestwood Midstream elected to pay the quarterly distribution through the issuance of additional Preferred Units, the number of units to be distributed were calculated as the fixed quarterly distribution of $0.5804 per unit divided by the cash purchase price of $25.10 per unit. Crestwood Midstream accrued the fair value of such distribution at the end of the quarterly period and adjusted the fair value of the distribution on the date the additional Preferred Units are distributed.

Non-Controlling Partners

Crestwood Midstream Class A Preferred Units

As discussed above, prior to the Simplification Merger, Crestwood Equity classified the Crestwood Midstream Class A Preferred Units as a component of Interest of Non-Controlling Partners in its consolidated financial statements.

Crestwood Niobrara Preferred Interest

Crestwood Niobrara issued a preferred interest (Series A Preferred Units) 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. In December 2017, Crestwood Niobrara redeemed 100% of the outstanding Series A Preferred Units from GE for an aggregate purchase price of approximately $202.7 million and issued $175 million in new preferred interests (Series A-2 Preferred Units) to CN Jackalope Holdings LLC (Jackalope Holdings). In conjunction with the issuance of the Series A-2 Preferred Units, we entered into a Second Amended and Restated Limited Liability Company Agreement (Crestwood Niobrara Amended Agreement) with Crestwood Niobrara. Pursuant to the Crestwood Niobrara Amended Agreement, we serve as the managing member of Crestwood Niobrara and, subject to certain restrictions, we have the ability to redeem the Series A-2 Preferred Units for an amount in cash or CEQP common units equal to an amount necessary for Jackalope Holdings to achieve a certain rate of return. Also in conjunction with the Crestwood Niobrara Amended Agreement, we entered into a registration rights agreement with Jackalope Holdings. Pursuant to the registration rights agreement, we granted Jackalope Holdings certain rights with respect to CEQP’s common units issuable to Jackalope Holdings in certain circumstances as set forth in the Crestwood Niobrara Amended Agreement.

Net Income (Loss) Attributable to Non-Controlling Partners

The components of net income (loss) attributable to non-controlling partners for the years ended December 31, 2017, 2016 and 2015 are as follows (in millions):

	Year Ended December 31,
	2017		2016		2015
Crestwood Niobrara preferred interests	$	25.3	$	24.2	$	23.1
CMLP net income attributable to non-controlling partners	25.3		24.2		23.1
Crestwood Midstream limited partner interests	—		—		(683.0		)
Crestwood Midstream Class A preferred units	—		—		23.1
CEQP net income (loss) attributable to non-controlling partners	$	25.3	$	24.2	$	(636.8	)

Distributions to Non-Controlling Partners

Crestwood Midstream Limited Partners. Prior to the completion of the Simplification Merger, the Crestwood Midstream partnership agreement required it 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 applicable record date. Crestwood Equity was not entitled to distributions on its non-economic general partner interest in Crestwood Midstream. Crestwood Midstream paid cash distributions to its limited partners (excluding distributions to its general partner) of $222.9 million during the year ended December 31, 2015.

Crestwood Midstream Class A Preferred Unitholders. During the year ended December 31, 2015, Crestwood Midstream issued 1,271,935 Preferred Units to its preferred unitholders in lieu of paying a cash distribution of approximately $31.9 million.

Crestwood Niobrara Preferred Unitholders. Crestwood Niobrara is required to make quarterly distributions to GE within 30 days after the end of each quarter. Beginning with the distribution for 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 January 30, 2015, Crestwood Niobrara issued 3,680,570 preferred units to GE in lieu of paying a cash distribution for the quarter ended December 31, 2014. During the years ended December 31, 2017, 2016 and 2015, Crestwood Niobrara paid cash distributions of $15.2 million, $15.2 million and $11.3 million to GE.

Other Partners’ Capital Transactions

Subordinated Units

In conjunction with Crestwood Holdings’ acquisition of Crestwood Equity’s general partner, Crestwood Equity issued 438,789 subordinated units, which are considered limited partnership interests, and have the same rights and obligations as its common units, except that the subordinated units are entitled to receive distributions of available cash for a particular quarter only after each of our common units has received a distribution of at least $1.30 for that quarter.  The subordinated units convert to common units after (i) CEQP’s common units have received a cumulative distribution in excess of $5.20 during a consecutive four quarter period; and (ii) its Adjusted Operating Surplus (as defined in the agreement) exceeds the distribution on a fully dilutive basis.

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Equity Plans

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

Equity Plan

Equity Plans

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

The following table summarizes information regarding restricted and phantom unit activity during the years ended December 31, 2017, 2016 and 2015.

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2015	131,588		$	132.10
Vested - restricted units	(91,798	)	$	121.13
Vested - phantom units	(4,856	)	$	67.10
Granted - restricted units	142,255		$	55.25
Granted - phantom units	42,349		$	62.31
Modification - restricted units	226,401		$	68.85
Modification - phantom units	41,269		$	58.36
Forfeited (1)	(20,994	)	$	89.97
Unvested - December 31, 2015	466,214		$	69.80
Vested - restricted units	(193,295	)	$	76.82
Granted - restricted units	1,067,535		$	14.58
Granted - phantom units	17,467		$	15.54
Forfeited	(65,591	)	$	25.13
Unvested - December 31, 2016	1,292,330		$	24.67
Vested - restricted units	(607,115	)	$	28.00
Vested - performance units	(31,106	)	$	30.27
Granted - restricted units	919,411		$	25.69
Granted - phantom units	15,849		$	25.02
Granted - performance units	405,620		$	30.21
Forfeited - restricted units	(140,137	)	$	23.73
Forfeited - performance units	(24,756	)	$	30.45
Unvested - December 31, 2017	1,830,096		$	25.21

(1) We implemented a company-wide initiative to reduce operating costs in 2015 and beyond, which included a reduction in workforce. As a result, 7,263 restricted units were forfeited during the year ended December 31, 2015.

As of December 31, 2017 and 2016, we had total unamortized compensation expense of approximately $23.7 million and $14.9 million related to restricted, phantom, and performance units, which 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 $22.4 million, $16.0 million and $11.5 million under the Crestwood LTIP during the years ended December 31, 2017, 2016 and 2015, which is included in general and administrative expenses on our consolidated statements of operations.  As of February 12, 2018, we had 3,428,811 units available for issuance under the Crestwood LTIP.

Restricted Units. Under the Crestwood LTIP, participants who have been granted restricted units may elect to have 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 years ended December 31, 2017, 2016, and 2015 we withheld 206,600, 57,508 and 26,095 common units to satisfy employee tax withholding obligations.

Phantom Units. The Crestwood LTIP permits, grants of phantom units that entitle the holder thereof to receive upon vesting one CEQP common unit 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.

Performance Units. The Crestwood LTIP permits grants of performance units that are designed to provide an incentive for continuous employment to certain key employees. Performance units vest over a three-year performance period and the number of units issued are based on a performance multiplier ranging between 50% and 200%, determined based on the actual performance in the third year of the performance period compared to pre-established performance goals. The performance goals are based on achieving a specified level of distributable cash flow per unit, Adjusted EBITDA, return on capital invested, and three-year relative total shareholder return. The vesting of performance units is subject to the attainment of certain performance and market goals over a three year period and entitle a participant to receive common units of Crestwood Equity without payment of an exercise price upon vesting.

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Employee Benefit Plan

12 Months Ended

Dec. 31, 2017

Postemployment Benefits [Abstract]

Employee Benefit Plans

Employee Benefit Plan

A 401(k) plan is available to all of our employees after meeting certain requirements. The plan permits employees to make contributions up to 90% of their salary, up to statutory limits, which was $18,000 in 2017, 2016 and 2015. We match 100% of participants basic contribution up to 6% of eligible compensation. Employees may participate in the plans immediately and certain employees are not eligible for matching contributions until after a 90-day waiting period. Aggregate matching contributions made by us were $4.0 million, $3.8 million and $4.0 million during the years ended December 31, 2017, 2016 and 2015.

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Legal Proceedings

California Trucking Lawsuit. On March 13, 2017, a former Crestwood truck driver filed a lawsuit in the Superior Court for Kern County, California on behalf of all Crestwood Transportation LLC’s California drivers alleging that Crestwood Equity and its officers, directors and employees violated the California wage and hour laws by failing to comply with certain requirements of the laws. The plaintiffs currently include a total of 13 former and current Company drivers, however they are seeking to certify this lawsuit as a class action, which could potentially include approximately 150 drivers. Although our insurance policies would not cover this action, we believe we have meritorious defenses to this lawsuit and will vigorously defend ourselves. We are unable to predict the outcome or to estimate a reasonably possible loss or range of loss for this matter.

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 December 31, 2017 and 2016, both CEQP and CMLP had approximately $2.1 million and less than $0.1 million accrued for outstanding legal matters. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures for which we can estimate will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.

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

Regulatory Compliance

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

Environmental Compliance

Our operations are subject to stringent and complex laws and regulations pertaining to worker health, safety, and the environment. We are subject to laws and regulations at the federal, state, regional 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 worker safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures.

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. Thereafter, we contained and cleaned up the releases, and placed the impacted segments of these water lines back into service. In May 2015, we experienced a release of approximately 5,200 barrels of produced water on our Arrow water gathering system, immediately notified numerous regulatory authorities and other third parties, and thereafter contained and cleaned up the releases. 

In October 2014, we received data requests from the EPA related to the 2014 water releases and we responded to the requests during the first half of 2015.  In April 2015, the EPA issued a Notice of Potential Violation (NOPV) under the Clean Water Act relating to the 2014 water releases. We responded to the NOPV in May 2015 and in April 2017, we entered into an Administrative Order on Consent (the Order) with the EPA. The Order requires us to continue to remediate and monitor the impacted area for no less than four years unless all goals of the Order are satisfied earlier. On December 13, 2017, the EPA and Crestwood signed a Combined Complaint and Consent Agreement (CCCA) whereby we agreed to pay a civil penalty of $49,000 to the EPA and purchase emergency response equipment at an estimated cost of approximately $173,000 for the Three Affiliated Tribes as a Supplemental Environmental Project (SEP). The CCCA and SEP concludes the EPA’s penalty phase related to this matter.

On March 3, 2015, we received a grand jury subpoena from the United States Attorney’s Office in Bismarck, North Dakota, seeking documents and information relating to the largest of the three 2014 water releases. We provided the requested information during the second quarter of 2015 and key employees were interviewed by the United States’ Attorney in December

2015. On September 13, 2017, we received a notice from the United States Department of Justice that it completed the

investigation with no charges being filed against us.

In August 2015, we received a notice of violation from the Three Affiliated Tribes’ Environmental Division related to our 2014 produced water releases on the Fort Berthold Indian Reservation. The notice of violation imposes fines and requests reimbursements exceeding $1.1 million; however, the notice of violation was stayed on September 15, 2015, upon our posting of a performance bond for the amount contemplated by the notice, and pending the outcome of settlement discussions with the EPA related to the NOPV. Our discussions regarding the notice of violation continue with the Three Affiliated Tribes.

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 December 31, 2017.

At December 31, 2017 and 2016, our accrual of approximately $1.9 million and $2.1 million is based on our undiscounted estimate of amounts we will spend on compliance with environmental and other regulations, and any associated fines or penalties. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures (including the Arrow water releases described above) could range from approximately $1.9 million to $3.1 million at December 31, 2017.

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. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Our self insurance reserves could be affected if future claim developments differ from the historical trends. We believe changes in health care costs, trends in health care claims of our employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. We continually monitor changes in employee demographics, incident and claim type and evaluate our insurance accruals and adjust our accruals based on our evaluation of these qualitative data points. We are liable for the development of claims for our disposed retail propane operations, provided they were reported prior to August 1, 2012. At December 31, 2017 and 2016, CEQP’s self-insurance reserves were $13.6 million and $15.6 million. We estimate that $9.1 million of this balance will be paid subsequent to December 31, 2018. As such, CEQP has classified $9.1 million in other long-term liabilities on its consolidated balance sheet at December 31, 2017. At December 31, 2017 and 2016, CMLP’s self-insurance reserves were $11.6 million and $12.2 million. CMLP estimates that $7.6 million of this balance will be paid subsequent to December 31, 2018. As such, CMLP has classified $7.6 million in other long-term liabilities on its consolidated balance sheet at December 31, 2017.

Commitments and Purchase Obligations

Operating Leases.We also maintain operating leases in the ordinary course of our business activities. These leases include those for office buildings, crude oil railroad cars and other operating facilities and equipment. The terms of the agreements vary from 2018 until 2032.

Future minimum lease payments under our noncancelable operating leases for the next five years ending December 31 and in total thereafter consist of the following (in millions):

Year Ending December 31,
2018	$	35.2
2019	30.1
2020	23.2
2021	11.5
2022	7.7
Thereafter	18.8
Total minimum lease payments	$	126.5

Our rent expense for operating leases for the years ended December 31, 2017, 2016 and 2015, totaled $34.2 million, $25.5 million and $37.4 million.

Purchase Commitments. We periodically enter into agreements with suppliers to purchase fixed quantities of NGLs, distillates, crude oil and natural gas at fixed prices. At December 31, 2017, the total of these firm purchase commitments was $479.3 million, substantially all of which will occur over the course of the next twelve months. We also enter into non-binding agreements with suppliers to purchase quantities of NGLs, distillates and natural gas at variable prices at future dates at the then prevailing market prices.

We have entered into certain purchase commitments primarily related to our G&P segment. At December 31, 2017, our total purchase commitments were approximately $63.9 million, which primarily relate to future growth projects and maintenance obligations in our G&P segment. The purchases associated with these commitments are expected to occur over the next twelve months.

Guarantees and Indemnifications. We are involved in various joint ventures that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. For a further description of our guarantees associated with our joint ventures, see Note 6, and for a further description of our guarantees associated with our assets or businesses we have sold, see Note 9.

Our potential exposure under guarantee and indemnification arrangements can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim, specificity as to duration, and the particular transaction. As of December 31, 2017, we have no amounts accrued for these guarantees.

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Related Party Transactions

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Crestwood Holdings indirectly owns both CEQP’s and CMLP’s general partner. The affiliates of Crestwood Holdings and its owners are considered CEQP’s and CMLP’s related parties. 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. Below is a discussion of certain of our related party agreements.

Shared Services. CMLP shares common management, general and administrative and overhead costs with CEQP. CEQP grants long-term incentive awards under the Crestwood LTIP as discussed in Note 13. CEQP allocates a portion of its unit-based compensation costs to CMLP.

Stagecoach Gas Management Agreement. In May 2016, Crestwood Midstream Operations, LLC (Crestwood Midstream Operations), our wholly-owned subsidiary and Stagecoach Gas entered into a management agreement under which Crestwood Midstream Operations provides the management and operating services required by Stagecoach Gas’ facilities. The initial term of the agreement will expire in May 2021, and is automatically extended for three-year periods unless otherwise terminated pursuant to the terms of the agreement. Reimbursements charged to Stagecoach Gas under this agreement are reflected as operations and maintenance expenses charged by CEQP and CMLP in the table below.

Tres Palacios Operating Agreement. A consolidated subsidiary of Crestwood Midstream entered into an operating agreement with Tres Palacios, pursuant to which we assumed the responsibility of operating and maintaining the facilities as well as certain administrative and other general services identified in the agreement. Under the operating agreement, Tres Palacios reimburses us for all cost incurred on its behalf. These reimbursements are reflected as operations and maintenance expense charged by CEQP and CMLP in the table below.

Crestwood Permian Operating Agreement. In October 2016, Crestwood Midstream Operations entered into an operating agreement with Crestwood Permian, pursuant to which we provide operating services of Crestwood Permian’s facilities, as well as certain administrative and other general services identified in the agreement. Under this operating agreement, Crestwood Permian reimburses us for all costs incurred on its behalf. These reimbursements are reflected as operations and maintenance expense charged by CEQP and CMLP in the table below.

The following table shows revenues, costs of product/services sold, general and administrative expenses and reimbursement of expenses from our affiliates for the years December 31, 2017, 2016 and 2015 (in millions):

	Year Ended December 31,
	2017			2016			2015
Gathering and processing revenues at CEQP and CMLP	$	1.8		$	2.6		$	3.9
Gathering and processing costs of product sold at CEQP and CMLP(1)	$	15.3		$	17.7		$	28.9
Operations and maintenance expenses charged at CEQP and CMLP(2)	$	22.3		$	8.1		$	3.3
General and administrative expenses charged by CEQP to CMLP, net(3)	$	19.4		$	13.0		$	49.5
General and administrative expenses at CEQP charged to (from) Crestwood Holdings, net(4)	$	(1.7	)	$	(2.2	)	$	0.4

(1)    Represents natural gas purchases from Sabine Oil and Gas, an affiliate of Crestwood Holdings.

(2) We have operating agreements with certain of our unconsolidated affiliates pursuant to which we charge them operations and maintenance expenses in accordance with their respective agreements. During the year ended December 31, 2017, we charged $8.4 million to Stagecoach Gas, $3.5 million to Tres Palacios, $10.0 million to Crestwood Permian and $0.4 million to Jackalope. During the year ended December 31, 2016, we charged $5.0 million to Stagecoach Gas, $2.7 million to Tres Palacios, and $0.4 million to Jackalope. During the year ended December 31, 2015, we charged $2.8 million to Tres Palacios and $0.5 million to Jackalope.

(3) Includes $22.4 million, $16.0 million and $10.0 million of net unit-based compensation charges allocated from CEQP to CMLP for the years ended December 31, 2017, 2016 and 2015. In addition, includes $3.0 million, $3.0 million and $0.8 million of CMLP’s general and administrative costs allocated to CEQP during the years ended December 31, 2017, 2016 and 2015.

(4) Includes $3.1 million, $3.2 million and $0.1 million unit-based compensation charges allocated from Crestwood Holdings to CEQP and CMLP during the years ended December 31, 2017, 2016 and 2015.

The following table shows accounts receivable and accounts payable from our affiliates as of December 31, 2017 and 2016 (in millions):

	December 31,
	2017		2016
Accounts receivable at CEQP and CMLP	$	7.1	$	5.6
Accounts payable at CEQP	$	7.4	$	2.5
Accounts payable at CMLP	$	5.0	$	—

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Segments

12 Months Ended

Dec. 31, 2017

Segment Reporting [Abstract]

Segments

Segments

Financial Information

We have three operating and reportable segments: (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) marketing, supply and logistics operations. Our corporate operations include all general and administrative expenses that are not allocated to our reportable segments. For a further description of our operating and reporting segments, see Note 1. We assess the performance of our operating segments based on EBITDA, which is defined as income before income taxes, plus debt-related costs (net interest and debt expense and gain or loss on modification/extinguishment of debt) and depreciation, amortization and accretion expense.

Below is a reconciliation of CEQP’s net loss to EBITDA (in millions):

	Year Ended December 31,
	2017			2016			2015
Net loss	$	(166.6	)	$	(192.1	)	$	(2,303.7	)
Add:
Interest and debt expense, net	99.4			125.1			140.1
(Gain) loss on modification/extinguishment of debt	37.7			(10.0		)	20.0
Provision (benefit) for income taxes	(0.8		)	0.3			(1.4		)
Depreciation, amortization and accretion	191.7			229.6			300.1
EBITDA	$	161.4		$	152.9		$	(1,844.9	)

Below is a reconciliation of CMLP’s net loss to EBITDA (in millions):

	Year Ended December 31,
	2017			2016			2015
Net loss	$	(175.5	)	$	(197.5	)	$	(1,410.6	)
Add:
Interest and debt expense, net	99.4			125.1			130.5
(Gain) loss on modification/extinguishment of debt	37.7			(10.0		)	18.9
Depreciation, amortization and accretion	202.7			240.5			278.5
EBITDA	$	164.3		$	158.1		$	(982.7	)

The following tables summarize CEQP’s and CMLP’s reportable segment data for the years ended December 31, 2017, 2016 and 2015 (in millions). Intersegment revenues included in the following tables are accounted for as arms-length transactions that apply our revenue recognition policies described in Note 2. Included in earnings (loss) from unconsolidated affiliates below was approximately $32.5 million, $29.6 million and $86.1 million of depreciation and amortization expense and gains (losses) on long-lived assets, net related to our equity investments for the years ended December 31, 2017, 2016 and 2015, respectively.

Crestwood Equity

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			96.5			96.5
Loss on long-lived assets, net	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			0.5			1.3
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(99.0	)	$	161.4
Goodwill	$	45.9		$	—		$	101.7		$	—		$	147.6
Total assets	$	2,474.1		$	1,040.6		$	757.1		$	13.1		$	4,284.9
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

	Year Ended December 31, 2016
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,118.8		$	165.3		$	1,236.4		$	—		$	2,520.5
Intersegment revenues	108.6			4.2			(112.8		)	—			—
Costs of product/services sold	917.0			5.1			1,003.0			—			1,925.1
Operations and maintenance expense	77.0			21.4			59.7			—			158.1
General and administrative expense	—			—			—			88.2			88.2
Loss on long-lived assets, net	(2.0		)	(32.2		)	(31.4		)	—			(65.6		)
Goodwill impairment	(8.6		)	(44.9		)	(109.1		)	—			(162.6		)
Earnings from unconsolidated affiliates, net	20.3			11.2			—			—			31.5
Other income, net	—			—			—			0.5			0.5
EBITDA	$	243.1		$	77.1		$	(79.6	)	$	(87.7	)	$	152.9
Goodwill	$	45.9		$	—		$	153.1		$	—		$	199.0
Total assets	$	2,359.7		$	1,094.6		$	972.2		$	22.4		$	4,448.9
Purchases of property, plant and equipment	$	76.6		$	3.3		$	19.1		$	1.7		$	100.7

	Year Ended December 31, 2015
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,381.0		$	266.3		$	985.5		$	—		$	2,632.8
Intersegment revenues	66.7			—			(66.7		)	—			—
Costs of product/services sold	1,103.9			20.1			759.5			—			1,883.5
Operations and maintenance expense	89.0			31.7			69.5			—			190.2
General and administrative expense	—			—			—			116.3			116.3
Loss on long-lived assets	(787.3		)	(1.6		)	(32.3		)	—			(821.2		)
Goodwill impairment	(329.7		)	(623.4		)	(453.2		)	—			(1,406.3		)
Loss from unconsolidated affiliates, net	(43.4		)	(17.4		)	—			—			(60.8		)
Other income, net	—			—			—			0.6			0.6
EBITDA	$	(905.6	)	$	(427.9	)	$	(395.7	)	$	(115.7	)	$	(1,844.9	)
Purchases of property, plant and equipment	$	132.7		$	26.4		$	22.8		$	0.8		$	182.7

Crestwood Midstream

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			93.1			93.1
Loss on long-lived assets, net	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			—			0.8
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(96.1	)	$	164.3
Goodwill	$	45.9		$	—		$	101.7		$	—		$	147.6
Total assets	$	2,662.0		$	1,040.6		$	757.1		$	6.6		$	4,466.3
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

	Year Ended December 31, 2016
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,118.8		$	165.3		$	1,236.4		$	—		$	2,520.5
Intersegment revenues	108.6			4.2			(112.8		)	—			—
Costs of product/services sold	917.0			5.1			1,003.0			—			1,925.1
Operations and maintenance expense	77.0			18.3			59.7			—			155.0
General and administrative expense	—			—			—			85.6			85.6
Loss on long-lived assets, net	(2.0		)	(32.2		)	(31.4		)	—			(65.6		)
Goodwill impairment	(8.6		)	(44.9		)	(109.1		)	—			(162.6		)
Earnings from unconsolidated affiliates, net	20.3			11.2			—			—			31.5
EBITDA	$	243.1		$	80.2		$	(79.6	)	$	(85.6	)	$	158.1
Goodwill	$	45.9		$	—		$	153.1		$	—		$	199.0
Total assets	$	2,561.9		$	1,094.6		$	972.2		$	11.9		$	4,640.6
Purchases of property, plant and equipment	$	76.6		$	3.3		$	19.1		$	1.7		$	100.7

	Year Ended December 31, 2015
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,381.0		$	266.3		$	985.5		$	—		$	2,632.8
Intersegment revenues	66.7			—			(66.7		)	—			—
Costs of product/services sold	1,103.9			20.1			759.5			—			1,883.5
Operations and maintenance expense	89.0			30.2			69.5			—			188.7
General and administrative expense	—			—			—			105.6			105.6
Loss on long-lived assets, net	(194.1		)	(1.4		)	(32.3		)	—			(227.8		)
Goodwill impairment	(72.5		)	(623.4		)	(453.2		)	—			(1,149.1		)
Loss from unconsolidated affiliates, net	(43.4		)	(17.4		)	—			—			(60.8		)
EBITDA	$	(55.2	)	$	(426.2	)	$	(395.7	)	$	(105.6	)	$	(982.7	)
Purchases of property, plant and equipment	$	132.7		$	26.4		$	22.8		$	0.8		$	182.7

Major Customers

No customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2017, 2016 or 2015 at CEQP or CMLP.

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Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Consolidating Financial Information Disclosure

Condensed Consolidating Financial Information

Crestwood Midstream is a holding company (Parent) and owns no operating assets and has no significant operations independent of its subsidiaries. Obligations under Crestwood Midstream’s senior notes and its credit facility are jointly and severally guaranteed by substantially all of its subsidiaries, except for Crestwood Infrastructure, Crestwood Niobrara, Crestwood Northeast, PRBIC and Tres Holdings and their respective subsidiaries (collectively, Non-Guarantor Subsidiaries). Crestwood Midstream Finance Corp., the co-issuer of its senior notes, is Crestwood Midstream’s 100% owned subsidiary and has no material assets, operations, revenues or cash flows other than those related to its service as co-issuer of the Crestwood Midstream senior notes.

The tables below present condensed consolidating financial statements for Crestwood Midstream as Parent on a stand-alone, unconsolidated basis, and Crestwood Midstream’s combined guarantor and combined non-guarantor subsidiaries as of and for the years ended December 31, 2017, 2016 and 2015. 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.

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2017
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	1.0	$	—	$	—	$	—		$	1.0
Accounts receivable	—		439.7		2.9		—			442.6
Inventory	—		68.4		—		—			68.4
Other current assets	—		18.1		—		—			18.1
Total current assets	1.0		526.2		2.9		—			530.1
Property, plant and equipment, net	—		2,007.5		—		—			2,007.5
Goodwill and intangible assets, net	—		743.3		—		—			743.3
Investments in consolidated affiliates	3,705.4		—		—		(3,705.4		)	—
Investments in unconsolidated affiliates	—		—		1,183.0		—			1,183.0
Other assets	—		2.4		—		—			2.4
Total assets	$	3,706.4	$	3,279.4	$	1,185.9	$	(3,705.4	)	$	4,466.3
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	—	$	346.8	$	—	$	—		$	346.8
Other current liabilities	20.5		134.0		—		—			154.5
Total current liabilities	20.5		480.8		—		—			501.3
Long-term liabilities:
Long-term debt, less current portion	1,490.5		0.8		—		—			1,491.3
Other long-term liabilities	—		45.6		57.0		—			102.6
Deferred income taxes	—		0.7		—		—			0.7
Partners’ capital	2,195.4		2,751.5		953.9		(3,705.4		)	2,195.4
Interest of non-controlling partners in subsidiary	—		—		175.0		—			175.0
Total partners’ capital	2,195.4		2,751.5		1,128.9		(3,705.4		)	2,370.4
Total liabilities and partners’ capital	$	3,706.4	$	3,279.4	$	1,185.9	$	(3,705.4	)	$	4,466.3

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2016
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	1.3	$	—	$	—	$	—		$	1.3
Accounts receivable	—		289.3		0.5		—			289.8
Inventory	—		66.0		—		—			66.0
Other current assets	—		16.0		—		—			16.0
Total current assets	1.3		371.3		0.5		—			373.1
Property, plant and equipment, net	—		2,298.4		—		—			2,298.4
Goodwill and intangible assets, net	—		851.9		—		—			851.9
Investments in consolidated affiliates	4,093.7		—		—		(4,093.7		)	—
Investments in unconsolidated affiliates	—		—		1,115.4		—			1,115.4
Other assets	—		1.8		—		—			1.8
Total assets	$	4,095.0	$	3,523.4	$	1,115.9	$	(4,093.7	)	$	4,640.6
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	—	$	214.5	$	—	$	—		$	214.5
Other current liabilities	23.1		94.4		—		—			117.5
Total current liabilities	23.1		308.9		—		—			332.0
Long-term liabilities:
Long-term debt, less current portion	1,521.2		1.5		—		—			1,522.7
Other long-term liabilities	—		42.0		—		—			42.0
Deferred income taxes	—		0.7		—		—			0.7
Partners’ capital	2,550.7		3,170.3		923.4		(4,093.7		)	2,550.7
Interest of non-controlling partners in subsidiary	—		—		192.5		—			192.5
Total partners’ capital	2,550.7		3,170.3		1,115.9		(4,093.7		)	2,743.2
Total liabilities and partners’ capital	$	4,095.0	$	3,523.4	$	1,115.9	$	(4,093.7	)	$	4,640.6

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,880.9		$	—		$	—		$	3,880.9
Costs of product/services sold	—			3,374.7			—			—			3,374.7
Expenses:
Operations and maintenance	—			136.0			—			—			136.0
General and administrative	67.6			25.5			—			—			93.1
Depreciation, amortization and accretion	—			202.7			—			—			202.7
	67.6			364.2			—			—			431.8
Other operating expenses:
Gain on long-lived assets, net	—			(65.6		)	—			—			(65.6		)
Goodwill impairment	—			(38.8		)	—			—			(38.8		)
Loss on contingent consideration	—			—			(57.0		)	—			(57.0		)
Operating income (loss)	(67.6		)	37.6			(57.0		)	—			(87.0		)
Earnings from unconsolidated affiliates, net	—			—			47.8			—			47.8
Interest and debt expense, net	(99.4		)	—			—			—			(99.4		)
Loss on modification/extinguishment of debt	(37.7		)	—			—			—			(37.7		)
Other income, net	—			0.8			—			—			0.8
Equity in net income (loss) of subsidiaries	3.9			—			—			(3.9		)	—
Net income (loss)	(200.8		)	38.4			(9.2		)	(3.9		)	(175.5		)
Net income attributable to non-controlling partners	—			—			25.3			—			25.3
Net income (loss) attributable to Crestwood Midstream Partners LP	$	(200.8	)	$	38.4		$	(34.5	)	$	(3.9	)	$	(200.8	)

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2016
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations		Consolidated
Revenues	$	—		$	2,520.5		$	—	$	—	$	2,520.5
Costs of product/services sold	—			1,925.1			—		—		1,925.1
Expenses:
Operations and maintenance	—			155.0			—		—		155.0
General and administrative	66.4			19.2			—		—		85.6
Depreciation, amortization and accretion	—			240.5			—		—		240.5
	66.4			414.7			—		—		481.1
Other operating expenses:
Loss on long-lived assets, net	—			(65.6		)	—		—		(65.6		)
Goodwill impairment	—			(162.6		)	—		—		(162.6		)
Operating loss	(66.4		)	(47.5		)	—		—		(113.9		)
Earnings from unconsolidated affiliates, net	—			—			31.5		—		31.5
Interest and debt expense, net	(125.1		)	—			—		—		(125.1		)
Gain on modification/extinguishment of debt	10.0			—			—		—		10.0
Equity in net income (loss) of subsidiaries	(40.2		)	—			—		40.2		—
Net income (loss)	(221.7		)	(47.5		)	31.5		40.2		(197.5		)
Net income attributable to non-controlling partners	—			—			24.2		—		24.2
Net income (loss) attributable to Crestwood Midstream Partners LP	$	(221.7	)	$	(47.5	)	$	7.3	$	40.2	$	(221.7	)

Crestwood Midstream Partners
Condensed Consolidating Statements of Operations
Year Ended December 31, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Revenues	$	—		$	2,632.8		$	—		$	—	$	2,632.8
Costs of product/services sold	—			1,883.5			—			—		1,883.5
Expenses:
Operations and maintenance	—			188.7			—			—		188.7
General and administrative	65.3			40.3			—			—		105.6
Depreciation, amortization and accretion	—			278.5			—			—		278.5
	65.3			507.5			—			—		572.8
Other operating expenses:
Loss on long-lived assets, net	—			(227.8		)	—			—		(227.8		)
Goodwill impairment	—			(1,149.1		)	—			—		(1,149.1		)
Operating loss	(65.3		)	(1,135.1		)	—			—		(1,200.4		)
Loss from unconsolidated affiliates, net	—			—			(60.8		)	—		(60.8		)
Interest and debt expense, net	(130.5		)	—			—			—		(130.5		)
Loss on modification/extinguishment of debt	(18.9		)	—			—			—		(18.9		)
Equity in net income (loss) of subsidiaries	(1,219.0		)	—			—			1,219.0		—
Net income (loss)	(1,433.7		)	(1,135.1		)	(60.8		)	1,219.0		(1,410.6		)
Net income attributable to non-controlling partners	—			—			23.1			—		23.1
Net income (loss) attributable to Crestwood Midstream Partners LP	(1,433.7		)	(1,135.1		)	(83.9		)	1,219.0		(1,433.7		)
Net income attributable to Class A preferred units	23.1			—			—			—		23.1
Net income (loss) attributable to partners	$	(1,456.8	)	$	(1,135.1	)	$	(83.9	)	$	1,219.0	$	(1,456.8	)

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(162.3	)	$	379.2		$	45.3		$	—		$	262.2
Cash flows from investing activities:
Purchases of property, plant and equipment	(6.7		)	(181.7		)	—			—			(188.4		)
Investment in unconsolidated affiliates	—			—			(58.0		)	—			(58.0		)
Capital distributions from unconsolidated affiliates	—			—			59.9			—			59.9
Net proceeds from sale of assets	—			225.2			—			—			225.2
Capital distributions from consolidated affiliates	4.3			—			—			(4.3		)	—
Net cash provided by (used in) investing activities	(2.4		)	43.5			1.9			(4.3		)	38.7
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,838.6			—			—			—			2,838.6
Payments on long-term debt	(2,912.6		)	(1.3		)	—			—			(2,913.9		)
Payments on capital leases	—			(2.7		)	—			—			(2.7		)
Payments for debt-related deferred costs	(1.0		)	—			—			—			(1.0		)
Redemption of non-controlling interest	—			—			(202.7		)	—			(202.7		)
Net proceeds from issuance of non-controlling interest	—			—			175.0			—			175.0
Distributions to partners	(174.0		)	—			(15.2		)	—			(189.2		)
Distributions to parent	—			—			(4.3		)	4.3			—
Taxes paid for unit-based compensation vesting	—			(5.5		)	—			—			(5.5		)
Change in intercompany balances	413.4			(413.4		)	—			—			—
Other	—			0.2			—			—			0.2
Net cash provided by (used in) financing activities	164.4			(422.7		)	(47.2		)	4.3			(301.2		)
Net change in cash	(0.3		)	—			—			—			(0.3		)
Cash at beginning of period	1.3			—			—			—			1.3
Cash at end of period	$	1.0		$	—		$	—		$	—		$	1.0

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2016
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(188.0	)	$	502.8		$	39.0		$	—		$	353.8
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(7.2		)	—			—			(7.2		)
Purchases of property, plant and equipment	(1.7		)	(99.0		)	—			—			(100.7		)
Investment in unconsolidated affiliates	—			—			(12.4		)	—			(12.4		)
Capital distributions from unconsolidated affiliates	—			—			14.8			—			14.8
Net proceeds from sale of assets	—			972.7			—			—			972.7
Capital distributions from consolidated affiliates	26.2			—			—			(26.2		)	—
Net cash provided by (used in) investing activities	24.5			866.5			2.4			(26.2		)	867.2
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	1,565.3			—			—			—			1,565.3
Payments on long-term debt	(2,535.3		)	(0.8		)	—			—			(2,536.1		)
Payments on capital leases	—			(1.9		)	—			—			(1.9		)
Payments for debt-related deferred costs	(3.5		)	—			—			—			(3.5		)
Distributions to partners	(227.6		)	—			(15.2		)	—			(242.8		)
Distributions to parent	—			—			(26.2		)	26.2			—
Taxes paid for unit-based compensation vesting	—			(0.8		)	—			—			(0.8		)
Change in intercompany balances	1,365.8			(1,365.8		)	—			—			—
Net cash provided by (used in) financing activities	164.7			(1,369.3		)	(41.4		)	26.2			(1,219.8		)
Net change in cash	1.2			—			—			—			1.2
Cash at beginning of period	0.1			—			—			—			0.1
Cash at end of period	$	1.3		$	—		$	—		$	—		$	1.3

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(190.8	)	$	650.0		$	12.6		$	—		$	471.8
Cash flows from investing activities:
Purchases of property, plant and equipment	(0.8		)	(181.9		)	—			—			(182.7		)
Investment in unconsolidated affiliates	—			—			(41.8		)	—			(41.8		)
Capital distributions from unconsolidated affiliates	—			—			9.3			—			9.3
Net proceeds from sale of assets	—			2.7			—			—			2.7
Capital contributions to consolidated affiliates	(31.2		)	—			—			31.2			—
Net cash provided by (used in) investing activities	(32.0		)	(179.2		)	(32.5		)	31.2			(212.5		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	3,490.1			—			—			—			3,490.1
Payments on long-term debt	(2,960.9		)	—			—			—			(2,960.9		)
Payments on capital leases	—			(2.2		)	—			—			(2.2		)
Payments for debt-related deferred costs	(17.3		)	—			—			—			(17.3		)
Financing fees paid for early debt redemption	(13.6		)	—			—			—			(13.6		)
Distributions to partners	(808.2		)	—			(11.3		)	—			(819.5		)
Contributions from parent	—			—			31.2			(31.2		)	—
Net proceeds from issuance of preferred units	58.8			—			—			—			58.8
Taxes paid for unit-based compensation vesting	—			(2.1		)	—			—			(2.1		)
Change in intercompany balances	474.1			(474.1		)	—			—			—
Other	(0.1		)	—			—			—			(0.1		)
Net cash provided by (used in) financing activities	222.9			(478.4		)	19.9			(31.2		)	(266.8		)
Net change in cash	0.1			(7.6		)	—			—			(7.5		)
Cash at beginning of period	—			7.6			—			—			7.6
Cash at end of period	$	0.1		$	—		$	—		$	—		$	0.1

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Schedule I - Crestwood Equity Partners LP - Parent Only

12 Months Ended

Dec. 31, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Schedule I - Crestwood Equity Partners LP - Parent Only

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Balance Sheets

(in millions)

	December 31,
	2017		2016
Assets
Current assets:
Cash	$	0.3	$	0.3
Total current assets	0.3		0.3
Property, plant and equipment, net	1.2		1.4
Intangible assets, net	1.4		4.5
Investments in subsidiaries	2,005.1		2,342.7
Other assets	3.5		4.3
Total assets	$	2,011.5	$	2,353.2
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	2.7	$	2.7
Accrued expenses	1.2		1.4
Total current liabilities	3.9		4.1
Other long-term liabilities	2.1		2.6
Total partners’ capital	2,005.5		2,346.5
Total liabilities and partners’ capital	$	2,011.5	$	2,353.2

See accompanying notes.

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Operations

(in millions)

	Year Ended December 31,
	2017			2016			2015
Revenues	$	—		$	—		$	—
Expenses	6.7			6.0			14.5
Operating loss	(6.7		)	(6.0		)	(14.5		)
Interest and debt expense, net	—			—			(9.6		)
Equity in net loss of subsidiaries	(160.4		)	(186.6		)	(2,279.1		)
Loss on modification/extinguishment of debt	—			—			(1.1		)
Other income, net	0.5			0.5			0.6
Net loss	(166.6		)	(192.1		)	(2,303.7		)
Net income (loss) attributable to non-controlling partners	25.3			24.2			(636.8		)
Net income loss attributable to Crestwood Equity Partners LP	$	(191.9	)	$	(216.3	)	$	(1,666.9	)

See accompanying notes.

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Comprehensive Income

(in millions)

	Year Ended December 31,
	2017			2016			2015
Net loss	$	(166.6	)	$	(192.1	)	$	(2,303.7	)
Change in fair value of Suburban Propane Partners, LP units	(0.8		)	0.8			(2.7		)
Comprehensive loss	(167.4		)	(191.3		)	(2,306.4		)
Comprehensive income (loss) attributable to non-controlling interest	25.3			24.2			(636.8		)
Comprehensive loss attributable to Crestwood Equity Partners LP	$	(192.7	)	$	(215.5	)	$	(1,669.6	)

See accompanying notes.

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Cash Flows

(in millions)

	Year Ended December 31,
	2017			2016			2015
Cash flows from operating activities	$	(3.6	)	$	(3.5	)	$	(14.7	)
Cash flows from investing activities	174.0			227.6			593.8
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	—			—			771.7
Principal payments on long-term debt	—			(0.2		)	(1,152.1		)
Distributions paid to partners	(182.6		)	(219.8		)	(171.5		)
Proceeds from issuance of common units	15.2			—			—
Change in intercompany balances	(3.0		)	(4.2		)	(30.5		)
Net cash used in financing activities	(170.4		)	(224.2		)	(582.4		)
Net change in cash	—			(0.1		)	(3.3		)
Cash at beginning of period	0.3			0.4			3.7
Cash at end of period	$	0.3		$	0.3		$	0.4

See accompanying notes.

Schedule I

Crestwood Equity Partners LP

Parent Only

Notes to Condensed Financial Statements

Note 1. Basis of Presentation

In the parent-only financial statements, our investment in subsidiaries is stated at cost plus equity in undistributed earnings of subsidiaries since the date of acquisition.  Our share of net income of our unconsolidated subsidiaries is included in consolidated income using the equity method.  The parent-only financial statements should be read in conjunction with our consolidated financial statements. 

Note 2.Distributions    

During the years ended December 31, 2017, 2016 and 2015, we received cash distributions from Crestwood Midstream Partners LP of approximately $174.0 million, $227.6 million and $31.4 million.

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Schedule II - Crestwood Equity Parnters LP - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2017

Valuation and Qualifying Accounts [Abstract]

Schedule II - Crestwood Equity Parnters LP - Valuation and Qualifying Accounts

Schedule II

Crestwood Equity Partners LP

Crestwood Midstream Partners LP

Valuation and Qualifying Accounts

For the Years Ended December 31, 2017, 2016 and 2015

(in millions)

	Balance at beginning of period		Charged to costs and expenses		Other Additions		Deductions (write-offs)			Balance at end of period
Allowance for doubtful accounts
2017	$	1.9	$	1.5	$	—	$	(1.0	)	$	2.4
2016	0.4		1.9		—		(0.4		)	1.9
2015	0.1		—		0.4		(0.1		)	0.4

XML

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

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Use of Estimates

Use of Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these consolidated financial statements. Actual results can differ from those estimates.

Cash

Cash

We consider all highly liquid investments with an original maturity of less than three months to be cash.

Inventory

Inventory

Inventory for our marketing, supply and logistics operations are stated at the lower of cost or market and cost is computed predominantly using the average cost method. Our inventory consists primarily of crude oil and NGLs of approximately $67.9 million and $56.7 million at December 31, 2017 and 2016.

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment is recorded at is original cost of construction or, upon acquisition, at the fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and interest. We capitalize major units of property replacements or improvement and expense minor items. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Gathering systems and pipelines	15 - 20
Facilities and equipment	3 - 25
Buildings, rights-of-way and easements	1 - 40
Office furniture and fixtures	5 - 10
Vehicles	5

We depleted salt deposits included in our property, plant and equipment utilizing the unit of production method prior to their sale in December 2017.

We evaluate our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset, which is typically based on discounted cash flow projections using assumptions as to revenues, costs and discount rates typical of third party market participants, which is a Level 3 fair value measurement.

During 2017 and 2015, we recorded the following impairments of our property, plant and equipment and we reflected these impairments in loss on long-lived assets in our consolidated statements of operations. We did not record impairments of our property, plant and equipment during the year ended December 31, 2016.

• During 2017, we incurred $81.4 million of impairments of our property, plant and equipment related to our MS&L West Coast operations, which resulted from decreasing the forecasted cash flows to be generated by those operations. The fair value of our property, plant and equipment related to our West Coast operation was $66.4 million as of December 31, 2017. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future.

• During 2015, we incurred $8.5 million of impairments of our property, plant and equipment related to our Granite Wash gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our major customer of those assets declared bankruptcy and ceased substantial drilling in the Granite Wash in the near future given current and future anticipated market conditions related to natural gas and NGLs.

• During 2015, Crestwood Equity incurred a $354.4 million impairment of its property, plant and equipment related to its Barnett gathering and processing operations, which resulted from the actions of our primary customer in the Barnett Shale, Quicksilver Resources, Inc. (Quicksilver), related to its filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015. Crestwood Midstream did not record an impairment of its property, plant and equipment related to its gathering and processing assets in the Barnett Shale as the sum of the undiscounted cash flows expected to result from the use of the assets and their eventual disposition exceeded the carrying value of the property, plant and equipment by over 30%. As a result, Crestwood Midstream’s property, plant and equipment exceeds Crestwood Equity’s property, plant and equipment related to its gathering and processing assets in the Barnett Shale.

• During 2015, we incurred $61.9 million and $45.7 million of impairments of property, plant and equipment related to our Fayetteville and Haynesville gathering and processing operations, respectively, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas.

• During 2015, we incurred a $31.2 million impairment of our property, plant and equipment related to our Watkins Glen development project in our marketing, supply and logistics operations, which resulted from continued delays and uncertainties in the permitting of our proposed NGL storage facility.

At December 31, 2017, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 12% discount rate and projected cash flows, which is a Level 3 fair value measurement. At December 31, 2015, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 15% discount rate and projected cash flows, which is a Level 3 fair value measurement. Projected cash flows of our property, plant and equipment are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, constructions costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Identifiable Intangible Assets

Identifiable Intangible Assets

Our identifiable intangible assets consist of customer accounts, covenants not to compete, trademarks and certain revenue contracts. Customer accounts, covenants not to compete, trademarks and certain of our revenue contracts have arisen from acquisitions. We amortize certain of our revenue contracts based on the projected cash flows associated with these contracts if the projected cash flows are readily determinable, otherwise we amortize our revenue contracts on a straight-line basis.  We recognize acquired intangible assets separately if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

Goodwill

Identifiable Intangible Assets

Our identifiable intangible assets consist of customer accounts, covenants not to compete, trademarks and certain revenue contracts. Customer accounts, covenants not to compete, trademarks and certain of our revenue contracts have arisen from acquisitions. We amortize certain of our revenue contracts based on the projected cash flows associated with these contracts if the projected cash flows are readily determinable, otherwise we amortize our revenue contracts on a straight-line basis.  We recognize acquired intangible assets separately if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

During 2017, 2016 and 2015, we recorded the following impairments of our intangible assets and we reflected these impairments in loss on long-lived assets in our consolidated statements of operations:

• During 2017, we fully impaired $0.8 million of intangible assets related to our MS&L West Coast operations, which resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future.

• During 2016, we incurred a $31.4 million impairment of intangible assets related to our MS&L Trucking operations, which resulted from the impact of increased competition on our Trucking business and the loss of several key customer relationships that were acquired in 2013 to which the intangible assets related.

• During 2015, Crestwood Equity fully impaired $238.9 million of its intangible assets related to its Barnett gathering and processing operations, which resulted from the actions of our primary customer in the Barnett Shale, Quicksilver, related to filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015.

• During 2015, we fully impaired $70.9 million and $6.0 million of intangible assets related to our Fayetteville and Haynesville gathering and processing operations, respectively, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas.

At December 31, 2016, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 19% discount rate and projected cash flows, which is a Level 3 fair value measurement. At December 31, 2015, our estimates of fair value considered a number of factors, including the potential value we would receive if we sold the asset, a 15% discount rate and projected cash flows, which is a Level 3 fair value measurement. Projected cash flows of our intangible assets are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:

	Weighted-Average Life (years)
Customer accounts and revenue contracts	20
Trademarks	6 - 8

Investment in Unconsolidated Affiliate

Investment in Unconsolidated Affiliates

Equity method investments in which we exercise significant influence, but do not control and are not the primary beneficiary, are accounted for using the equity method of accounting. Differences in the basis of investments and the separate net asset values of the investees, if any, are amortized into net income or loss over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill. We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, or if we decide to sell an investment in unconsolidated affiliate, we adjust the carrying values of the asset downward, if necessary, to their estimated fair values.

Asset Retirement Obligations

Asset Retirement Obligations

An asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. We record a liability for legal or contractual obligations to retire our long-lived assets associated with our facilities and right-of-way contracts we hold. We record a liability in the period the obligation is incurred and estimable. An ARO is initially recorded at its estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the fair value of the liability as a result of the passage of time, which we record as depreciation, amortization and accretion expense on our consolidated statements of operations. The fair value of certain AROs could not be determined as the settlement dates (or range of dates) associated with these assets were not estimable. At December 31, 2017 and 2016, our AROs were reflected in other long-term liabilities on our consolidated balance sheets. See Note 5 for a further discussion of our AROs.

Revenue Recognition

Revenue Recognition

We gather, process, treat, compress, store, transport and sell various commodities (including crude oil, natural gas, NGLs and water) pursuant to fixed-fee and percent-of-proceeds contracts. Under certain of those contracts in our G&P operations and our MS&L operations, we take title to the underlying commodity. We classify the revenues associated with the products to which we take title as product revenues and all other revenues as service revenues in our consolidated statement of operations.

We recognize revenues for these services and products when all of the following criteria are met:

• services have been rendered or products delivered or sold;

• persuasive evidence of an exchange arrangement exists;

• the price for services is fixed or determinable; and

• collectability is reasonably assured.

We record deferred revenue when we receive amounts from our customers but have not met the criteria listed above. We recognize deferred revenue in our consolidated statements of operations when the criteria has been met and all services have been rendered. At December 31, 2017 and 2016, we had deferred revenue of approximately $0.6 million and $7.5 million, which is reflected in accrued expenses and other liabilities on our consolidated balance sheets.

Credit Risk and Concentrations

Credit Risk and Concentrations

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.

Income Taxes

Income Taxes

Crestwood Equity is a master limited partnership and Crestwood Midstream is a limited partnership. Partnerships are generally not subject to federal income tax, although publicly-traded partnerships are treated as corporations for federal income tax purposes and therefore are subject to federal income tax, unless the partnership generates at least 90% of its gross income from qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a partnership for federal income tax purposes. We satisfy the qualifying income requirement and are treated as a partnership for federal and state income tax purposes. Our consolidated earnings are included in the federal and state income tax returns of our partners. However, legislation in certain states allows for taxation of partnerships, and as such, certain state taxes have been included in our accompanying financial statements as income taxes due to the nature of the tax in those particular states as discussed below. In addition, federal and state income taxes are provided on the earnings of the subsidiaries incorporated as taxable entities. We are required to recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax basis of assets and liabilities using expected rates in effect for the year in which the differences are expected to reverse.

We are responsible for the Texas Margin tax computed on the Texas franchise tax returns. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Environmental Costs and Other Contingencies

Environmental Costs and Other Contingencies

We recognize liabilities for environmental and other contingencies when there is an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of range is accrued.

We record liabilities for environmental contingencies at their undiscounted amounts on our consolidated balance sheets as accrued expenses and other liabilities when environmental assessments indicate that remediation efforts are probable and costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors. These estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and recognize a current period charge in operations and maintenance expenses when clean-up efforts do not benefit future periods.

We evaluate potential recoveries of amounts from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet.

Price Risk Management Activities

Price Risk Management Activities

We utilize certain derivative financial instruments to (i) manage our exposure to commodity price risk, specifically, the related change in the fair value of inventory, as well as the variability of cash flows related to forecasted transactions; (ii) ensure the availability of adequate physical supply of commodity; and (iii) manage our exposure to the interest rate risk associated with fixed and variable rate borrowings. We record all derivative instruments on the balance sheet at their fair values as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded through current earnings.

We did not have any derivatives identified as fair value hedges or cash flow hedges for accounting purposes during the years ended December 31, 2017, 2016 or 2015.

Unit-Based Compensation

Unit-Based Compensation

Long-term incentive awards are granted under the Crestwood Equity incentive plan. Unit-based compensation awards consist of restricted units that are valued at the closing market price of CEQP’s common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. We generally recognize the expense associated with the award over the vesting period on a straight line basis. Effective January 1, 2017, we adopted the provisions of ASU 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of the accounting for share-based payment award transactions, including the classification of awards as either equity or liabilities and the presentation on the statement of cash flows. The adoption of this accounting standard did not have a material impact on our consolidated financial statements.

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

12 Months Ended

Dec. 31, 2017

Accounting Policies [Abstract]

Estimated Useful Lives Of Property, Plant And Equipment

Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Gathering systems and pipelines	15 - 20
Facilities and equipment	3 - 25
Buildings, rights-of-way and easements	1 - 40
Office furniture and fixtures	5 - 10
Vehicles	5

Intangible Assets, Useful life

Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:

	Weighted-Average Life (years)
Customer accounts and revenue contracts	20
Trademarks	6 - 8

Intangible assets consisted of the following at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Customer accounts	$	438.9	$	541.9	$	438.9	$	541.9
Covenants not to compete	—		1.0		—		1.0
Gas gathering, compression and processing contracts	325.2		325.2		325.2		325.2
Trademarks	24.7		30.5		9.2		15.0
	788.8		898.6		773.3		883.1
Less: accumulated amortization	191.6		241.2		177.6		230.2
Total intangible assets, net	$	597.2	$	657.4	$	595.7	$	652.9

The following table summarizes total accumulated amortization of our intangible assets at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Customer accounts	$	89.8	$	162.4	$	89.8	$	162.4
Gas gathering, compression and processing contracts	82.0		63.2		82.0		63.2
Trademarks	19.8		15.6		5.8		4.6
Total accumulated amortization	$	191.6	$	241.2	$	177.6	$	230.2

Schedule of Goodwill

The following table summarizes the goodwill of our various reporting units (in millions):

	Goodwill Impairments during the Year Ended December 31, 2015		Goodwill at January 1, 2016		Goodwill Impairments during the Year Ended December 31, 2016		Other				Goodwill at December 31, 2016		Impact of Sale of US Salt				Goodwill Impairments during the Year Ended December 31, 2017		Goodwill at December 31, 2017
G&P
Fayetteville	$	72.5	$	—	$	—	$	—			$	—	$	—			$	—	$	—
Marcellus	—		8.6		8.6		—				—		—				—		—
Arrow	—		45.9		—		—				45.9		—				—		45.9
S&T
Northeast Storage and Transportation	—		726.3		—		(726.3		)	(1)	—		—				—		—
COLT	623.4		44.9		44.9		—				—		—				—		—
MS&L																			—
West Coast	85.9		—		—		2.4			(2)	2.4		—				2.4		—
Supply and Logistics	99.0		167.2		65.5		—				101.7		—				—		101.7
Storage and Terminals	53.7		50.5		14.1		—				36.4		—				36.4		—
US Salt	—		12.6		—		—				12.6		(12.6		)	(3)	—		—
Trucking	148.4		29.5		29.5		—				—		—				—		—
Watkins Glen	66.2		—		—		—				—		—				—		—
Total CMLP	$	1,149.1	$	1,085.5	$	162.6	$	(723.9	)		$	199.0	$	(12.6	)		$	38.8	$	147.6
Barnett (G&P)	257.2		—		—		—				—		—				—		—
Total CEQP	$	1,406.3	$	1,085.5	$	162.6	$	(723.9	)		$	199.0	$	(12.6	)		$	38.8	$	147.6

(1) Reflects impact of the deconsolidation of our NE S&T assets in June 2016.

(2) In December 2016, we acquired four NGL terminals for our MS&L segment for approximately $7.2 million with total goodwill of approximately $2.4 million. This acquisition was not material to our consolidated financial statements as of and for the year ended December 31, 2016.

(3) In December 2017, we sold 100% of our equity interests in US Salt to an affiliate of Kissner Group Holdings LP.

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Certain Balance Sheet Information (Tables)

12 Months Ended

Dec. 31, 2017

Balance Sheet Related Disclosures [Abstract]

Property, Plant And Equipment

Property, plant and equipment of the following at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Gathering systems and pipelines and related assets	$	678.0	$	639.4	$	820.9	$	782.3
Facilities and equipment	1,141.4		1,328.3		1,326.5		1,513.4
Buildings, land, rights-of-way, storage rights and easements	319.1		315.4		322.8		319.1
Vehicles	37.3		45.7		35.5		44.0
Construction in process	87.5		85.9		87.5		85.9
Salt deposits	—		120.5		—		120.5
Office furniture and fixtures	21.9		20.2		22.1		20.3
	2,285.2		2,555.4		2,615.3		2,885.5
Less: accumulated depreciation and depletion	464.4		457.8		607.8		587.1
Total property, plant and equipment, net	$	1,820.8	$	2,097.6	$	2,007.5	$	2,298.4

Intangible Assets

Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:

	Weighted-Average Life (years)
Customer accounts and revenue contracts	20
Trademarks	6 - 8

Intangible assets consisted of the following at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Customer accounts	$	438.9	$	541.9	$	438.9	$	541.9
Covenants not to compete	—		1.0		—		1.0
Gas gathering, compression and processing contracts	325.2		325.2		325.2		325.2
Trademarks	24.7		30.5		9.2		15.0
	788.8		898.6		773.3		883.1
Less: accumulated amortization	191.6		241.2		177.6		230.2
Total intangible assets, net	$	597.2	$	657.4	$	595.7	$	652.9

The following table summarizes total accumulated amortization of our intangible assets at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Customer accounts	$	89.8	$	162.4	$	89.8	$	162.4
Gas gathering, compression and processing contracts	82.0		63.2		82.0		63.2
Trademarks	19.8		15.6		5.8		4.6
Total accumulated amortization	$	191.6	$	241.2	$	177.6	$	230.2

Schedule of Intangible Assets, Future Amortization Expense

Estimated amortization of our intangible assets for the next five years is as follows (in millions):

	CEQP		CMLP
Year Ending December 31,
2018	$	43.4	$	42.0
2019	41.7		41.7
2020	41.7		41.7
2021	41.7		41.7
2022	41.7		41.7

Schedule of Accrued Liabilities

Accrued expenses and other liabilities consisted of the following at December 31, 2017 and 2016 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2017		2016		2017		2016
Accrued expenses	$	56.6	$	46.5	$	55.5	$	45.1
Accrued property taxes	4.8		4.2		4.8		4.2
Accrued natural gas purchases	—		4.9		—		4.9
Income tax payable	0.3		1.6		0.3		0.4
Interest payable	20.3		22.8		20.3		22.8
Accrued additions to property, plant and equipment	22.3		1.7		22.2		1.7
Capital leases	1.0		1.3		1.0		1.3
Deferred revenue	0.6		7.5		0.6		7.5
Total accrued expenses and other liabilities	$	105.9	$	90.5	$	104.7	$	87.9

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2017

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

The following table presents the changes in the net asset retirement obligations for the years ended December 31, 2017 and 2016 (in millions):

	December 31,
	2017			2016
Net asset retirement obligation at January 1	$	27.8		$	26.4
Liabilities incurred	—			1.0
Liabilities settled	(1.2		)	(1.2		)
Accretion expense	1.4			1.6
Change in estimate	(0.5		)	—
Net asset retirement obligation at December 31	$	27.5		$	27.8

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Investments in Unconsolidated Affiliates Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2017

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments [Table Text Block]

Distributions and Contributions

	Distributions						Contributions
	Year Ended December 31,						Year Ended December 31,
	2017		2016		2015		2017		2016		2015
Stagecoach Gas	$	47.3	$	16.0	$	—	$	0.8	$	—	$	—
Jackalope(1)	26.3		27.4		12.5		3.5		1.4		25.4
Tres Holdings(2)	9.0		8.5		7.4		5.6		11.0		5.7
PRBIC(1)	1.6		2.0		1.9		—		—		10.7
Crestwood Permian(3)	23.4		—		—		117.5		—		—
Total	$	107.6	$	53.9	$	21.8	$	127.4	$	12.4	$	41.8

(1) Jackalope and PRBIC are required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. We

received a cash distribution of $7.4 million from Jackalope in January 2018, and we received a cash distribution of $0.3 million from PRBIC in February

2018.

(2) 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.

(3) On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico at our historical book value of

approximately $69.4 million. This contribution was treated as a non-cash transaction between entities under common control.

Operating Results Data

	Year Ended December 31,
	2017						2016						2015
	Operating Revenues		Operating Expenses		Net  Income		Operating Revenues		Operating Expenses		Net  Income		Operating Revenues		Operating Expenses		Net  Income
Stagecoach	$	168.6	$	77.7	$	91.1	$	99.3	$	44.1	$	55.3	$	—	$	—	$	—
Other(1)	181.8		143.6		38.9		127.6		113.9		13.5		104.7		79.5		24.9
Total	$	350.4	$	221.3	$	130.0	$	226.9	$	158.0	$	68.8	$	104.7	$	79.5	$	24.9

(1) Includes our Jackalope, Tres Holdings, PRBIC and Crestwood Permian equity investments. We amortize the excess basis in certain of our equity investments as an increase in our earnings from unconsolidated affiliates. We recorded amortization of the excess basis in our Jackalope equity investment of less than $0.1 million for both the years ended December 31, 2017 and 2016, and $3.0 million for the year ended December 31, 2015, which we amortize over the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake). We recorded amortization of the excess basis in our Tres Holdings equity investment of approximately $1.3 million for each of the years ended December 31, 2017, 2016 and 2015, which we amortize over the life of Tres Palacios’ sublease agreement. We recorded amortization of the excess basis in our PRBIC equity investment of approximately $0.6 million and $1.6 million for the years ended December 31, 2017 and 2016, which we amortize over the life of PRBIC’s property, plant and equipment and its agreement with Chesapeake.

Financial Position Data

	December 31,
	2017										2016
	Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity		Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity
Stagecoach(1)	$	55.1	$	1,765.4	$	7.0	$	1.4	$	1,812.1	$	57.0	$	1,807.6	$	6.0	$	4.1	$	1,854.5
Other(2)(3)	81.3		801.1		53.4		93.6		735.4		50.4		708.5		23.2		74.4		661.3
Total	$	136.4	$	2,566.5	$	60.4	$	95.0	$	2,547.5	$	107.4	$	2,516.1	$	29.2	$	78.5	$	2,515.8

(1) As of December 31, 2017, our equity in the underlying net assets of Stagecoach Gas exceeded our investment balance by approximately $51.4 million. This excess amount is entirely attributable to goodwill and, as such, is not subject to amortization. Our Stagecoach Gas investment is included in our storage and transportation segment.

(2) Includes our Jackalope, Tres Holdings, PRBIC and Crestwood Permian investments. As of December 31, 2017, our equity in the underlying net assets of Jackalope, Tres Holdings, PRBIC and Crestwood Permian exceeded our investment balance by approximately $0.7 million, $26.5 million, $6.4 million and $11.6 million, respectively. Our Tres Holdings and PRBIC investments are included in our storage and transportation segment and our Jackalope and Crestwood Permian investments are included in our gathering and processing segment.

(3) On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico. This contribution was treated as a transaction between entities under common control (because of our relationship with First Reserve) and the accounting standards related to such transactions requires Crestwood Permian to record the assets and liabilities of Crestwood New Mexico at our historical book value. The difference between our equity in Crestwood New Mexico’s net assets and our investment balance is not subject to amortization.

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
	December 31,			December 31,					Year Ended December 31,
	2017			2017		2016			2017		2016				2015
Stagecoach Gas Services LLC	50.00	%		$	849.8	$	871.0		$	25.3	$	15.9			$	—
Jackalope Gas Gathering Services, L.L.C.	50.00	%	(1)	184.9		197.2			10.5		20.8				(43.4		)	(3)
Crestwood Permian Basin Holdings LLC	50.00	%		102.0		(0.5		)	8.4		(0.5		)		—
Tres Palacios Holdings LLC	50.01	%		37.8		39.0			2.2		(0.3		)		2.5
Powder River Basin Industrial Complex, LLC(2)	50.01	%		8.5		8.7			1.4		(4.4		)	(3)	(19.9		)	(3)
Total				$	1,183.0	$	1,115.4		$	47.8	$	31.5			$	(60.8	)

(1) Excludes non-controlling interest related to our investment in Jackalope. See Note 12 for a further discussion of our non-controlling interest related to our investment in Jackalope.

(2) During the year ended December 31, 2015, we recorded additional equity earnings of approximately $3.2 million related to a gain associated with the adjustment of our member’s capital account by our equity investee.

(3) During the year ended December 31, 2016, we recorded a reduction of our equity earnings from PRBIC of approximately $5.8 million related to impairments recorded by our equity investee. During the year ended December 31, 2015, we recorded impairments of our PRBIC and Jackalope equity investments of approximately $23.4 million and $51.4 million. For a further discussion of these impairments, see Note 2.

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Risk Management (Tables)

12 Months Ended

Dec. 31, 2017

Risk Management - Notional Amounts and Terms of Companys Derivative Financial Instruments [Abstract]

Notional Amounts And Terms Of Company's Derivative Financial Instruments

The notional amounts and terms of our derivative financial instruments include the following:

	December 31, 2017		December 31, 2016
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (MMBbls)	15.3	17.5	13.1	15.1
Natural gas (MMcf)	780	660	—	—

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2017

Fair Value, Assets, Liabilities and Stockholders' Equity Measured on Recurring Basis [Abstract]

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

The following table reflects the carrying value (reduced for deferred financing costs associated with the respective notes) and fair value of our senior notes (in millions):

	December 31, 2017				December 31, 2016
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2020 Senior Notes	$	—	$	—	$	340.6	$	350.2
2022 Senior Notes	$	—	$	—	$	429.3	$	447.3
2023 Senior Notes	$	692.1	$	728.8	$	690.6	$	722.6
2025 Senior Notes	$	492.3	$	517.9	$	—	$	—

Assets And Liabilities Measured At Fair Value On Recurring Basis

The following tables set forth by level within the fair value hierarchy, our financial instruments that were accounted for at fair value on a recurring basis at December 31, 2017 and 2016 (in millions):

	December 31, 2017
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Recorded in Balance Sheet
Assets
Assets from price risk management	$	1.1	$	102.2	$	—	$	103.3	$	(74.6	)	$	(21.5	)	$	7.2
Suburban Propane Partners, L.P. units(2)	3.5		—		—		3.5		—			—			3.5
Total assets at fair value	$	4.6	$	102.2	$	—	$	106.8	$	(74.6	)	$	(21.5	)	$	10.7
Liabilities
Liabilities from price risk management	$	1.4	$	118.2	$	—	$	119.6	$	(74.6	)	$	3.9		$	48.9
Total liabilities at fair value	$	1.4	$	118.2	$	—	$	119.6	$	(74.6	)	$	3.9		$	48.9
	December 31, 2016
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Recorded in Balance Sheet
Assets
Assets from price risk management	$	0.6	$	84.4	$	—	$	85.0	$	(67.8	)	$	(10.9	)	$	6.3
Suburban Propane Partners, L.P. units(2)	4.3		—		—		4.3		—			—			4.3
Total assets at fair value	$	4.9	$	84.4	$	—	$	89.3	$	(67.8	)	$	(10.9	)	$	10.6
Liabilities
Liabilities from price risk management	$	2.7	$	90.2	$	—	$	92.9	$	(67.8	)	$	3.5		$	28.6
Total liabilities at fair value	$	2.7	$	90.2	$	—	$	92.9	$	(67.8	)	$	3.5		$	28.6

(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) Amount is reflected in other assets on CEQP’s consolidated balance sheets.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2017

Text Block [Abstract]

Components Of Long-Term Debt

Long-term debt consisted of the following at December 31, 2017 and 2016, (in millions):

	December 31,
	2017		2016
Credit Facility	$	318.2	$	77.0
2020 Senior Notes	—		338.8
Fair value adjustment of 2020 Senior Notes	—		1.8
2022 Senior Notes	—		436.4
2023 Senior Notes	700.0		700.0
2025 Senior Notes	500.0		—
Other	2.4		3.7
Less: deferred financing costs, net	28.4		34.0
Total debt	1,492.2		1,523.7
Less: current portion	0.9		1.0
Total long-term debt, less current portion	$	1,491.3	$	1,522.7

Schedule of Maturities of Long-term Debt

The aggregate maturities of principal amounts on our outstanding long-term debt and other notes payable as of December 31, 2017 for the next five years and in total thereafter are as follows (in millions):

2018	$	0.9
2019	0.9
2020	318.4
2021	0.2
2022	0.2
Thereafter	1,200.0
Total debt	$	1,520.6

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2017

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The (provision) benefit for income taxes for the years ended December 31, 2017, 2016, and 2015 consisted of the following (in millions):

	CEQP									CMLP
	Year Ended December 31,									Year Ended December 31,
	2017			2016			2015			2017 (1)		2016			2015
Current:
Federal	$	(1.1	)	$	(3.2	)	$	(1.6	)	$	—	$	—		$	—
State	(0.2		)	(0.2		)	(0.6		)	—		0.2			(0.3		)
Total current	(1.3		)	(3.4		)	(2.2		)	—		0.2			(0.3		)
Deferred:
Federal	2.1			3.0			2.9			—		—			—
State	—			0.1			0.7			—		(0.2		)	0.3
Total deferred	2.1			3.1			3.6			—		(0.2		)	0.3
(Provision) benefit for income taxes	$	0.8		$	(0.3	)	$	1.4		$	—	$	—		$	—

(1) For the year ended December 31, 2017, our benefit for income taxes was not material to CMLP’s consolidated statement of operations.

Schedule of Deferred Tax Assets and Liabilities

Components of our deferred income taxes at December 31, 2017 and 2016 are as follows (in millions).

	CEQP						CMLP
	December 31,						December 31,
	2017			2016			2017			2016
Deferred tax asset:
Basis difference in stock of company	$	0.2		$	0.2		$	—		$	—
Total deferred tax asset	0.2			0.2			—			—
Deferred tax liability:
Basis difference in stock of acquired company	(3.5		)	(5.5		)	(0.7		)	(0.7		)
Total deferred tax liability	(3.5		)	(5.5		)	(0.7		)	(0.7		)
Net deferred tax liability	$	(3.3	)	$	(5.3	)	$	(0.7	)	$	(0.7	)

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Partners' Capital (Tables)

12 Months Ended

Dec. 31, 2017

Distribution Made to Limited Liability Company (LLC) Member [Line Items]

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

A summary of CEQP’s limited partner quarterly cash distributions for the years ended December 31, 2017, 2016 and 2015 is presented below:

Record Date	Payment Date	Per Unit Rate		Cash Distributions  (in millions)
2017
February 7, 2017	February 14, 2017	$	0.60	$	41.8
May 8, 2017	May 15, 2017	$	0.60	41.8
August 7, 2017	August 14, 2017	$	0.60	41.8
November 7, 2017	November 14, 2017	$	0.60	42.2
				$	167.6
2016
February 5, 2016	February 12, 2016	$	1.375	$	95.6
May 6, 2016	May 13, 2016	$	0.60	41.4
August 5, 2016	August 12, 2016	$	0.60	41.4
November 7, 2016	November 14, 2016	$	0.60	41.4
				$	219.8
2015
February 6, 2015	February 13, 2015	$	1.375	$	25.8
May 8, 2015	May 15, 2015	$	1.375	25.7
August 7, 2015	August 14, 2015	$	1.375	25.7
November 6, 2015	November 13, 2015	$	1.375	94.3
				$	171.5

Schedule of Limited Partners' Capital Account by Class

The components of net income (loss) attributable to non-controlling partners for the years ended December 31, 2017, 2016 and 2015 are as follows (in millions):

	Year Ended December 31,
	2017		2016		2015
Crestwood Niobrara preferred interests	$	25.3	$	24.2	$	23.1
CMLP net income attributable to non-controlling partners	25.3		24.2		23.1
Crestwood Midstream limited partner interests	—		—		(683.0		)
Crestwood Midstream Class A preferred units	—		—		23.1
CEQP net income (loss) attributable to non-controlling partners	$	25.3	$	24.2	$	(636.8	)

CMLP

Distribution Made to Limited Liability Company (LLC) Member [Line Items]

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

Record Date	Payment Date	Per Unit Rate		Cash Distributions (in millions)
2015
February 6, 2015	February 13, 2015	$	0.41	$	74.3
May 8, 2015	May 15, 2015	$	0.41	74.3
August 7, 2015	August 14, 2015	$	0.41	74.3
				$	222.9

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Partners' Capital Schedule of Issuance of Units (Tables)

12 Months Ended

Dec. 31, 2017

Schedule of Issuance of Units [Abstract]

Schedule Of Issuances And Net Proceeds Of Common Units [Table Text Block]

The table below shows the units issued and the net proceeds from the issuances:

Issuance Dates	Common Units	Net Proceeds(1) (in millions)
Third Quarter 2017	437,518	$	10.6
Fourth Quarter 2017	195,753	4.6
Total 2017	633,271	$	15.2

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Equity Plans (Tables)

12 Months Ended

Dec. 31, 2017

Equity [Abstract]

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

The following table summarizes information regarding restricted and phantom unit activity during the years ended December 31, 2017, 2016 and 2015.

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2015	131,588		$	132.10
Vested - restricted units	(91,798	)	$	121.13
Vested - phantom units	(4,856	)	$	67.10
Granted - restricted units	142,255		$	55.25
Granted - phantom units	42,349		$	62.31
Modification - restricted units	226,401		$	68.85
Modification - phantom units	41,269		$	58.36
Forfeited (1)	(20,994	)	$	89.97
Unvested - December 31, 2015	466,214		$	69.80
Vested - restricted units	(193,295	)	$	76.82
Granted - restricted units	1,067,535		$	14.58
Granted - phantom units	17,467		$	15.54
Forfeited	(65,591	)	$	25.13
Unvested - December 31, 2016	1,292,330		$	24.67
Vested - restricted units	(607,115	)	$	28.00
Vested - performance units	(31,106	)	$	30.27
Granted - restricted units	919,411		$	25.69
Granted - phantom units	15,849		$	25.02
Granted - performance units	405,620		$	30.21
Forfeited - restricted units	(140,137	)	$	23.73
Forfeited - performance units	(24,756	)	$	30.45
Unvested - December 31, 2017	1,830,096		$	25.21

(1) We implemented a company-wide initiative to reduce operating costs in 2015 and beyond, which included a reduction in workforce. As a result, 7,263 restricted units were forfeited during the year ended December 31, 2015.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2017

Commitments and Contingencies Disclosure [Abstract]

Schedule of Future Minimum Rental Payments for Operating Leases

Future minimum lease payments under our noncancelable operating leases for the next five years ending December 31 and in total thereafter consist of the following (in millions):

Year Ending December 31,
2018	$	35.2
2019	30.1
2020	23.2
2021	11.5
2022	7.7
Thereafter	18.8
Total minimum lease payments	$	126.5

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2017

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following table shows revenues, costs of product/services sold, general and administrative expenses and reimbursement of expenses from our affiliates for the years December 31, 2017, 2016 and 2015 (in millions):

	Year Ended December 31,
	2017			2016			2015
Gathering and processing revenues at CEQP and CMLP	$	1.8		$	2.6		$	3.9
Gathering and processing costs of product sold at CEQP and CMLP(1)	$	15.3		$	17.7		$	28.9
Operations and maintenance expenses charged at CEQP and CMLP(2)	$	22.3		$	8.1		$	3.3
General and administrative expenses charged by CEQP to CMLP, net(3)	$	19.4		$	13.0		$	49.5
General and administrative expenses at CEQP charged to (from) Crestwood Holdings, net(4)	$	(1.7	)	$	(2.2	)	$	0.4

(1)    Represents natural gas purchases from Sabine Oil and Gas, an affiliate of Crestwood Holdings.

(2) We have operating agreements with certain of our unconsolidated affiliates pursuant to which we charge them operations and maintenance expenses in accordance with their respective agreements. During the year ended December 31, 2017, we charged $8.4 million to Stagecoach Gas, $3.5 million to Tres Palacios, $10.0 million to Crestwood Permian and $0.4 million to Jackalope. During the year ended December 31, 2016, we charged $5.0 million to Stagecoach Gas, $2.7 million to Tres Palacios, and $0.4 million to Jackalope. During the year ended December 31, 2015, we charged $2.8 million to Tres Palacios and $0.5 million to Jackalope.

(3) Includes $22.4 million, $16.0 million and $10.0 million of net unit-based compensation charges allocated from CEQP to CMLP for the years ended December 31, 2017, 2016 and 2015. In addition, includes $3.0 million, $3.0 million and $0.8 million of CMLP’s general and administrative costs allocated to CEQP during the years ended December 31, 2017, 2016 and 2015.

(4) Includes $3.1 million, $3.2 million and $0.1 million unit-based compensation charges allocated from Crestwood Holdings to CEQP and CMLP during the years ended December 31, 2017, 2016 and 2015.

Schedule of Related Party Receivables and Payables

The following table shows accounts receivable and accounts payable from our affiliates as of December 31, 2017 and 2016 (in millions):

	December 31,
	2017		2016
Accounts receivable at CEQP and CMLP	$	7.1	$	5.6
Accounts payable at CEQP	$	7.4	$	2.5
Accounts payable at CMLP	$	5.0	$	—

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Segments (Tables)

12 Months Ended

Dec. 31, 2017

Segment Reporting Information [Line Items]

Reportable Segments

Below is a reconciliation of CEQP’s net loss to EBITDA (in millions):

	Year Ended December 31,
	2017			2016			2015
Net loss	$	(166.6	)	$	(192.1	)	$	(2,303.7	)
Add:
Interest and debt expense, net	99.4			125.1			140.1
(Gain) loss on modification/extinguishment of debt	37.7			(10.0		)	20.0
Provision (benefit) for income taxes	(0.8		)	0.3			(1.4		)
Depreciation, amortization and accretion	191.7			229.6			300.1
EBITDA	$	161.4		$	152.9		$	(1,844.9	)

Below is a reconciliation of CMLP’s net loss to EBITDA (in millions):

	Year Ended December 31,
	2017			2016			2015
Net loss	$	(175.5	)	$	(197.5	)	$	(1,410.6	)
Add:
Interest and debt expense, net	99.4			125.1			130.5
(Gain) loss on modification/extinguishment of debt	37.7			(10.0		)	18.9
Depreciation, amortization and accretion	202.7			240.5			278.5
EBITDA	$	164.3		$	158.1		$	(982.7	)

The following tables summarize CEQP’s and CMLP’s reportable segment data for the years ended December 31, 2017, 2016 and 2015 (in millions). Intersegment revenues included in the following tables are accounted for as arms-length transactions that apply our revenue recognition policies described in Note 2. Included in earnings (loss) from unconsolidated affiliates below was approximately $32.5 million, $29.6 million and $86.1 million of depreciation and amortization expense and gains (losses) on long-lived assets, net related to our equity investments for the years ended December 31, 2017, 2016 and 2015, respectively.

Crestwood Equity

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			96.5			96.5
Loss on long-lived assets, net	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			0.5			1.3
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(99.0	)	$	161.4
Goodwill	$	45.9		$	—		$	101.7		$	—		$	147.6
Total assets	$	2,474.1		$	1,040.6		$	757.1		$	13.1		$	4,284.9
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

	Year Ended December 31, 2016
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,118.8		$	165.3		$	1,236.4		$	—		$	2,520.5
Intersegment revenues	108.6			4.2			(112.8		)	—			—
Costs of product/services sold	917.0			5.1			1,003.0			—			1,925.1
Operations and maintenance expense	77.0			21.4			59.7			—			158.1
General and administrative expense	—			—			—			88.2			88.2
Loss on long-lived assets, net	(2.0		)	(32.2		)	(31.4		)	—			(65.6		)
Goodwill impairment	(8.6		)	(44.9		)	(109.1		)	—			(162.6		)
Earnings from unconsolidated affiliates, net	20.3			11.2			—			—			31.5
Other income, net	—			—			—			0.5			0.5
EBITDA	$	243.1		$	77.1		$	(79.6	)	$	(87.7	)	$	152.9
Goodwill	$	45.9		$	—		$	153.1		$	—		$	199.0
Total assets	$	2,359.7		$	1,094.6		$	972.2		$	22.4		$	4,448.9
Purchases of property, plant and equipment	$	76.6		$	3.3		$	19.1		$	1.7		$	100.7

	Year Ended December 31, 2015
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,381.0		$	266.3		$	985.5		$	—		$	2,632.8
Intersegment revenues	66.7			—			(66.7		)	—			—
Costs of product/services sold	1,103.9			20.1			759.5			—			1,883.5
Operations and maintenance expense	89.0			31.7			69.5			—			190.2
General and administrative expense	—			—			—			116.3			116.3
Loss on long-lived assets	(787.3		)	(1.6		)	(32.3		)	—			(821.2		)
Goodwill impairment	(329.7		)	(623.4		)	(453.2		)	—			(1,406.3		)
Loss from unconsolidated affiliates, net	(43.4		)	(17.4		)	—			—			(60.8		)
Other income, net	—			—			—			0.6			0.6
EBITDA	$	(905.6	)	$	(427.9	)	$	(395.7	)	$	(115.7	)	$	(1,844.9	)
Purchases of property, plant and equipment	$	132.7		$	26.4		$	22.8		$	0.8		$	182.7

CMLP

Segment Reporting Information [Line Items]

Reportable Segments

Crestwood Midstream

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			93.1			93.1
Loss on long-lived assets, net	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			—			0.8
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(96.1	)	$	164.3
Goodwill	$	45.9		$	—		$	101.7		$	—		$	147.6
Total assets	$	2,662.0		$	1,040.6		$	757.1		$	6.6		$	4,466.3
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

	Year Ended December 31, 2016
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,118.8		$	165.3		$	1,236.4		$	—		$	2,520.5
Intersegment revenues	108.6			4.2			(112.8		)	—			—
Costs of product/services sold	917.0			5.1			1,003.0			—			1,925.1
Operations and maintenance expense	77.0			18.3			59.7			—			155.0
General and administrative expense	—			—			—			85.6			85.6
Loss on long-lived assets, net	(2.0		)	(32.2		)	(31.4		)	—			(65.6		)
Goodwill impairment	(8.6		)	(44.9		)	(109.1		)	—			(162.6		)
Earnings from unconsolidated affiliates, net	20.3			11.2			—			—			31.5
EBITDA	$	243.1		$	80.2		$	(79.6	)	$	(85.6	)	$	158.1
Goodwill	$	45.9		$	—		$	153.1		$	—		$	199.0
Total assets	$	2,561.9		$	1,094.6		$	972.2		$	11.9		$	4,640.6
Purchases of property, plant and equipment	$	76.6		$	3.3		$	19.1		$	1.7		$	100.7

	Year Ended December 31, 2015
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,381.0		$	266.3		$	985.5		$	—		$	2,632.8
Intersegment revenues	66.7			—			(66.7		)	—			—
Costs of product/services sold	1,103.9			20.1			759.5			—			1,883.5
Operations and maintenance expense	89.0			30.2			69.5			—			188.7
General and administrative expense	—			—			—			105.6			105.6
Loss on long-lived assets, net	(194.1		)	(1.4		)	(32.3		)	—			(227.8		)
Goodwill impairment	(72.5		)	(623.4		)	(453.2		)	—			(1,149.1		)
Loss from unconsolidated affiliates, net	(43.4		)	(17.4		)	—			—			(60.8		)
EBITDA	$	(55.2	)	$	(426.2	)	$	(395.7	)	$	(105.6	)	$	(982.7	)
Purchases of property, plant and equipment	$	132.7		$	26.4		$	22.8		$	0.8		$	182.7

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Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2017

Condensed Financial Information of Parent Company Only Disclosure [Abstract]

Condensed Consolidating Balance Sheet

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2017
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	1.0	$	—	$	—	$	—		$	1.0
Accounts receivable	—		439.7		2.9		—			442.6
Inventory	—		68.4		—		—			68.4
Other current assets	—		18.1		—		—			18.1
Total current assets	1.0		526.2		2.9		—			530.1
Property, plant and equipment, net	—		2,007.5		—		—			2,007.5
Goodwill and intangible assets, net	—		743.3		—		—			743.3
Investments in consolidated affiliates	3,705.4		—		—		(3,705.4		)	—
Investments in unconsolidated affiliates	—		—		1,183.0		—			1,183.0
Other assets	—		2.4		—		—			2.4
Total assets	$	3,706.4	$	3,279.4	$	1,185.9	$	(3,705.4	)	$	4,466.3
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	—	$	346.8	$	—	$	—		$	346.8
Other current liabilities	20.5		134.0		—		—			154.5
Total current liabilities	20.5		480.8		—		—			501.3
Long-term liabilities:
Long-term debt, less current portion	1,490.5		0.8		—		—			1,491.3
Other long-term liabilities	—		45.6		57.0		—			102.6
Deferred income taxes	—		0.7		—		—			0.7
Partners’ capital	2,195.4		2,751.5		953.9		(3,705.4		)	2,195.4
Interest of non-controlling partners in subsidiary	—		—		175.0		—			175.0
Total partners’ capital	2,195.4		2,751.5		1,128.9		(3,705.4		)	2,370.4
Total liabilities and partners’ capital	$	3,706.4	$	3,279.4	$	1,185.9	$	(3,705.4	)	$	4,466.3

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2016
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	1.3	$	—	$	—	$	—		$	1.3
Accounts receivable	—		289.3		0.5		—			289.8
Inventory	—		66.0		—		—			66.0
Other current assets	—		16.0		—		—			16.0
Total current assets	1.3		371.3		0.5		—			373.1
Property, plant and equipment, net	—		2,298.4		—		—			2,298.4
Goodwill and intangible assets, net	—		851.9		—		—			851.9
Investments in consolidated affiliates	4,093.7		—		—		(4,093.7		)	—
Investments in unconsolidated affiliates	—		—		1,115.4		—			1,115.4
Other assets	—		1.8		—		—			1.8
Total assets	$	4,095.0	$	3,523.4	$	1,115.9	$	(4,093.7	)	$	4,640.6
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	—	$	214.5	$	—	$	—		$	214.5
Other current liabilities	23.1		94.4		—		—			117.5
Total current liabilities	23.1		308.9		—		—			332.0
Long-term liabilities:
Long-term debt, less current portion	1,521.2		1.5		—		—			1,522.7
Other long-term liabilities	—		42.0		—		—			42.0
Deferred income taxes	—		0.7		—		—			0.7
Partners’ capital	2,550.7		3,170.3		923.4		(4,093.7		)	2,550.7
Interest of non-controlling partners in subsidiary	—		—		192.5		—			192.5
Total partners’ capital	2,550.7		3,170.3		1,115.9		(4,093.7		)	2,743.2
Total liabilities and partners’ capital	$	4,095.0	$	3,523.4	$	1,115.9	$	(4,093.7	)	$	4,640.6

Condensed Consolidating Statements of Operations

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,880.9		$	—		$	—		$	3,880.9
Costs of product/services sold	—			3,374.7			—			—			3,374.7
Expenses:
Operations and maintenance	—			136.0			—			—			136.0
General and administrative	67.6			25.5			—			—			93.1
Depreciation, amortization and accretion	—			202.7			—			—			202.7
	67.6			364.2			—			—			431.8
Other operating expenses:
Gain on long-lived assets, net	—			(65.6		)	—			—			(65.6		)
Goodwill impairment	—			(38.8		)	—			—			(38.8		)
Loss on contingent consideration	—			—			(57.0		)	—			(57.0		)
Operating income (loss)	(67.6		)	37.6			(57.0		)	—			(87.0		)
Earnings from unconsolidated affiliates, net	—			—			47.8			—			47.8
Interest and debt expense, net	(99.4		)	—			—			—			(99.4		)
Loss on modification/extinguishment of debt	(37.7		)	—			—			—			(37.7		)
Other income, net	—			0.8			—			—			0.8
Equity in net income (loss) of subsidiaries	3.9			—			—			(3.9		)	—
Net income (loss)	(200.8		)	38.4			(9.2		)	(3.9		)	(175.5		)
Net income attributable to non-controlling partners	—			—			25.3			—			25.3
Net income (loss) attributable to Crestwood Midstream Partners LP	$	(200.8	)	$	38.4		$	(34.5	)	$	(3.9	)	$	(200.8	)

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2016
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries		Eliminations		Consolidated
Revenues	$	—		$	2,520.5		$	—	$	—	$	2,520.5
Costs of product/services sold	—			1,925.1			—		—		1,925.1
Expenses:
Operations and maintenance	—			155.0			—		—		155.0
General and administrative	66.4			19.2			—		—		85.6
Depreciation, amortization and accretion	—			240.5			—		—		240.5
	66.4			414.7			—		—		481.1
Other operating expenses:
Loss on long-lived assets, net	—			(65.6		)	—		—		(65.6		)
Goodwill impairment	—			(162.6		)	—		—		(162.6		)
Operating loss	(66.4		)	(47.5		)	—		—		(113.9		)
Earnings from unconsolidated affiliates, net	—			—			31.5		—		31.5
Interest and debt expense, net	(125.1		)	—			—		—		(125.1		)
Gain on modification/extinguishment of debt	10.0			—			—		—		10.0
Equity in net income (loss) of subsidiaries	(40.2		)	—			—		40.2		—
Net income (loss)	(221.7		)	(47.5		)	31.5		40.2		(197.5		)
Net income attributable to non-controlling partners	—			—			24.2		—		24.2
Net income (loss) attributable to Crestwood Midstream Partners LP	$	(221.7	)	$	(47.5	)	$	7.3	$	40.2	$	(221.7	)

Crestwood Midstream Partners
Condensed Consolidating Statements of Operations
Year Ended December 31, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Revenues	$	—		$	2,632.8		$	—		$	—	$	2,632.8
Costs of product/services sold	—			1,883.5			—			—		1,883.5
Expenses:
Operations and maintenance	—			188.7			—			—		188.7
General and administrative	65.3			40.3			—			—		105.6
Depreciation, amortization and accretion	—			278.5			—			—		278.5
	65.3			507.5			—			—		572.8
Other operating expenses:
Loss on long-lived assets, net	—			(227.8		)	—			—		(227.8		)
Goodwill impairment	—			(1,149.1		)	—			—		(1,149.1		)
Operating loss	(65.3		)	(1,135.1		)	—			—		(1,200.4		)
Loss from unconsolidated affiliates, net	—			—			(60.8		)	—		(60.8		)
Interest and debt expense, net	(130.5		)	—			—			—		(130.5		)
Loss on modification/extinguishment of debt	(18.9		)	—			—			—		(18.9		)
Equity in net income (loss) of subsidiaries	(1,219.0		)	—			—			1,219.0		—
Net income (loss)	(1,433.7		)	(1,135.1		)	(60.8		)	1,219.0		(1,410.6		)
Net income attributable to non-controlling partners	—			—			23.1			—		23.1
Net income (loss) attributable to Crestwood Midstream Partners LP	(1,433.7		)	(1,135.1		)	(83.9		)	1,219.0		(1,433.7		)
Net income attributable to Class A preferred units	23.1			—			—			—		23.1
Net income (loss) attributable to partners	$	(1,456.8	)	$	(1,135.1	)	$	(83.9	)	$	1,219.0	$	(1,456.8	)

Condensed Consolidating Statements of Cash Flows

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(162.3	)	$	379.2		$	45.3		$	—		$	262.2
Cash flows from investing activities:
Purchases of property, plant and equipment	(6.7		)	(181.7		)	—			—			(188.4		)
Investment in unconsolidated affiliates	—			—			(58.0		)	—			(58.0		)
Capital distributions from unconsolidated affiliates	—			—			59.9			—			59.9
Net proceeds from sale of assets	—			225.2			—			—			225.2
Capital distributions from consolidated affiliates	4.3			—			—			(4.3		)	—
Net cash provided by (used in) investing activities	(2.4		)	43.5			1.9			(4.3		)	38.7
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,838.6			—			—			—			2,838.6
Payments on long-term debt	(2,912.6		)	(1.3		)	—			—			(2,913.9		)
Payments on capital leases	—			(2.7		)	—			—			(2.7		)
Payments for debt-related deferred costs	(1.0		)	—			—			—			(1.0		)
Redemption of non-controlling interest	—			—			(202.7		)	—			(202.7		)
Net proceeds from issuance of non-controlling interest	—			—			175.0			—			175.0
Distributions to partners	(174.0		)	—			(15.2		)	—			(189.2		)
Distributions to parent	—			—			(4.3		)	4.3			—
Taxes paid for unit-based compensation vesting	—			(5.5		)	—			—			(5.5		)
Change in intercompany balances	413.4			(413.4		)	—			—			—
Other	—			0.2			—			—			0.2
Net cash provided by (used in) financing activities	164.4			(422.7		)	(47.2		)	4.3			(301.2		)
Net change in cash	(0.3		)	—			—			—			(0.3		)
Cash at beginning of period	1.3			—			—			—			1.3
Cash at end of period	$	1.0		$	—		$	—		$	—		$	1.0

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2016
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(188.0	)	$	502.8		$	39.0		$	—		$	353.8
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(7.2		)	—			—			(7.2		)
Purchases of property, plant and equipment	(1.7		)	(99.0		)	—			—			(100.7		)
Investment in unconsolidated affiliates	—			—			(12.4		)	—			(12.4		)
Capital distributions from unconsolidated affiliates	—			—			14.8			—			14.8
Net proceeds from sale of assets	—			972.7			—			—			972.7
Capital distributions from consolidated affiliates	26.2			—			—			(26.2		)	—
Net cash provided by (used in) investing activities	24.5			866.5			2.4			(26.2		)	867.2
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	1,565.3			—			—			—			1,565.3
Payments on long-term debt	(2,535.3		)	(0.8		)	—			—			(2,536.1		)
Payments on capital leases	—			(1.9		)	—			—			(1.9		)
Payments for debt-related deferred costs	(3.5		)	—			—			—			(3.5		)
Distributions to partners	(227.6		)	—			(15.2		)	—			(242.8		)
Distributions to parent	—			—			(26.2		)	26.2			—
Taxes paid for unit-based compensation vesting	—			(0.8		)	—			—			(0.8		)
Change in intercompany balances	1,365.8			(1,365.8		)	—			—			—
Net cash provided by (used in) financing activities	164.7			(1,369.3		)	(41.4		)	26.2			(1,219.8		)
Net change in cash	1.2			—			—			—			1.2
Cash at beginning of period	0.1			—			—			—			0.1
Cash at end of period	$	1.3		$	—		$	—		$	—		$	1.3

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2015
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(190.8	)	$	650.0		$	12.6		$	—		$	471.8
Cash flows from investing activities:
Purchases of property, plant and equipment	(0.8		)	(181.9		)	—			—			(182.7		)
Investment in unconsolidated affiliates	—			—			(41.8		)	—			(41.8		)
Capital distributions from unconsolidated affiliates	—			—			9.3			—			9.3
Net proceeds from sale of assets	—			2.7			—			—			2.7
Capital contributions to consolidated affiliates	(31.2		)	—			—			31.2			—
Net cash provided by (used in) investing activities	(32.0		)	(179.2		)	(32.5		)	31.2			(212.5		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	3,490.1			—			—			—			3,490.1
Payments on long-term debt	(2,960.9		)	—			—			—			(2,960.9		)
Payments on capital leases	—			(2.2		)	—			—			(2.2		)
Payments for debt-related deferred costs	(17.3		)	—			—			—			(17.3		)
Financing fees paid for early debt redemption	(13.6		)	—			—			—			(13.6		)
Distributions to partners	(808.2		)	—			(11.3		)	—			(819.5		)
Contributions from parent	—			—			31.2			(31.2		)	—
Net proceeds from issuance of preferred units	58.8			—			—			—			58.8
Taxes paid for unit-based compensation vesting	—			(2.1		)	—			—			(2.1		)
Change in intercompany balances	474.1			(474.1		)	—			—			—
Other	(0.1		)	—			—			—			(0.1		)
Net cash provided by (used in) financing activities	222.9			(478.4		)	19.9			(31.2		)	(266.8		)
Net change in cash	0.1			(7.6		)	—			—			(7.5		)
Cash at beginning of period	—			7.6			—			—			7.6
Cash at end of period	$	0.1		$	—		$	—		$	—		$	0.1

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Organization and Description of Business (Narrative) (Detail) - 12 months ended Dec. 31, 2017	Total	segment	reporting_units
Partnership Organization And Basis Of Presentation [Line Items]
Number of operating segments		3	3
Crestwood Equity Partners LP
Partnership Organization And Basis Of Presentation [Line Items]
Limited partnership interest	99.90%
Crestwood Gas Services GP, LLC [Member]
Partnership Organization And Basis Of Presentation [Line Items]
Limited partnership interest	0.10%
Common Unit Capital | Crestwood Holdings
Partnership Organization And Basis Of Presentation [Line Items]
General partner ownership percentage	25.00%

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Basis of Presentation and Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions				12 Months Ended
	Jan. 01, 2018	Jun. 21, 2017	Jun. 03, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Summary Of Significant Accounting Policies [Line Items]
Assets Held-for-sale, Not Part of Disposal Group				$ 3.0
Loss on long-lived assets, net				(65.6)	$ (65.6)	$ (821.2)
Inventory				68.4	66.0
Estimated Cost to Build				180.0
Contribution of Property		$ 69.0
Net proceeds from sale of assets				225.2	972.7	$ 2.7
Debt Issuance Costs, Net				28.4	34.0
Property, plant and equipment				2,285.2	2,555.4
Deferred revenue				$ 0.6	$ 7.5
Percentage of gross income from qualifying sources required to be subject to federal income tax, minimum				90.00%
Discount rate				12.00%	19.00%	15.00%
Increase (Decrease) in Intangible Assets, Current					$ 8.5
Goodwill impairment				$ 38.8	162.6	$ 1,406.3
Increase (Decrease) in Other Current Assets and Liabilities, Net					11.2
West Coast
Summary Of Significant Accounting Policies [Line Items]
Goodwill, Acquired During Period				2.4
Impaired assets to be disposed of				81.4
Fair value disclosure				66.4
Impairment of intangible assets				0.8
Goodwill impairment				2.4	0.0	85.9
Granite Wash
Summary Of Significant Accounting Policies [Line Items]
Impaired assets to be disposed of						8.5
Barnett
Summary Of Significant Accounting Policies [Line Items]
Impaired assets to be disposed of						354.4
Impairment of intangible assets						238.9
Goodwill impairment				0.0	0.0	257.2
Fayetteville
Summary Of Significant Accounting Policies [Line Items]
Impaired assets to be disposed of						61.9
Impairment of intangible assets						70.9
Goodwill impairment				0.0	0.0	72.5
Haynesville
Summary Of Significant Accounting Policies [Line Items]
Impaired assets to be disposed of						45.7
Impairment of intangible assets						6.0
Marcellus
Summary Of Significant Accounting Policies [Line Items]
Loss on long-lived assets, net				2.5
Goodwill impairment				0.0	8.6	0.0
Watkins Glen
Summary Of Significant Accounting Policies [Line Items]
Impaired assets to be disposed of						31.2
Trucking
Summary Of Significant Accounting Policies [Line Items]
Impairment of intangible assets					31.4
Goodwill impairment				0.0	29.5	148.4
Natural Gas Liquids
Summary Of Significant Accounting Policies [Line Items]
Inventory				67.9	56.7
CMLP
Summary Of Significant Accounting Policies [Line Items]
Loss on long-lived assets, net				(65.6)	(65.6)	(227.8)
Inventory				68.4	66.0
Net proceeds from sale of assets				225.2	972.7	2.7
Property, plant and equipment				2,615.3	2,885.5
Deferred revenue				0.6	7.5
Goodwill impairment				38.8	162.6	1,149.1
Goodwill, Impaired, Accumulated Impairment Loss				1,399.3
Crestwood Equity Partners LP
Summary Of Significant Accounting Policies [Line Items]
Property, plant and equipment				2,285.2	2,555.4
Goodwill impairment				38.8	$ 162.6	1,406.3
Goodwill, Impaired, Accumulated Impairment Loss				$ 1,656.5
Jackalope Gas Gathering Services, LLC
Summary Of Significant Accounting Policies [Line Items]
Equity method investment, other than temporary impairment						51.4
Powder River Basin Industrial Complex, LLC
Summary Of Significant Accounting Policies [Line Items]
Equity method investment, other than temporary impairment						$ 23.4
Minimum
Summary Of Significant Accounting Policies [Line Items]
Discount rate				10.00%	10.00%	9.00%
Maximum
Summary Of Significant Accounting Policies [Line Items]
Discount rate				12.00%	19.00%	12.00%
Equity Method Investments [Member]
Summary Of Significant Accounting Policies [Line Items]
Discount rate						15.50%
Stagecoach Gas Services LLC
Summary Of Significant Accounting Policies [Line Items]
Net proceeds from sale of assets					$ 3.0
Equity method ownership percentage				50.00%
Property, Plant and Equipment, Gross, Period Increase (Decrease)					(1,127.6)
Stagecoach Gas Services LLC | CEGP
Summary Of Significant Accounting Policies [Line Items]
Net proceeds from sale of assets			$ 975.0		$ 975.0
Stagecoach Gas Services LLC | CMLP
Summary Of Significant Accounting Policies [Line Items]
Equity method ownership percentage			50.00%		50.00%
Subsequent Event
Summary Of Significant Accounting Policies [Line Items]
New Accounting Pronouncement Change in Balance Sheet Classification	$ 69.1
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 20.0

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Basis of Presentation and Summary of Significant Accounting Policies (Estimated Useful Lives Of Property, Plant And Equipment) (Detail)	12 Months Ended
	Dec. 31, 2017
Gathering systems and pipelines and related assets | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	15 years
Gathering systems and pipelines and related assets | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	20 years
Facilities and equipment | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	3 years
Facilities and equipment | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	25 years
Buildings, land, rights-of-way, storage rights and easements | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	1 year
Buildings, land, rights-of-way, storage rights and easements | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	40 years
Office furniture and fixtures | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Office furniture and fixtures | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	10 years
Vehicles | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Vehicles | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years

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Basis of Presentation and Summary of Significant Accounting Policies (Estimated Economic Lives Of Intangible Assets) (Detail)	12 Months Ended
	Dec. 31, 2017
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Weighted-Average Life (years)	20 years
Minimum | Trademarks
Finite-Lived Intangible Assets [Line Items]
Weighted-Average Life (years)	6 years
Maximum | Trademarks
Finite-Lived Intangible Assets [Line Items]
Weighted-Average Life (years)	8 years

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Basis of Presentation and Summary of Significant Accounting Policies (Goodwill, by Reporting Unit) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Goodwill [Roll Forward]
Beginning Balance		$ 199.0
Goodwill Impairments during the Period		38.8	$ 162.6	$ 1,406.3
Ending Balance	$ 199.0	147.6	199.0
Goodwill, Other Increase (Decrease)		(12.6)	(723.9)
Fayetteville
Goodwill [Line Items]
Impairment of intangible assets				70.9
Goodwill [Roll Forward]
Beginning Balance		0.0	0.0
Goodwill Impairments during the Period		0.0	0.0	72.5
Ending Balance	0.0	0.0	0.0	0.0
Marcellus
Goodwill [Roll Forward]
Beginning Balance		0.0	8.6
Goodwill Impairments during the Period		0.0	8.6	0.0
Ending Balance	0.0	0.0	0.0	8.6
Arrow
Goodwill [Roll Forward]
Beginning Balance		45.9	45.9
Goodwill Impairments during the Period		0.0	0.0	0.0
Ending Balance	45.9	45.9	45.9	45.9
Northeast Storage and Transportation
Goodwill [Roll Forward]
Beginning Balance		0.0	726.3
Goodwill Impairments during the Period		0.0	0.0	0.0
Goodwill, Written off Related to Sale of Business Unit		(726.3)
Ending Balance	0.0	0.0	0.0	726.3
COLT
Goodwill [Roll Forward]
Beginning Balance		0.0	44.9
Goodwill Impairments during the Period		0.0	44.9	623.4
Ending Balance	0.0	0.0	0.0	44.9
West Coast
Goodwill [Line Items]
Impairment of intangible assets		0.8
Goodwill [Roll Forward]
Beginning Balance		2.4	0.0
Goodwill Impairments during the Period		2.4	0.0	85.9
Goodwill, Acquired During Period		2.4
Ending Balance	2.4	0.0	2.4	0.0
Supply and Logistics
Goodwill [Roll Forward]
Beginning Balance		101.7	167.2
Goodwill Impairments during the Period		0.0	65.5	99.0
Ending Balance	101.7	101.7	101.7	167.2
Storage and Terminals
Goodwill [Roll Forward]
Beginning Balance		36.4	50.5
Goodwill Impairments during the Period		36.4	14.1	53.7
Ending Balance	36.4	0.0	36.4	50.5
US Salt
Goodwill [Roll Forward]
Beginning Balance		12.6	12.6
Goodwill Impairments during the Period		0.0	0.0	0.0
Goodwill, Written off Related to Sale of Business Unit		(12.6)
Ending Balance	12.6	0.0	12.6	12.6
Trucking
Goodwill [Line Items]
Impairment of intangible assets			31.4
Goodwill [Roll Forward]
Beginning Balance		0.0	29.5
Goodwill Impairments during the Period		0.0	29.5	148.4
Ending Balance	0.0	0.0	0.0	29.5
Haynesville
Goodwill [Line Items]
Impairment of intangible assets				6.0
Barnett
Goodwill [Line Items]
Impairment of intangible assets				238.9
Goodwill [Roll Forward]
Beginning Balance		0.0	0.0
Goodwill Impairments during the Period		0.0	0.0	257.2
Ending Balance	0.0	0.0	0.0	0.0
Watkins Glen
Goodwill [Roll Forward]
Beginning Balance		0.0	0.0
Goodwill Impairments during the Period		0.0	0.0	66.2
Ending Balance	0.0	0.0	0.0	0.0
CMLP
Goodwill [Roll Forward]
Beginning Balance		199.0	1,085.5
Goodwill Impairments during the Period		38.8	162.6	1,149.1
Ending Balance	199.0	147.6	199.0	1,085.5
Goodwill, Other Increase (Decrease)		(12.6)	(723.9)
Crestwood Equity Partners LP
Goodwill [Roll Forward]
Beginning Balance		199.0	1,085.5
Goodwill Impairments during the Period		38.8	162.6	1,406.3
Ending Balance	199.0	147.6	199.0	1,085.5
Marketing Supply and Logistics
Goodwill [Line Items]
Consideration transferred	7.2
Goodwill [Roll Forward]
Beginning Balance		153.1
Goodwill Impairments during the Period		38.8	109.1	453.2
Ending Balance	153.1	101.7	153.1
Marketing Supply and Logistics | CMLP
Goodwill [Roll Forward]
Beginning Balance		153.1
Goodwill Impairments during the Period		38.8	109.1	$ 453.2
Ending Balance	$ 153.1	$ 101.7	$ 153.1

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Divestitures (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Decrease in Intangible Assets		$ (8.5)
US Salt, LLC | Marketing Supply and Logistics
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration	$ 223.6
Property, Plant and Equipment, Gross, Period Decrease	157.4
Goodwill, Period Decrease	12.6
Decrease in Intangible Assets	5.8
Decrease in Other Operating Assets	14.2
Gain (Loss) on Sale of Assets and Asset Impairment Charges	$ 33.6

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Certain Balance Sheet Information (Property, Plant And Equipment) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 2,285.2	$ 2,555.4
Less: accumulated depreciation and depletion	464.4	457.8
Property, plant and equipment, net	1,820.8	2,097.6
Depletion	0.7
Loss on long-lived assets, net	(65.6)	(65.6)	$ (821.2)
Crestwood Equity Partners LP
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,285.2	2,555.4
Less: accumulated depreciation and depletion	464.4	457.8
Property, plant and equipment, net	1,820.8	2,097.6
Depreciation	135.9	154.8	195.1
Interest Costs Capitalized	2.9	0.7	2.5
Crestwood Equity Partners LP | Gathering systems and pipelines and related assets
Property, Plant and Equipment [Line Items]
Property, plant and equipment	678.0	639.4
Crestwood Equity Partners LP | Facilities and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,141.4	1,328.3
Crestwood Equity Partners LP | Buildings, land, rights-of-way, storage rights and easements
Property, Plant and Equipment [Line Items]
Property, plant and equipment	319.1	315.4
Crestwood Equity Partners LP | Vehicles
Property, Plant and Equipment [Line Items]
Property, plant and equipment	37.3	45.7
Crestwood Equity Partners LP | Construction in process
Property, Plant and Equipment [Line Items]
Property, plant and equipment	87.5	85.9
Crestwood Equity Partners LP | Salt deposits
Property, Plant and Equipment [Line Items]
Property, plant and equipment	0.0	120.5
Crestwood Equity Partners LP | Office furniture and fixtures
Property, Plant and Equipment [Line Items]
Property, plant and equipment	21.9	20.2
CMLP
Property, Plant and Equipment [Line Items]
Property, plant and equipment	2,615.3	2,885.5
Less: accumulated depreciation and depletion	607.8	587.1
Property, plant and equipment, net	2,007.5	2,298.4
Depreciation	150.0	168.9	186.7
Loss on long-lived assets, net	(65.6)	(65.6)	$ (227.8)
CMLP | Gathering systems and pipelines and related assets
Property, Plant and Equipment [Line Items]
Property, plant and equipment	820.9	782.3
CMLP | Facilities and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,326.5	1,513.4
CMLP | Buildings, land, rights-of-way, storage rights and easements
Property, Plant and Equipment [Line Items]
Property, plant and equipment	322.8	319.1
CMLP | Vehicles
Property, Plant and Equipment [Line Items]
Property, plant and equipment	35.5	44.0
CMLP | Construction in process
Property, Plant and Equipment [Line Items]
Property, plant and equipment	87.5	85.9
CMLP | Salt deposits
Property, Plant and Equipment [Line Items]
Property, plant and equipment	0.0	120.5
CMLP | Office furniture and fixtures
Property, Plant and Equipment [Line Items]
Property, plant and equipment	22.1	$ 20.3
US Salt
Property, Plant and Equipment [Line Items]
Loss on long-lived assets, net	33.6
Arrow and Marcellus
Property, Plant and Equipment [Line Items]
Loss on long-lived assets, net	$ 14.4

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Certain Balance Sheet Information (Intangible Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Finite-Lived Intangible Assets [Line Items]
Less: accumulated amortization	$ 191.6	$ 241.2
Crestwood Equity Partners LP
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	53.7	72.5	$ 102.8
Intangible assets, Gross	788.8	898.6
Less: accumulated amortization	191.6	241.2
Total intangible assets, net	597.2	657.4
Crestwood Equity Partners LP | Customer accounts
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	438.9	541.9
Less: accumulated amortization	89.8	162.4
Crestwood Equity Partners LP | Covenants not to compete
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	0.0	1.0
Crestwood Equity Partners LP | Gathering systems and pipelines and related assets
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	325.2	325.2
Less: accumulated amortization	82.0	63.2
Crestwood Equity Partners LP | Trademarks
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	24.7	30.5
Less: accumulated amortization	19.8	15.6
CMLP
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	50.6	69.3	$ 89.6
Intangible assets, Gross	773.3	883.1
Less: accumulated amortization	177.6	230.2
Total intangible assets, net	595.7	652.9
CMLP | Customer accounts
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	438.9	541.9
Less: accumulated amortization	89.8	162.4
CMLP | Covenants not to compete
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	0.0	1.0
CMLP | Gathering systems and pipelines and related assets
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	325.2	325.2
CMLP | Acquired storage contracts
Finite-Lived Intangible Assets [Line Items]
Less: accumulated amortization	5.8	4.6
CMLP | Trademarks
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	9.2	15.0
Less: accumulated amortization	$ 82.0	$ 63.2

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Certain Balance Sheet Information (Amortization and Interest Expense, Fiscal Year Maturity) (Details) $ in Millions	Dec. 31, 2017 USD ($)
Crestwood Equity Partners LP
Finite-Lived Intangible Assets [Line Items]
2018	$ 43.4
2019	41.7
2020	41.7
2021	41.7
2022	41.7
CMLP
Finite-Lived Intangible Assets [Line Items]
2018	42.0
2019	41.7
2020	41.7
2021	41.7
2022	$ 41.7

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Certain Balance Sheet Information (Accrued Expenses and Other Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Accrued Expenses and Other Liabilities [Line Items]
Accrued expenses	$ 56.6	$ 46.5
Accrued expenses and other liabilities	105.9	90.5
Accrued property taxes	4.8	4.2
Accrued natural gas purchases	0.0	4.9
Income tax payable	0.3	1.6
Interest payable	20.3	22.8
Accrued additions to property, plant and equipment	22.3	1.7
Capital leases	1.0	1.3
Deferred revenue	0.6	7.5
Total accrued expenses and other liabilities	105.9	90.5
CMLP
Accrued Expenses and Other Liabilities [Line Items]
Accrued expenses	55.5	45.1
Accrued expenses and other liabilities	104.7	87.9
Accrued property taxes	4.8	4.2
Accrued natural gas purchases	0.0	4.9
Income tax payable	0.3	0.4
Interest payable	20.3	22.8
Accrued additions to property, plant and equipment	22.2	1.7
Capital leases	1.0	1.3
Deferred revenue	0.6	7.5
Total accrued expenses and other liabilities	$ 104.7	$ 87.9

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Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Net asset retirement obligation at January 1	$ 27.8	$ 26.4
Liabilities incurred	0.0	1.0
Liabilities settled	(1.2)	(1.2)
Accretion expense	(1.4)	(1.6)
Change in estimate	(0.5)	0.0
Net asset retirement obligation at December 31	$ 27.5	$ 27.8

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Investments in Unconsolidated Affiliates Investments in Unconsolidated Affiliates Table (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution	$ 107.6	$ 53.9	$ 21.8
Payments to Acquire Equity Method Investments Cash and Noncash Consideration	127.4		41.8
Payments to Acquire Equity Method Investments	58.0	12.4	42.0
Equity Method Investment, Summarized Financial Information, Current Assets	136.4	107.4
Equity Method Investment, Summarized Financial Information, Revenue	350.4	226.9	104.7
Equity Method Investment Summarized Financial Information Operating Expenses	221.3	158.0	79.5
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	130.0	68.8	24.9
Investments in unconsolidated affiliates	1,183.0	1,115.4
Earnings (loss) from unconsolidated affiliates, net	47.8	31.5	(60.8)
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	2,566.5	2,516.1
Equity Method Investment, Summarized Financial Information, Current Liabilities	60.4	29.2
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	95.0	78.5
Equity Method Investment Summarized Financial Information, Equity	2,547.5	2,515.8
Goodwill impairment	38.8	162.6	1,406.3
Stagecoach Gas Services LLC
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution	47.3	16.0	0.0
Payments to Acquire Equity Method Investments	0.8	0.0	0.0
Equity Method Investment, Summarized Financial Information, Current Assets	55.1	57.0
Equity Method Investment, Summarized Financial Information, Revenue	168.6	99.3	0.0
Equity Method Investment Summarized Financial Information Operating Expenses	77.7	44.1	0.0
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	91.1	55.3	0.0
Difference between carrying amount and underlying equity	$ 51.4
Equity method ownership percentage	50.00%
Investments in unconsolidated affiliates	$ 849.8	871.0
Earnings (loss) from unconsolidated affiliates, net	25.3	15.9	0.0
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	1,765.4	1,807.6
Equity Method Investment, Summarized Financial Information, Current Liabilities	7.0	6.0
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	1.4	4.1
Equity Method Investment Summarized Financial Information, Equity	1,812.1	1,854.5
Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution	26.3	27.4	12.5
Equity Method Investment, Summarized Financial Information, Revenue	181.8	127.6	104.7
Equity Method Investment Summarized Financial Information Operating Expenses	143.6	113.9	79.5
Equity Method Investment, Summarized Financial Information, Net Income (Loss)	38.9	13.5	24.9
Difference between carrying amount and underlying equity	$ 0.7
Equity method ownership percentage	50.00%
Investments in unconsolidated affiliates	$ 184.9	197.2
Earnings (loss) from unconsolidated affiliates, net	10.5	20.8	(43.4)
Goodwill impairment			51.4
Other Equity Method Investments
Schedule of Equity Method Investments [Line Items]
Equity Method Investment, Summarized Financial Information, Current Assets	81.3	50.4
Equity Method Investment, Summarized Financial Information, Noncurrent Assets	801.1	708.5
Equity Method Investment, Summarized Financial Information, Current Liabilities	53.4	23.2
Equity Method Investment, Summarized Financial Information, Noncurrent Liabilities	93.6	74.4
Equity Method Investment Summarized Financial Information, Equity	735.4	661.3
Crestwood Permian Basin Holdings LLC
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution	23.4	0.0	0.0
Payments to Acquire Equity Method Investments Cash and Noncash Consideration	$ 117.5
Payments to Acquire Equity Method Investments		0.0	0.0
Equity method ownership percentage	50.00%
Investments in unconsolidated affiliates	$ 102.0	(0.5)
Earnings (loss) from unconsolidated affiliates, net	8.4	(0.5)	0.0
Tres Palacios Holdings LLC
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution	9.0	8.5	7.4
Payments to Acquire Equity Method Investments	5.6	11.0	5.7
Difference between carrying amount and underlying equity	26.5
Amortization	$ 1.3	1.3	1.3
Equity method ownership percentage	50.01%
Investments in unconsolidated affiliates	$ 37.8	39.0
Earnings (loss) from unconsolidated affiliates, net	2.2	(0.3)	2.5
Powder River Basin Industrial Complex, LLC
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution	1.6	2.0	1.9
Payments to Acquire Equity Method Investments	0.0	0.0	10.7
Difference between carrying amount and underlying equity	6.4
Income (loss) from Equity Method Investments, Capital Adjustment			3.2
Amortization	$ 0.6	1.6
Equity method ownership percentage	50.01%
Investments in unconsolidated affiliates	$ 8.5	8.7
Earnings (loss) from unconsolidated affiliates, net	1.4	(4.4)	(19.9)
Goodwill impairment		5.8	23.4
RKI Exploration and Production, LLC's | Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
Amortization	$ 0.1	$ 0.1	$ 3.0

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Investments in Unconsolidated Affiliates (Details) $ in Millions				1 Months Ended		12 Months Ended
	Jan. 01, 2018 USD ($)	Jun. 21, 2017 USD ($)	Jun. 03, 2016 USD ($)	Jan. 31, 2018 USD ($)	Oct. 31, 2017 USD ($)	Dec. 31, 2017 USD ($) a	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments						$ 58.0	$ 12.4	$ 42.0
Investments in unconsolidated affiliates						1,183.0	1,115.4
Earnings (loss) from unconsolidated affiliates, net						47.8	31.5	(60.8)
Net proceeds from sale of assets						225.2	972.7	2.7
Loss on long-lived assets, net						(65.6)	(65.6)	(821.2)
Estimated Cost to Build						180.0
Payments to Acquire Property, Plant, and Equipment						188.4	100.7	182.7
Contribution of Property		$ 69.0
Related Party Transaction, Expenses from Transactions with Related Party						22.3	8.1	3.3
Proceeds from Equity Method Investment, Distribution, Return of Capital						59.9	14.8	9.3
Proceeds from Equity Method Investment, Distribution						107.6	53.9	21.8
Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates						184.9	197.2
Earnings (loss) from unconsolidated affiliates, net						10.5	20.8	(43.4)
Difference between carrying amount and underlying equity						$ 0.7
Equity method ownership percentage						50.00%
Related Party Transaction, Expenses from Transactions with Related Party						$ 0.4	0.4	0.5
Proceeds from Equity Method Investment, Distribution						26.3	27.4	12.5
Jackalope Gas Gathering Services, LLC | Subsequent Event
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution	$ 7.4
Tres Palacios Holdings LLC
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments						5.6	11.0	5.7
Investments in unconsolidated affiliates						37.8	39.0
Earnings (loss) from unconsolidated affiliates, net						2.2	(0.3)	2.5
Difference between carrying amount and underlying equity						26.5
Amortization						$ 1.3	1.3	1.3
Equity method ownership percentage						50.01%
Related Party Transaction, Expenses from Transactions with Related Party						$ 3.5	2.7	2.8
Proceeds from Equity Method Investment, Distribution						9.0	8.5	7.4
Powder River Basin Industrial Complex, LLC
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments						0.0	0.0	10.7
Investments in unconsolidated affiliates						8.5	8.7
Earnings (loss) from unconsolidated affiliates, net						1.4	(4.4)	(19.9)
Difference between carrying amount and underlying equity						6.4
Amortization						$ 0.6	1.6
Equity method ownership percentage						50.01%
Proceeds from Equity Method Investment, Distribution						$ 1.6	2.0	1.9
Powder River Basin Industrial Complex, LLC | Subsequent Event
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution				$ 0.3
Crestwood Permian Basin Holdings
Schedule of Equity Method Investments [Line Items]
Percentage of Available Cash Distributed						100.00%
Difference between carrying amount and underlying equity						$ 11.6
Net proceeds from sale of assets					$ 37.9
Related Party Transaction, Expenses from Transactions with Related Party						$ 10.0
Proceeds from Equity Method Investment, Distribution					$ 18.9
Crestwood Permian Basin Holdings | Subsequent Event
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution				4.3
Stagecoach Gas Services LLC
Schedule of Equity Method Investments [Line Items]
Percentage of Available Cash Distributed						35.00%
Payments to Acquire Equity Method Investments						$ 0.8	0.0	0.0
Investments in unconsolidated affiliates						849.8	871.0
Contingent consideration, noncurrent liability						57.0
Earnings (loss) from unconsolidated affiliates, net						25.3	15.9	0.0
Difference between carrying amount and underlying equity						$ 51.4
Net proceeds from sale of assets							3.0
Equity method ownership percentage						50.00%
Related Party Transaction, Expenses from Transactions with Related Party						$ 8.4	5.0
Proceeds from Equity Method Investment, Distribution						47.3	16.0	0.0
Stagecoach Gas Services LLC | Subsequent Event
Schedule of Equity Method Investments [Line Items]
Proceeds from Equity Method Investment, Distribution				$ 11.3
RKI Exploration and Production, LLC's | Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
Amortization						$ 0.1	0.1	3.0
Crestwood Permian Basin LLC
Schedule of Equity Method Investments [Line Items]
Equity Interest						100.00%
Crestwood Niobrara LLC | Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments						$ 3.5	1.4	25.4
Crestwood Equity Partners LP | Crestwood Permian Basin Holdings
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage						50.00%
SWEPI LP | Crestwood Permian Basin Holdings
Schedule of Equity Method Investments [Line Items]
Area of Land | a						100,000
Payments to Acquire Property, Plant, and Equipment						$ 84.3
SWEPI LP | Crestwood Permian Basin LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage					50.00%
Crestwood New Mexico Pipeline LLC [Member]
Schedule of Equity Method Investments [Line Items]
Equity Interest						100.00%
Twin Eagle Powder River Basin, LLC | Powder River Basin Industrial Complex, LLC
Schedule of Equity Method Investments [Line Items]
Percentage of voting interests acquired						50.00%
First Reserve Management, L.P. | Crestwood Permian Basin Holdings
Schedule of Equity Method Investments [Line Items]
Capital Commitment to Acquire Equity Method Investment		$ 151.0
CEGP | Stagecoach Gas Services LLC
Schedule of Equity Method Investments [Line Items]
Percentage of Available Cash Distributed						65.00%
Net proceeds from sale of assets			$ 975.0				975.0
CMLP
Schedule of Equity Method Investments [Line Items]
Payments to Acquire Equity Method Investments						$ 58.0	12.4	41.8
Investments in unconsolidated affiliates						1,183.0	1,115.4
Earnings (loss) from unconsolidated affiliates, net						47.8	31.5	(60.8)
Net proceeds from sale of assets						225.2	972.7	2.7
Loss on long-lived assets, net						(65.6)	(65.6)	(227.8)
Payments to Acquire Property, Plant, and Equipment						188.4	100.7	182.7
Proceeds from Equity Method Investment, Distribution, Return of Capital						$ 59.9	14.8	$ 9.3
CMLP | Tres Palacios Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage						50.01%
CMLP | Stagecoach Gas Services LLC
Schedule of Equity Method Investments [Line Items]
Deconsolidation, Gain (Loss), Amount							$ 32.4
Equity method ownership percentage			50.00%				50.00%
Williams Partners LP | Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
Percentage of voting interests acquired						50.00%
Brookfield Infrastructure Group | Tres Palacios Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage						49.99%

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Risk Management (Notional Amounts and Terms of Company's Derivative Financial Instruments) (Details) - bbl bbl in Millions	Dec. 31, 2017	Dec. 31, 2016
Propane, crude and heating oil (MMBbls) | Fixed Price Payor
Derivative [Line Items]
Propane, crude and heating oil (MMBbls)	15.3	13.1
Propane, crude and heating oil (MMBbls) | Fixed Price Receiver
Derivative [Line Items]
Propane, crude and heating oil (MMBbls)	17.5	15.1
Natural Gas [Member] | Fixed Price Payor
Derivative [Line Items]
Propane, crude and heating oil (MMBbls)	780.0	0.0
Natural Gas [Member] | Fixed Price Receiver
Derivative [Line Items]
Propane, crude and heating oil (MMBbls)	660.0	0.0

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Risk Management (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative [Line Items]
Collateral posted for commodity derivative instruments	$ 3.7	$ 4.3
Price Risk Contracts | Maximum
Derivative [Line Items]
Remaining maturity	34 months
Percent of contracts expiring in next twelve months	88.00%
ERROR in label resolution.
Derivative [Line Items]
Aggregate fair value of commodity derivative instruments	$ 28.9	13.9
Collateral posted for commodity derivative instruments	0.1	0.1
ERROR in label resolution.
Derivative [Line Items]
Derivative Asset	27.2	14.3
ERROR in label resolution.
Derivative [Line Items]
NYMEX margin deposit	5.6	4.2
Products and services sold
Derivative [Line Items]
Gain (Loss) on derivative instruments not designated as hedging	$ 31.2	$ 7.8	$ 18.9

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Fair Value Measurements (Schedule of Carrying Values and Estimated Fair Values of Senior Notes) (Details) - CMLP - Crestwood Midstream Senior Notes - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Senior Notes, 2020
Debt Instrument [Line Items]
Carrying Amount	$ 0.0	$ 340.6
Fair Value	0.0	350.2
Senior Notes, 2022
Debt Instrument [Line Items]
Carrying Amount	0.0	429.3
Fair Value	0.0	447.3
Senior Notes, 2023
Debt Instrument [Line Items]
Carrying Amount	692.1	690.6
Debt Instrument, Fair Value Disclosure	728.8	722.6
Senior Notes, 2025
Debt Instrument [Line Items]
Carrying Amount	492.3	0.0
Debt Instrument, Fair Value Disclosure	$ 517.9	$ 0.0

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Fair Value Measurements (Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Assets, Fair Value Disclosure [Abstract]
Assets from price risk management	$ 103.3	$ 85.0
Assets from price risk management, Total	7.2	6.3
SPH units	3.5	4.3
Assets, Fair Value Disclosure, Excluding Netting Adjustments	106.8	89.3
Netting Agreements	(74.6)	(67.8)
Derivative Asset, Fair Value of Collateral	(21.5)	(10.9)
Total assets at fair value	10.7	10.6
Liabilities, Fair Value Disclosure [Abstract]
Liabilities from price risk management	119.6	92.9
Liabilities from price risk management, Total	48.9	28.6
Liabilities, Fair Value Disclosure, Excluding Netting Adjustments		92.9
Netting Agreements	(74.6)	(67.8)
Derivative Liability, Fair Value of Collateral	3.9	3.5
Total liabilities at fair value		28.6
Level 1
Assets, Fair Value Disclosure [Abstract]
Assets from price risk management	1.1	0.6
SPH units	3.5	4.3
Assets, Fair Value Disclosure, Excluding Netting Adjustments	4.6	4.9
Liabilities, Fair Value Disclosure [Abstract]
Liabilities from price risk management	1.4	2.7
Liabilities, Fair Value Disclosure, Excluding Netting Adjustments	1.4	2.7
Level 2
Assets, Fair Value Disclosure [Abstract]
Assets from price risk management	102.2	84.4
SPH units	0.0	0.0
Assets, Fair Value Disclosure, Excluding Netting Adjustments	102.2	84.4
Liabilities, Fair Value Disclosure [Abstract]
Liabilities from price risk management	118.2	90.2
Liabilities, Fair Value Disclosure, Excluding Netting Adjustments	118.2	90.2
Level 3
Assets, Fair Value Disclosure [Abstract]
Assets from price risk management	0.0	0.0
SPH units	0.0	0.0
Assets, Fair Value Disclosure, Excluding Netting Adjustments	0.0	0.0
Liabilities, Fair Value Disclosure [Abstract]
Liabilities from price risk management	0.0	0.0
Liabilities, Fair Value Disclosure, Excluding Netting Adjustments	$ 0.0	$ 0.0

XML

Long-Term Debt (Components Of Long-Term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Carrying Amount	$ 0.0
Debt Issuance Costs, Net	28.4	$ 34.0
Less: current portion	0.9	1.0
Total long-term debt	1,491.3	1,522.7
Crestwood Midstream 2020 Senior Notes
Debt Instrument [Line Items]
Fair value adjustment	0.0	1.8
Crestwood Midstream Revolver | Revolving Credit Facility
Debt Instrument [Line Items]
Credit agreement outstanding carrying value	318.2	77.0
Senior Notes, 2022
Debt Instrument [Line Items]
Debt Issuance Costs, Net	6.8
Senior Notes, 2025 | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Carrying Amount	500.0
CMLP
Debt Instrument [Line Items]
Carrying Amount		338.8
Obligations under noncompetition agreements and notes to former owners of businesses acquired	2.4	3.7
Debt, Long-term and Short-term, Combined Amount	1,492.2	1,523.7
Less: current portion	0.9	1.0
Total long-term debt	1,491.3	1,522.7
CMLP | Crestwood Midstream 2022 senior unsecured notes
Debt Instrument [Line Items]
Carrying Amount		436.4
CMLP | Senior Notes, 2022 | Crestwood Midstream 2022 senior unsecured notes
Debt Instrument [Line Items]
Carrying Amount	0.0
CMLP | Senior Notes, 2023 | Crestwood Midstream 2022 senior unsecured notes
Debt Instrument [Line Items]
Carrying Amount	700.0	700.0
CMLP | Senior Notes, 2025 | Crestwood Midstream 2022 senior unsecured notes
Debt Instrument [Line Items]
Carrying Amount	$ 500.0	$ 0.0

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Long-Term Debt (Narrative) (Detail)														1 Months Ended		9 Months Ended			12 Months Ended
	Nov. 14, 2017 USD ($)	Aug. 14, 2017 USD ($)	May 15, 2017 USD ($)	Feb. 14, 2017 USD ($)	Nov. 14, 2016 USD ($)	Aug. 12, 2016 USD ($)	May 13, 2016 USD ($)	Feb. 12, 2016 USD ($)	Nov. 13, 2015 USD ($)	Sep. 30, 2015 USD ($)	Aug. 14, 2015 USD ($)	May 15, 2015 USD ($)	Feb. 13, 2015 USD ($)	Jun. 30, 2016 USD ($)	Apr. 30, 2015 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2016 USD ($)	Sep. 30, 2015 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Debt Instrument [Line Items]
Amount of Restricted Net Assets for Consolidated and Unconsolidated Subsidiaries																			$ 2,195,400,000
Distribution Made to Limited Partner, Cash Distributions Paid	$ 42,200,000	$ 41,800,000	$ 41,800,000	$ 41,800,000	$ 41,400,000	$ 41,400,000	$ 41,400,000	$ 95,600,000	$ 94,300,000		$ 25,700,000	$ 25,700,000	$ 25,800,000						167,600,000	$ 219,800,000	$ 171,500,000
Gains (Losses) on Extinguishment of Debt																	$ 10,000,000		(37,700,000)	10,000,000	(20,000,000)
Debt Issuance Costs, Net																			28,400,000	34,000,000
Carrying amount																			0
Repayments of Senior Debt														$ 312,900,000
Crestwood Equity Partners LP
Debt Instrument [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid										$ 378,300,000								$ 378,300,000
CMLP
Debt Instrument [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid											$ 74,300,000	$ 74,300,000	$ 74,300,000							222,900,000
Gains (Losses) on Extinguishment of Debt																			(37,700,000)	10,000,000	$ (18,900,000)
Carrying amount																				338,800,000
Senior Notes, 2019
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt															$ 17,100,000
Revolving Loan Facility | CMLP
Debt Instrument [Line Items]
Credit agreement outstanding carrying value																			1,500,000,000	1,000,000,000
Crestwood Midstream 2020 Senior Notes
Debt Instrument [Line Items]
Fair value adjustment																			$ 0	1,800,000
Crestwood Midstream 2022 senior unsecured notes | CMLP
Debt Instrument [Line Items]
Carrying amount																				436,400,000
Crestwood Midstream Revolver
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt																		$ 1,800,000
Senior Notes, 2023 | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage																			6.25%
Senior Notes, 2023 | Crestwood Midstream 2022 senior unsecured notes | CMLP
Debt Instrument [Line Items]
Carrying amount																			$ 700,000,000	700,000,000
Senior Notes, 2025 | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Carrying amount																			$ 500,000,000
Interest rate, stated percentage																			5.75%
Senior Notes, 2025 | Crestwood Midstream 2019 Senior Notes | CMLP
Debt Instrument [Line Items]
Proceeds from Issuance of Debt																			$ 492,000,000
Senior Notes, 2025 | Crestwood Midstream 2022 senior unsecured notes | CMLP
Debt Instrument [Line Items]
Carrying amount																			500,000,000	0
Crestwood Midstream Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Additional Potential Capacity																			350,000,000
Line of Credit Facility, Current Borrowing Capacity																			350,000,000
Crestwood Midstream Credit Facility | Minimum
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Amount																			0.0030
Crestwood Midstream Credit Facility | Maximum
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Amount																			0.0050
Senior Notes, 2022
Debt Instrument [Line Items]
Debt Issuance Costs, Net																			6,800,000
Repayments of Senior Debt																			$ 457,800,000
Senior Notes, 2022 | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage																			6.125%
Interest Paid														2,600,000					$ 1,000,000
Extinguishment of Debt, Amount														163,600,000
Senior Notes, 2022 | Crestwood Midstream 2022 senior unsecured notes | CMLP
Debt Instrument [Line Items]
Carrying amount																			$ 0
Crestwood Midstream Revolver
Debt Instrument [Line Items]
Consolidated leverage ratio, maximum																			5.50
Crestwood Midstream Revolver | Revolving Credit Facility
Debt Instrument [Line Items]
Credit agreement outstanding carrying value																			$ 318,200,000	77,000,000
Letters of credit outstanding																			$ 52,200,000	$ 64,000,000
Total funded debt to consolidated EBITDA																			4.14
Consolidated EBITDA to consolidated interest expense																			4.14
Senior Secured Leverage Ratio																			0.86
Weighted average interest rate																			4.11%	3.23%
Unused borrowing capacity																			$ 499,300,000
Interest coverage ratio, minimum																			2.50
Senior Secured Leverage Ratio, maximum																			3.75
Crestwood Midstream Revolver | Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Weighted average interest rate																			3.94%	3.21%
Crestwood Midstream Revolver | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Weighted average interest rate																			6.00%	5.25%
Crestwood Midstream Revolver | Revolving Credit Facility | Line of Credit
Debt Instrument [Line Items]
Proceeds from Issuance of Debt										$ 720,000,000
Crestwood Midstream Revolver | Bridge Loan
Debt Instrument [Line Items]
Credit agreement outstanding carrying value																			$ 25,000,000
Senior Notes, 2019 | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage															7.75%
Interest Paid															$ 500,000
Call Premium On Debt Redemption															13,600,000
Repayments of Senior Debt															364,100,000
Senior Notes, 2019 | Crestwood Midstream 2019 Senior Notes | CMLP
Debt Instrument [Line Items]
Long-term Debt															$ 350,000,000
Senior Notes, 2020
Debt Instrument [Line Items]
Repayments of Senior Debt																$ 349,900,000
Senior Notes, 2020 | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage																			6.00%
Interest Paid														4,500,000					$ 5,100,000
Extinguishment of Debt, Amount														$ 161,200,000
Obligations Under Noncompetition Agreements And Notes To Former Owners Of Businesses Acquired | CMLP
Debt Instrument [Line Items]
Total payments due																			2,700,000	$ 4,200,000
Obligations under noncompete agreements, unamortized discount																			$ 300,000	$ 500,000
Obligations Under Noncompetition Agreements And Notes To Former Owners Of Businesses Acquired | Minimum | CMLP
Debt Instrument [Line Items]
Inputed interest																			5.02%
Obligations Under Noncompetition Agreements And Notes To Former Owners Of Businesses Acquired | Maximum | CMLP
Debt Instrument [Line Items]
Inputed interest																			6.75%
Federal Funds Rate | Revolving Credit Facility | Crestwood Midstream Revolver
Debt Instrument [Line Items]
Variable interest rate																			0.50%
Eurodollar [Member] | Revolving Credit Facility | Crestwood Midstream Credit Facility | Minimum
Debt Instrument [Line Items]
Variable interest rate																			1.75%
Eurodollar [Member] | Revolving Credit Facility | Crestwood Midstream Credit Facility | Maximum
Debt Instrument [Line Items]
Variable interest rate																			2.75%
Eurodollar [Member] | Revolving Credit Facility | Crestwood Midstream Revolver
Debt Instrument [Line Items]
Variable interest rate																			1.00%
Eurodollar [Member] | Revolving Credit Facility | Crestwood Midstream Revolver | Minimum
Debt Instrument [Line Items]
Variable interest rate																			0.75%
Eurodollar [Member] | Revolving Credit Facility | Crestwood Midstream Revolver | Maximum
Debt Instrument [Line Items]
Variable interest rate																			1.75%
Tres Palacios Holdings LLC
Debt Instrument [Line Items]
Equity method ownership percentage																			50.01%
Tres Palacios Holdings LLC | CMLP
Debt Instrument [Line Items]
Equity method ownership percentage																			50.01%
Financial Guarantee [Member]
Debt Instrument [Line Items]
Guarantor Obligations, Maximum Exposure, Undiscounted																			$ 497,000,000
Interest rate, stated percentage																			7.50%

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Long-Term Debt (Maturities of Long Term Debt) (Details) - CMLP $ in Millions	Dec. 31, 2017 USD ($)
Debt Instrument [Line Items]
2018	$ 0.9
2019	0.9
2020	318.4
2021	0.2
2022	0.2
Thereafter	1,200.0
Total debt	$ 1,520.6

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Earnings Per Limited Partner Unit (Schedule of Reconciliation of Earnings Per Share) (Details) - shares	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Preferred Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	7,007,917	6,433,127	1,547,060
Subordinated units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	438,789
Crestwood Niobrara LLC | Preferred Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	7,146,663	7,548,624	2,760,794

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Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Contingency [Line Items]
Net Deferred Tax Liability, Decrease Due To Regulation	$ 1.3
Deferred:
Total deferred	2.1	$ 3.1	$ 3.6
(Provision) benefit for income taxes	0.8	(0.3)	1.4
Crestwood Equity Partners LP
Current:
Federal	(1.1)	(3.2)	(1.6)
State	(0.2)	(0.2)	(0.6)
Total current	(1.3)	(3.4)	(2.2)
Deferred:
Federal	2.1	3.0	2.9
State	0.0	0.1	0.7
Total deferred	2.1	3.1	3.6
(Provision) benefit for income taxes	0.8	(0.3)	1.4
Deferred tax asset:
Basis difference in stock of company	0.2	0.2
Total deferred tax asset	0.2	0.2
Deferred tax liability:
Basis difference in stock of acquired company	(3.5)	(5.5)
Deferred Tax Liabilities, Gross	(3.5)	(5.5)
Total deferred tax liability	(3.3)	(5.3)
CMLP
Current:
Federal	0.0	0.0	0.0
State	0.0	0.2	(0.3)
Total current	0.0	0.2	(0.3)
Deferred:
Federal	0.0	0.0	0.0
State	0.0	(0.2)	0.3
Total deferred	0.0	(0.2)	0.3
(Provision) benefit for income taxes	0.0	0.0	$ 0.0
Deferred tax asset:
Basis difference in stock of company	0.0	0.0
Total deferred tax asset	0.0	0.0
Deferred tax liability:
Basis difference in stock of acquired company	(0.7)	(0.7)
Deferred Tax Liabilities, Gross	(0.7)	(0.7)
Total deferred tax liability	$ (0.7)	$ (0.7)

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Partners' Capital (Schedule of Issuance of Units) (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016
Partners' Capital [Abstract]
Partners' Capital Account, Units, Sold in Public Offering	195,753	437,518	633,271
Proceeds from Issuance or Sale of Equity	$ 4.6	$ 10.6	$ 15.2
Units	70,721,563		70,721,563	69,499,741

XML

Partners' Capital (Narrative) (Details) $ / shares in Units, $ in Millions																															1 Months Ended	9 Months Ended	12 Months Ended
	Feb. 14, 2018 USD ($) $ / shares	Feb. 07, 2018	Nov. 14, 2017 USD ($) $ / shares	Nov. 07, 2017	Aug. 14, 2017 USD ($) $ / shares	Aug. 07, 2017	May 15, 2017 USD ($) $ / shares	May 08, 2017	Feb. 14, 2017 USD ($) $ / shares	Feb. 07, 2017	Nov. 14, 2016 USD ($) $ / shares	Nov. 07, 2016	Aug. 12, 2016 USD ($) $ / shares	Aug. 05, 2016	May 13, 2016 USD ($) $ / shares	May 06, 2016	Feb. 12, 2016 USD ($) $ / shares	Feb. 05, 2016	Nov. 13, 2015 USD ($) $ / shares	Nov. 06, 2015	Sep. 30, 2015 USD ($) shares	Aug. 14, 2015 USD ($) $ / shares	Aug. 10, 2015 USD ($)	Aug. 07, 2015	May 15, 2015 USD ($) $ / shares	May 08, 2015	Feb. 13, 2015 USD ($) $ / shares	Feb. 06, 2015	Jan. 30, 2015 shares	Jun. 17, 2014 USD ($) $ / shares	Dec. 31, 2017 USD ($) $ / shares shares	Sep. 30, 2015 USD ($) shares	Dec. 31, 2017 USD ($) $ / shares shares	Dec. 31, 2016 USD ($) shares	Dec. 31, 2015 USD ($) shares	Jun. 15, 2016 shares
Distribution Made to Member or Limited Partner [Line Items]
Distribution to limited partner, distribution date			Nov. 14, 2017		Aug. 14, 2017		May 15, 2017		Feb. 14, 2017		Nov. 14, 2016		Aug. 12, 2016		May 13, 2016		Feb. 12, 2016		Nov. 13, 2015			Aug. 14, 2015			May 15, 2015		Feb. 13, 2015
Conversion ratio																					2.75											2.75
Maximum Period For Distribution Of Available Cash																																	45 days
Distribution Made to Limited Partner, Cash Distributions Paid			$ 42.2		$ 41.8		$ 41.8		$ 41.8		$ 41.4		$ 41.4		$ 41.4		$ 95.6		$ 94.3			$ 25.7			$ 25.7		$ 25.8						$ 167.6	$ 219.8	$ 171.5
Per unit rate, in dollars per unit | $ / shares			$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 1.3750		$ 1.3750			$ 1.3750			$ 1.3750		$ 1.3750
Distributions to partners																																	(167.6)	(219.8)	(171.5)
Payments to Acquire Equity Method Investments																																	58.0	12.4	42.0
Loss on contingent consideration																																	$ (57.0)	$ 0.0	$ 0.0
Distribution made to limited partners | shares																																	4,724,030	5,815,170	1,372,573
Distributions paid to non-controlling partners																																	$ 15.2	$ 15.2	$ 234.2
Limited partners' units, issued | shares																															70,721,563		70,721,563	69,499,741
Dividends, Paid-in-kind																																	$ 43.1	$ 53.0	12.5
Common Units Available for Issuance | shares																																				7,290,552
Issuance of preferred equity of subsidiary																																	$ 0.0
Preferred units, outstanding | shares																															71,257,445		71,257,445	66,533,415
Preferred units, issued | shares																															71,257,445		71,257,445	66,533,415
Equity Offering Program Authorized Amount																																	$ 250.0
Equity Distribution Program Management Fee Percentage																																	2.00%
Payments of Stock Issuance Costs																																	$ 0.3
Distribution to limited partner, record date				Nov. 07, 2017		Aug. 07, 2017		May 08, 2017		Feb. 07, 2017		Nov. 07, 2016		Aug. 05, 2016		May 06, 2016		Feb. 05, 2016		Nov. 06, 2015				Aug. 07, 2015		May 08, 2015		Feb. 06, 2015
Payments for Repurchase of Redeemable Noncontrolling Interest																															$ 202.7		202.7	$ 0.0	0.0
Proceeds from Noncontrolling Interests																															$ 175.0		$ 175.0	0.0	0.0
Preferred Units, Class A
Distribution Made to Member or Limited Partner [Line Items]
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units																							$ 58.8
Partners' Capital Account, Private Placement of Units, Price Per Unit | $ / shares																														$ 25.10			$ 9.13
Proceeds from Issuance of Preferred Limited Partners Units, Gross																							$ 60.0
Crestwood Equity Partners LP
Distribution Made to Member or Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid																					$ 378.3											$ 378.3
Preferred units, issued | shares																					59,345,672											59,345,672
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest																																	99.90%
Crestwood Niobrara LLC | Cash distribution
Distribution Made to Member or Limited Partner [Line Items]
Distributions paid to non-controlling partners																																	$ 15.2	15.2	11.3
Crestwood Gas Services GP, LLC [Member]
Distribution Made to Member or Limited Partner [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest																																	0.10%
CMLP
Distribution Made to Member or Limited Partner [Line Items]
Distribution to limited partner, distribution date																						Aug. 14, 2015			May 15, 2015		Feb. 13, 2015
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units																																	$ 0.0	0.0	58.8
Maximum Period For Distribution Of Available Cash																																	45 days
Distribution Made to General Partner, Cash Distributions Paid																																			31.4
Distribution Made to Limited Partner, Cash Distributions Paid																						$ 74.3			$ 74.3		$ 74.3							222.9
Dividends received from CMLP																																	$ 174.0	227.6	175.6
Per unit rate, in dollars per unit | $ / shares																						$ 0.41			$ 0.41		$ 0.41
Distributions to partners																																	(189.2)	(242.8)	(819.5)
Payments to Acquire Equity Method Investments																																	58.0	12.4	41.8
Loss on contingent consideration																																	(57.0)	0.0	$ 0.0
Distribution made to limited partners | shares																																			1,271,935
Dividends, Paid-in-kind																																			$ 31.9
Issuance of preferred equity of subsidiary																																	175.0
Preferred units, outstanding | shares																					21,580,244											21,580,244
Distribution to limited partner, record date																								Aug. 07, 2015		May 08, 2015		Feb. 06, 2015
Payments for Repurchase of Redeemable Noncontrolling Interest																																	202.7	0.0
Proceeds from Noncontrolling Interests																																	175.0	0.0	0.0
Tres Palacios Holdings LLC
Distribution Made to Member or Limited Partner [Line Items]
Payments to Acquire Equity Method Investments																																	$ 5.6	11.0	5.7
Equity method ownership percentage																															50.01%		50.01%
Tres Palacios Holdings LLC | CMLP
Distribution Made to Member or Limited Partner [Line Items]
Equity method ownership percentage																															50.01%		50.01%
Jackalope Gas Gathering Services, LLC
Distribution Made to Member or Limited Partner [Line Items]
Equity method ownership percentage																															50.00%		50.00%
Jackalope Gas Gathering Services, LLC | Preferred Units
Distribution Made to Member or Limited Partner [Line Items]
Distribution made to limited partners | shares																													3,680,570
Jackalope Gas Gathering Services, LLC | Crestwood Niobrara LLC
Distribution Made to Member or Limited Partner [Line Items]
Payments to Acquire Equity Method Investments																																	$ 3.5	$ 1.4	25.4
Cash distribution
Distribution Made to Member or Limited Partner [Line Items]
Distributions paid to non-controlling partners																																			$ 222.9
Cash distribution | Subsequent Event
Distribution Made to Member or Limited Partner [Line Items]
Distribution to limited partner, distribution date	Feb. 14, 2018
Distribution declared per limited partner unit | $ / shares	$ 0.600
Distribution to limited partner, record date		Feb. 07, 2018
Preferred Partner
Distribution Made to Member or Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid																																	$ 15.0
Partners' Capital, Distribution Amount Per Share | $ / shares																															$ 0.2567		$ 0.2567
Partners' Capital, Contingent Distribution Amount Per Share | $ / shares																															0.2111		$ 0.2111
Partner's Capital, Unpaid Distribution, Accrual Percentage																																	2.8125%
Preferred Partner | Subsequent Event
Distribution Made to Member or Limited Partner [Line Items]
Distribution Made to Limited Partner, Cash Distributions Paid	$ 15.0
Preferred Partner | CMLP
Distribution Made to Member or Limited Partner [Line Items]
Partners' Capital, Distribution Amount Per Share | $ / shares																															$ 0.5804		$ 0.5804
Partners' Capital Account, Private Placement of Units, Price Per Unit | $ / shares																																	25.10
Subordinated Unit | Limited Partners
Distribution Made to Member or Limited Partner [Line Items]
Limited partners' units, issued | shares																																			438,789
Partners' Capital Account, Units, Cash Distribution Threshold, Quarterly Distribution | $ / shares																																	1.30
Partners' Capital Account, Units, Conversion Threshold, Cumulative Distribution | $ / shares																																	$ 5.20
Non-Controlling Partners
Distribution Made to Member or Limited Partner [Line Items]
Contribution from issuance of units																																	$ 0.0
Issuance of preferred equity of subsidiary																																	175.0
Non-Controlling Partners | CMLP
Distribution Made to Member or Limited Partner [Line Items]
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units																																			$ 0.0
Issuance of preferred equity of subsidiary																																	$ 175.0
Limited Partners | CMLP
Distribution Made to Member or Limited Partner [Line Items]
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units																																			$ 0.0
Maximum | Class A Purchasers | Preferred Units, Class A
Distribution Made to Member or Limited Partner [Line Items]
Contribution from issuance of units																														$ 500.0

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Partners' Capital (Schedule of Partnership Distributions) (Details) - USD ($) $ / shares in Units, $ in Millions																											12 Months Ended
	Feb. 14, 2018	Feb. 07, 2018	Nov. 14, 2017	Nov. 07, 2017	Aug. 14, 2017	Aug. 07, 2017	May 15, 2017	May 08, 2017	Feb. 14, 2017	Feb. 07, 2017	Nov. 14, 2016	Nov. 07, 2016	Aug. 12, 2016	Aug. 05, 2016	May 13, 2016	May 06, 2016	Feb. 12, 2016	Feb. 05, 2016	Nov. 13, 2015	Nov. 06, 2015	Aug. 14, 2015	Aug. 07, 2015	May 15, 2015	May 08, 2015	Feb. 13, 2015	Feb. 06, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Disclosure Partners Capital Summary Of Quarterly Distributions Of Available Cash [Abstract]
Distribution to limited partner, record date				Nov. 07, 2017		Aug. 07, 2017		May 08, 2017		Feb. 07, 2017		Nov. 07, 2016		Aug. 05, 2016		May 06, 2016		Feb. 05, 2016		Nov. 06, 2015		Aug. 07, 2015		May 08, 2015		Feb. 06, 2015
Distribution to limited partner, distribution date			Nov. 14, 2017		Aug. 14, 2017		May 15, 2017		Feb. 14, 2017		Nov. 14, 2016		Aug. 12, 2016		May 13, 2016		Feb. 12, 2016		Nov. 13, 2015		Aug. 14, 2015		May 15, 2015		Feb. 13, 2015
Distribution Made to Limited Partner, Distributions Paid, Per Unit			$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 1.3750		$ 1.3750		$ 1.3750		$ 1.3750		$ 1.3750
Distribution amount			$ 42.2		$ 41.8		$ 41.8		$ 41.8		$ 41.4		$ 41.4		$ 41.4		$ 95.6		$ 94.3		$ 25.7		$ 25.7		$ 25.8		$ 167.6	$ 219.8	$ 171.5
Cash distribution | Subsequent Event
Disclosure Partners Capital Summary Of Quarterly Distributions Of Available Cash [Abstract]
Distribution to limited partner, record date		Feb. 07, 2018
Distribution to limited partner, distribution date	Feb. 14, 2018
Distribution declared per limited partner unit	$ 0.600

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Partners' Capital Net Income (Loss) Attributable to NonControlling Partners (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Limited Partners' Capital Account [Line Items]
Net income (loss) attributable to non-controlling partners in subsidiary	$ 25.3	$ 24.2	$ (636.8)
CMLP
Limited Partners' Capital Account [Line Items]
Net income (loss) attributable to non-controlling partners in subsidiary	25.3	24.2	23.1
CMLP | Preferred Units, Class A
Limited Partners' Capital Account [Line Items]
Net income (loss) attributable to non-controlling partners in subsidiary	0.0	0.0	23.1
Crestwood Niobrara LLC
Limited Partners' Capital Account [Line Items]
Net income (loss) attributable to non-controlling partners in subsidiary	25.3	24.2	23.1
Limited Partners | CMLP
Limited Partners' Capital Account [Line Items]
Net income (loss) attributable to non-controlling partners in subsidiary	$ 0.0	$ 0.0	$ (683.0)

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Partners' Capital Schedule of CMLP Partnership Distributions (Details) - USD ($) $ / shares in Units, $ in Millions																									12 Months Ended
	Nov. 14, 2017	Nov. 07, 2017	Aug. 14, 2017	Aug. 07, 2017	May 15, 2017	May 08, 2017	Feb. 14, 2017	Feb. 07, 2017	Nov. 14, 2016	Nov. 07, 2016	Aug. 12, 2016	Aug. 05, 2016	May 13, 2016	May 06, 2016	Feb. 12, 2016	Feb. 05, 2016	Nov. 13, 2015	Nov. 06, 2015	Aug. 14, 2015	Aug. 07, 2015	May 15, 2015	May 08, 2015	Feb. 13, 2015	Feb. 06, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Distribution Made to Limited Liability Company (LLC) Member [Line Items]
Distribution to limited partner, record date		Nov. 07, 2017		Aug. 07, 2017		May 08, 2017		Feb. 07, 2017		Nov. 07, 2016		Aug. 05, 2016		May 06, 2016		Feb. 05, 2016		Nov. 06, 2015		Aug. 07, 2015		May 08, 2015		Feb. 06, 2015
Distribution to limited partner, distribution date	Nov. 14, 2017		Aug. 14, 2017		May 15, 2017		Feb. 14, 2017		Nov. 14, 2016		Aug. 12, 2016		May 13, 2016		Feb. 12, 2016		Nov. 13, 2015		Aug. 14, 2015		May 15, 2015		Feb. 13, 2015
Distribution Made to Limited Partner, Distributions Paid, Per Unit	$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 1.3750		$ 1.3750		$ 1.3750		$ 1.3750		$ 1.3750
Distribution Made to Limited Partner, Cash Distributions Paid	$ 42.2		$ 41.8		$ 41.8		$ 41.8		$ 41.4		$ 41.4		$ 41.4		$ 95.6		$ 94.3		$ 25.7		$ 25.7		$ 25.8		$ 167.6	$ 219.8	$ 171.5
CMLP
Distribution Made to Limited Liability Company (LLC) Member [Line Items]
Distribution to limited partner, record date																				Aug. 07, 2015		May 08, 2015		Feb. 06, 2015
Distribution to limited partner, distribution date																			Aug. 14, 2015		May 15, 2015		Feb. 13, 2015
Distribution Made to Limited Partner, Distributions Paid, Per Unit																			$ 0.41		$ 0.41		$ 0.41
Distribution Made to Limited Partner, Cash Distributions Paid																			$ 74.3		$ 74.3		$ 74.3			$ 222.9

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Equity Plans (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Feb. 12, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 22.4	$ 16.0	$ 11.5
Employer matching contribution, percent	6.00%
Crestwood Long-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Common units to satisfy employee tax withholding obligations	206,600	57,508	26,095
Crestwood Long-Term Incentive Plan | Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation costs not yet recognized	$ 23.7	$ 14.9
Subsequent Event | Crestwood Long-Term Incentive Plan | Restricted units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for future issuance				3,428,811
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier	50.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier	200.00%

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Equity Plans (Schedule of Phantom and Restricted Unit Activity) (Details) - $ / shares													12 Months Ended
	Nov. 14, 2017	Aug. 14, 2017	May 15, 2017	Feb. 14, 2017	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Nov. 13, 2015	Aug. 14, 2015	May 15, 2015	Feb. 13, 2015	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Distribution to limited partner, distribution date	Nov. 14, 2017	Aug. 14, 2017	May 15, 2017	Feb. 14, 2017	Nov. 14, 2016	Aug. 12, 2016	May 13, 2016	Feb. 12, 2016	Nov. 13, 2015	Aug. 14, 2015	May 15, 2015	Feb. 13, 2015
Crestwood Long-Term Incentive Plan | Restricted units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested units - December 31, units													1,292,330	466,214	131,588
Unvested units - December 31													$ 24.67	$ 69.80	$ 132.10
Vested, units													(607,115)	(193,295)	(91,798)
Vested													$ 28.00	$ 76.82	$ 121.13
Granted, units													919,411	1,067,535	142,255
Granted													$ 25.69	$ 14.58	$ 55.25
Share-based Compensation Arrangement by Share-based Payment Award, Other Share Increase (Decrease)															226,401
Share Based Compensation Arrangement By Share Based Payment Award Other Shares Increase Decrease Weighted Average Grant Date Fair Value															$ 68.85
Canceled, units													(140,137)	(65,591)	(20,994)
Canceled													$ 23.73	$ 25.13	$ 89.97
Unvested units - December 31, units													1,830,096	1,292,330	466,214
Unvested units - December 31													$ 25.21	$ 24.67	$ 69.80
Crestwood Long-Term Incentive Plan | Performance Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Vested, units													(31,106)
Vested													$ 30.27
Granted, units													405,620
Granted													$ 30.21
Canceled, units													(24,756)
Canceled													$ 30.45
Crestwood Long-Term Incentive Plan | Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Vested, units															(4,856)
Vested															$ 67.10
Granted, units													15,849	17,467	42,349
Granted													$ 25.02	$ 15.54	$ 62.31
Share-based Compensation Arrangement by Share-based Payment Award, Other Share Increase (Decrease)															41,269
Share Based Compensation Arrangement By Share Based Payment Award Other Shares Increase Decrease Weighted Average Grant Date Fair Value															$ 58.36
Employee Severance | Crestwood Long-Term Incentive Plan | Restricted units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Canceled, units															(7,263)

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Employee Benefit Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Postemployment Benefits [Abstract]
Defined Contribution Plan, Employer Matching Contribution, Percent	90.00%
Defined Benefit Plan, Employee Contributions, Statutory Maximum Per Employee	$ 18,000	$ 18,000	$ 18,000
Defined Contribution Plan Participants Basic Contribution	100.00%
Employer matching contribution, percent	6.00%
Defined Contribution Plan, Requisite Service Period	90 days
Defined Benefit Plan, Plan Assets, Contributions by Employer	$ 4,000,000	$ 3,800,000	$ 4,000,000

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Commitments and Contingencies (Narrative) (Details)		12 Months Ended
	Dec. 13, 2017 USD ($)	Dec. 31, 2017 USD ($) bbl Release	Dec. 31, 2016 USD ($)	Sep. 15, 2015 USD ($)	May 06, 2015 bbl
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Loss Contingency, Number of Plaintiffs		13
Accrued property taxes		$ 4,800,000	$ 4,200,000
Loss Contingency Accrual, at Carrying Value		2,100,000	100,000
Environmental Remediation Expense	$ 49,000
Estimated Environmental Costs	$ 173,000
Accrual for Environmental Loss Contingencies		1,900,000	2,100,000
Other Growth and Maintenance Contractual Purchase Obligations
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Firm Purchase Commitments		63,900,000
Commodity
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Firm Purchase Commitments		479,300,000
Crestwood Equity Partners LP
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Self-insurance reserves		13,600,000	15,600,000
Self-insurance reserve expected to be paid in next fiscal year		9,100,000
CMLP
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Accrued property taxes		4,800,000	4,200,000
Self-insurance reserves		11,600,000	$ 12,200,000
Self-insurance reserve expected to be paid in next fiscal year		$ 7,600,000
Maximum
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Loss Contingency, Number of Plaintiffs		150
Loss Contingency, Estimate of Possible Loss		$ 3,100,000		$ 1,100,000
Minimum
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Loss Contingency, Estimate of Possible Loss		$ 1,900,000
Fort Berthold Indian Reservation
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Site Contingency, Loss Exposure, Number of Releases of Produced Water | Release		3
Site Contingency, Loss Exposure, Release of Produced Water | bbl		28,000			5,200

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Commitments and Contingencies (Schedule of Future Minimum Lease Payments under Noncancelable Operatng Leases) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Commitments and Contingencies Disclosure [Abstract]
2015	$ 35.2
2016	30.1
2017	23.2
2018	11.5
2019	7.7
Thereafter	18.8
Rent expense	34.2	$ 25.5	$ 37.4
Operating Leases, Future Minimum Payments Due	$ 126.5

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Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Related Party Transaction [Line Items]
Gathering and processing revenues at CEQP and CMLP	$ 1.8	$ 2.6	$ 3.9
Related Party Transaction, Due from (to) Related Party [Abstract]
Related Party Transaction, Expenses from Transactions with Related Party	22.3	8.1	3.3
Affiliated Entity
Related Party Transaction [Line Items]
Gathering and processing revenues at CEQP and CMLP	1.8	2.6	3.9
Gathering and processing costs of product sold at CEQP and CMLP(1)	15.3	17.7	28.9
General and administrative expenses charged by CEQP to CMLP, net(3)	19.4	13.0	49.5
CMLP
Related Party Transaction [Line Items]
Gathering and processing revenues at CEQP and CMLP	1.8	2.6	3.9
CMLP | Affiliated Entity
Related Party Transaction [Line Items]
General and administrative expenses charged by CEQP to CMLP, net(3)	3.0	3.0	0.8
Related Party Transaction, Due from (to) Related Party [Abstract]
Accounts payable at CEQP	5.0	0.0
Crestwood Equity Partners LP
Related Party Transaction [Line Items]
Related Party Transaction, (Income) Expenses from Transactions with Related Party	(1.7)	(2.2)	0.4
Crestwood Equity Partners LP | Affiliated Entity
Related Party Transaction, Due from (to) Related Party [Abstract]
Accounts receivable at CEQP and CMLP	7.1	5.6
Accounts payable at CEQP	7.4	2.5
Crestwood Long-Term Incentive Plan | CMLP
Related Party Transaction [Line Items]
Allocated share based compensation expense	22.4	16.0	10.0
Crestwood Long-Term Incentive Plan | Crestwood Holdings
Related Party Transaction [Line Items]
Allocated share based compensation expense	3.1	3.2	0.1
Stagecoach Gas Services LLC
Related Party Transaction, Due from (to) Related Party [Abstract]
Related Party Transaction, Expenses from Transactions with Related Party	8.4	5.0
Tres Palacios Holdings LLC
Related Party Transaction, Due from (to) Related Party [Abstract]
Related Party Transaction, Expenses from Transactions with Related Party	3.5	2.7	2.8
Crestwood Permian Basin Holdings
Related Party Transaction, Due from (to) Related Party [Abstract]
Related Party Transaction, Expenses from Transactions with Related Party	10.0
Jackalope Gas Gathering Services, LLC
Related Party Transaction, Due from (to) Related Party [Abstract]
Related Party Transaction, Expenses from Transactions with Related Party	$ 0.4	$ 0.4	$ 0.5

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Segments (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2017 USD ($)	Dec. 31, 2017	Dec. 31, 2017 segment	Dec. 31, 2017 reporting_units	Dec. 31, 2016 USD ($)	Dec. 31, 2015 USD ($)
Revenue, Major Customer [Line Items]
Number of operating segments			3	3
Concentration Risk, Percentage		10.00%			10.00%	10.00%
Revenues	$ 3,880.9				$ 2,520.5	$ 2,632.8
Crestwood Equity Partners LP
Revenue, Major Customer [Line Items]
Earnings (Losses) Before Interest, Taxes, Depreciation and Amortization from Equity Method Investments	32.5				29.6	86.1
CMLP
Revenue, Major Customer [Line Items]
Revenues	$ 3,880.9				$ 2,520.5	$ 2,632.8

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Segments (Reconciliation of Net Income (Loss) to EBITDA) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Net loss		$ (166.6)	$ (192.1)	$ (2,303.7)
Interest and debt expense, net		(99.4)	(125.1)	(140.1)
(Gain) loss on modification/extinguishment of debt	$ (10.0)	37.7	(10.0)	20.0
(Provision) benefit for income taxes		(0.8)	0.3	(1.4)
Depreciation, amortization and accretion		191.7	229.6	300.1
EBITDA		161.4	152.9	(1,844.9)
CMLP
Segment Reporting Information [Line Items]
Net loss		(175.5)	(197.5)	(1,410.6)
Interest and debt expense, net		(99.4)	(125.1)	(130.5)
(Gain) loss on modification/extinguishment of debt		37.7	(10.0)	18.9
(Provision) benefit for income taxes		0.0	0.0	0.0
Depreciation, amortization and accretion		202.7	240.5	278.5
EBITDA		$ 164.3	$ 158.1	$ (982.7)

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Segments (Summary Of Segment Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Operating revenues	$ 3,880.9	$ 2,520.5	$ 2,632.8
Intersegment Revenues	0.0	0.0	0.0
Costs of product/services sold	3,374.7	1,925.1	1,883.5
Operations and maintenance	136.0	158.1	190.2
General and administrative	96.5	88.2	116.3
Loss on long-lived assets, net	(65.6)	(65.6)	(821.2)
Goodwill impairment	(38.8)	(162.6)	(1,406.3)
Loss on contingent consideration	(57.0)	0.0	0.0
Earnings (loss) from unconsolidated affiliates, net	47.8	31.5	(60.8)
Other income, net	1.3	0.5	0.6
EBITDA	161.4	152.9	(1,844.9)
Goodwill	147.6	199.0
Assets	4,284.9	4,448.9
Payments to Acquire Property, Plant, and Equipment	188.4	100.7	182.7
CMLP
Segment Reporting Information [Line Items]
Operating revenues	3,880.9	2,520.5	2,632.8
Intersegment Revenues	0.0	0.0	0.0
Costs of product/services sold	3,374.7	1,925.1	1,883.5
Operations and maintenance	136.0	155.0	188.7
General and administrative	93.1	85.6	105.6
Loss on long-lived assets, net	(65.6)	(65.6)	(227.8)
Goodwill impairment	(38.8)	(162.6)	(1,149.1)
Loss on contingent consideration	(57.0)	0.0	0.0
Earnings (loss) from unconsolidated affiliates, net	47.8	31.5	(60.8)
Other income, net	0.8
EBITDA	164.3	158.1	(982.7)
Goodwill	147.6	199.0	1,085.5
Assets	4,466.3	4,640.6
Payments to Acquire Property, Plant, and Equipment	188.4	100.7	182.7
Gathering systems and pipelines and related assets
Segment Reporting Information [Line Items]
Operating revenues	1,688.2	1,118.8	1,381.0
Intersegment Revenues	134.5	108.6	66.7
Costs of product/services sold	1,480.8	917.0	1,103.9
Operations and maintenance	68.4	77.0	89.0
General and administrative	0.0	0.0	0.0
Loss on long-lived assets, net	(14.4)	(2.0)	(787.3)
Goodwill impairment	0.0	(8.6)	(329.7)
Loss on contingent consideration	0.0
Earnings (loss) from unconsolidated affiliates, net	18.9	20.3	(43.4)
Other income, net	0.8	0.0	0.0
EBITDA	278.8	243.1	(905.6)
Goodwill	45.9	45.9
Assets	2,474.1	2,359.7
Payments to Acquire Property, Plant, and Equipment	162.7	76.6	132.7
Gathering systems and pipelines and related assets | CMLP
Segment Reporting Information [Line Items]
Operating revenues	1,688.2	1,118.8	1,381.0
Intersegment Revenues	134.5	108.6	66.7
Costs of product/services sold	1,480.8	917.0	1,103.9
Operations and maintenance	68.4	77.0	89.0
General and administrative	0.0	0.0	0.0
Loss on long-lived assets, net	(14.4)	(2.0)	(194.1)
Goodwill impairment	0.0	(8.6)	(72.5)
Loss on contingent consideration	0.0
Earnings (loss) from unconsolidated affiliates, net	18.9	20.3	(43.4)
Other income, net	0.8
EBITDA	278.8	243.1	(55.2)
Goodwill	45.9	45.9
Assets	2,662.0	2,561.9
Payments to Acquire Property, Plant, and Equipment	162.7	76.6	132.7
Storage and Transportation
Segment Reporting Information [Line Items]
Operating revenues	37.2	165.3	266.3
Intersegment Revenues	6.7	4.2	0.0
Costs of product/services sold	0.3	5.1	20.1
Operations and maintenance	4.2	21.4	31.7
General and administrative	0.0	0.0	0.0
Loss on long-lived assets, net	0.0	(32.2)	(1.6)
Goodwill impairment	0.0	(44.9)	(623.4)
Loss on contingent consideration	(57.0)
Earnings (loss) from unconsolidated affiliates, net	28.9	11.2	(17.4)
Other income, net	0.0	0.0	0.0
EBITDA	11.3	77.1	(427.9)
Goodwill	0.0	0.0
Assets	1,040.6	1,094.6
Payments to Acquire Property, Plant, and Equipment	1.3	3.3	26.4
Storage and Transportation | CMLP
Segment Reporting Information [Line Items]
Operating revenues	37.2	165.3	266.3
Intersegment Revenues	6.7	4.2	0.0
Costs of product/services sold	0.3	5.1	20.1
Operations and maintenance	4.2	18.3	30.2
General and administrative	0.0	0.0	0.0
Loss on long-lived assets, net	0.0	(32.2)	(1.4)
Goodwill impairment	0.0	(44.9)	(623.4)
Loss on contingent consideration	(57.0)
Earnings (loss) from unconsolidated affiliates, net	28.9	11.2	(17.4)
Other income, net	0.0
EBITDA	11.3	80.2	(426.2)
Goodwill	0.0	0.0
Assets	1,040.6	1,094.6
Payments to Acquire Property, Plant, and Equipment	1.3	3.3	26.4
Marketing Supply and Logistics
Segment Reporting Information [Line Items]
Operating revenues	2,155.5	1,236.4	985.5
Intersegment Revenues	(141.2)	(112.8)	(66.7)
Costs of product/services sold	1,893.6	1,003.0	759.5
Operations and maintenance	63.4	59.7	69.5
General and administrative	0.0	0.0	0.0
Loss on long-lived assets, net	(48.2)	(31.4)	(32.3)
Goodwill impairment	(38.8)	(109.1)	(453.2)
Loss on contingent consideration	0.0
Earnings (loss) from unconsolidated affiliates, net	0.0	0.0	0.0
Other income, net	0.0	0.0	0.0
EBITDA	(29.7)	(79.6)	(395.7)
Goodwill	101.7	153.1
Assets	757.1	972.2
Payments to Acquire Property, Plant, and Equipment	17.7	19.1	22.8
Marketing Supply and Logistics | CMLP
Segment Reporting Information [Line Items]
Operating revenues	2,155.5	1,236.4	985.5
Intersegment Revenues	(141.2)	(112.8)	(66.7)
Costs of product/services sold	1,893.6	1,003.0	759.5
Operations and maintenance	63.4	59.7	69.5
General and administrative	0.0	0.0	0.0
Loss on long-lived assets, net	(48.2)	(31.4)	(32.3)
Goodwill impairment	(38.8)	(109.1)	(453.2)
Loss on contingent consideration	0.0
Earnings (loss) from unconsolidated affiliates, net	0.0	0.0	0.0
Other income, net	0.0
EBITDA	(29.7)	(79.6)	(395.7)
Goodwill	101.7	153.1
Assets	757.1	972.2
Payments to Acquire Property, Plant, and Equipment	17.7	19.1	22.8
Corporate Segment
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0	0.0
Intersegment Revenues	0.0	0.0	0.0
Costs of product/services sold	0.0	0.0	0.0
Operations and maintenance	0.0	0.0	0.0
General and administrative	96.5	88.2	116.3
Loss on long-lived assets, net	(3.0)	0.0	0.0
Goodwill impairment	0.0	0.0	0.0
Loss on contingent consideration	0.0
Earnings (loss) from unconsolidated affiliates, net	0.0	0.0	0.0
Other income, net	0.5	0.5	0.6
EBITDA	(99.0)	(87.7)	(115.7)
Goodwill	0.0	0.0
Assets	13.1	22.4
Payments to Acquire Property, Plant, and Equipment	6.7	1.7	0.8
Corporate Segment | CMLP
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0	0.0
Intersegment Revenues	0.0	0.0	0.0
Costs of product/services sold	0.0	0.0	0.0
Operations and maintenance	0.0	0.0	0.0
General and administrative	93.1	85.6	105.6
Loss on long-lived assets, net	(3.0)	0.0	0.0
Goodwill impairment	0.0	0.0	0.0
Loss on contingent consideration	0.0
Earnings (loss) from unconsolidated affiliates, net	0.0	0.0	0.0
Other income, net	0.0
EBITDA	(96.1)	(85.6)	(105.6)
Goodwill	0.0	0.0
Assets	6.6	11.9
Payments to Acquire Property, Plant, and Equipment	$ 6.7	$ 1.7	$ 0.8

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Condensed Consolidating Financial Information (Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current assets:
Cash	$ 1.3	$ 1.6	$ 0.5	$ 8.8
Accounts receivable	442.7	289.8
Inventory	68.4	66.0
Total current assets	530.5	373.4
Property, plant and equipment, net	1,820.8	2,097.6
Investments in unconsolidated affiliates	1,183.0	1,115.4
Other assets	5.8	6.1
Total assets	4,284.9	4,448.9
Current liabilities:
Accounts payable	349.4	217.2
Total current liabilities	505.1	337.3
Long-term liabilities:
Long-term debt, less current portion	1,491.3	1,522.7
Other long-term liabilities	104.7	44.6
Deferred income taxes	3.3	5.3
Total partners’ capital	2,180.5	2,539.0	2,946.9	5,584.5
Total liabilities and partners’ capital	4,284.9	4,448.9
Eliminations
Current assets:
Cash	0.0	0.0	0.0	0.0
Accounts receivable	0.0	0.0
Inventory	0.0	0.0
Other	0.0	0.0
Total current assets	0.0	0.0
Property, plant and equipment, net	0.0	0.0
Intangible Assets, Net (Including Goodwill)	0.0	0.0
Investments in consolidated affiliates	(3,705.4)	(4,093.7)
Investments in unconsolidated affiliates	0.0	0.0
Other assets	0.0	0.0
Total assets	(3,705.4)	(4,093.7)
Current liabilities:
Accounts payable	0.0	0.0
Total current liabilities	0.0	0.0
Total current liabilities	0.0	0.0
Long-term liabilities:
Long-term debt, less current portion	0.0	0.0
Other long-term liabilities	0.0	0.0
Deferred income taxes	0.0	0.0
Partners' capital	(3,705.4)	(4,093.7)
Interest of non-controlling partners in subsidiary	0.0	0.0
Total partners’ capital	(3,705.4)	(4,093.7)
Total liabilities and partners’ capital	(3,705.4)	(4,093.7)
Parent Company, Crestwood Midstream Partners, LP | Reportable Legal Entities
Current assets:
Cash	1.0	1.3	0.1	0.0
Accounts receivable	0.0	0.0
Inventory	0.0	0.0
Other	0.0	0.0
Total current assets	1.0	1.3
Property, plant and equipment, net	0.0	0.0
Intangible Assets, Net (Including Goodwill)	0.0	0.0
Investments in consolidated affiliates	3,705.4	4,093.7
Investments in unconsolidated affiliates	0.0	0.0
Other assets	0.0	0.0
Total assets	3,706.4	4,095.0
Current liabilities:
Accounts payable	0.0	0.0
Total current liabilities	20.5	23.1
Total current liabilities	20.5	23.1
Long-term liabilities:
Long-term debt, less current portion	1,490.5	1,521.2
Other long-term liabilities	0.0	0.0
Deferred income taxes	0.0	0.0
Partners' capital	2,195.4	2,550.7
Interest of non-controlling partners in subsidiary	0.0	0.0
Total partners’ capital	2,195.4	2,550.7
Total liabilities and partners’ capital	3,706.4	4,095.0
Guarantor Subsidiaries | Reportable Legal Entities
Current assets:
Cash	0.0	0.0	0.0	7.6
Accounts receivable	439.7	289.3
Inventory	68.4	66.0
Other	18.1	16.0
Total current assets	526.2	371.3
Property, plant and equipment, net	2,007.5	2,298.4
Intangible Assets, Net (Including Goodwill)	743.3	851.9
Investments in consolidated affiliates	0.0	0.0
Investments in unconsolidated affiliates	0.0	0.0
Other assets	2.4	1.8
Total assets	3,279.4	3,523.4
Current liabilities:
Accounts payable	346.8	214.5
Total current liabilities	134.0	94.4
Total current liabilities	480.8	308.9
Long-term liabilities:
Long-term debt, less current portion	0.8	1.5
Other long-term liabilities	45.6	42.0
Deferred income taxes	0.7	0.7
Partners' capital	2,751.5	3,170.3
Interest of non-controlling partners in subsidiary	0.0	0.0
Total partners’ capital	2,751.5	3,170.3
Total liabilities and partners’ capital	3,279.4	3,523.4
Non-Guarantor Subsidiaries | Reportable Legal Entities
Current assets:
Cash	0.0	0.0	0.0	0.0
Accounts receivable	2.9	0.5
Inventory	0.0	0.0
Other	0.0	0.0
Total current assets	2.9	0.5
Property, plant and equipment, net	0.0	0.0
Intangible Assets, Net (Including Goodwill)	0.0	0.0
Investments in consolidated affiliates	0.0	0.0
Investments in unconsolidated affiliates	1,183.0	1,115.4
Other assets	0.0	0.0
Total assets	1,185.9	1,115.9
Current liabilities:
Accounts payable	0.0	0.0
Total current liabilities	0.0	0.0
Total current liabilities	0.0	0.0
Long-term liabilities:
Long-term debt, less current portion	0.0	0.0
Other long-term liabilities	57.0	0.0
Deferred income taxes	0.0	0.0
Partners' capital	953.9	923.4
Interest of non-controlling partners in subsidiary	175.0	192.5
Total partners’ capital	1,128.9	1,115.9
Total liabilities and partners’ capital	1,185.9	1,115.9
CMLP
Current assets:
Cash	1.0	1.3	$ 0.1	$ 7.6
Accounts receivable	442.6	289.8
Inventory	68.4	66.0
Other	18.1	16.0
Total current assets	530.1	373.1
Property, plant and equipment, net	2,007.5	2,298.4
Intangible Assets, Net (Including Goodwill)	743.3	851.9
Investments in consolidated affiliates	0.0	0.0
Investments in unconsolidated affiliates	1,183.0	1,115.4
Other assets	2.4	1.8
Total assets	4,466.3	4,640.6
Current liabilities:
Accounts payable	346.8	214.5
Total current liabilities	154.5	117.5
Total current liabilities	501.3	332.0
Long-term liabilities:
Long-term debt, less current portion	1,491.3	1,522.7
Other long-term liabilities	102.6	42.0
Deferred income taxes	0.7	0.7
Partners' capital	2,195.4	2,550.7
Interest of non-controlling partners in subsidiary	175.0	192.5
Total partners’ capital	2,370.4	2,743.2
Total liabilities and partners’ capital	$ 4,466.3	$ 4,640.6

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Condensed Consolidating Financial Information (Statements Of Operations) (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Revenues:
Storage and transportation		$ 37.2	$ 165.3	$ 266.3
Related party (Note 16)		1.8	2.6	3.9
Revenues		3,880.9	2,520.5	2,632.8
Costs of product/services sold (exclusive of items shown separately below):
Product costs - related party (Note 16)		15.3	17.7	28.9
Total costs of products/services sold		3,374.7	1,925.1	1,883.5
Expenses:
Operations and maintenance		136.0	158.1	190.2
General and administrative		96.5	88.2	116.3
Depreciation, amortization and accretion		191.7	229.6	300.1
Loss on long-lived assets, net		(65.6)	(65.6)	(821.2)
Goodwill impairment		(38.8)	(162.6)	(1,406.3)
Loss on contingent consideration		(57.0)	0.0	0.0
Operating income (loss)		(79.4)	(108.7)	(2,084.8)
Other income (expense):
Earnings (loss) from unconsolidated affiliates, net		47.8	31.5	(60.8)
Interest and debt expense, net		(99.4)	(125.1)	(140.1)
Gain (loss) on modification/extinguishment of debt	$ 10.0	(37.7)	10.0	(20.0)
Other income, net		1.3	0.5	0.6
Loss before income taxes		(167.4)	(191.8)	(2,305.1)
(Provision) benefit for income taxes		0.8	(0.3)	1.4
Net loss		(166.6)	(192.1)	(2,303.7)
Net income attributable to non-controlling partners in subsidiary		25.3	24.2	(636.8)
Net income (loss) attributable to parent		(191.9)	(216.3)	(1,666.9)
Net income attributable to preferred units		62.5	28.7	6.2
Net income (loss) attributable to partners		(254.4)	(245.0)	(1,673.1)
Eliminations
Revenues:
Revenues		0.0	0.0	0.0
Costs of product/services sold (exclusive of items shown separately below):
Total costs of products/services sold		0.0	0.0	0.0
Expenses:
Operations and maintenance		0.0	0.0	0.0
General and administrative		0.0	0.0	0.0
Depreciation, amortization and accretion		0.0	0.0	0.0
Costs and Expenses		0.0	0.0	0.0
Loss on long-lived assets, net		0.0	0.0	0.0
Goodwill impairment		0.0	0.0	0.0
Loss on contingent consideration		0.0
Operating income (loss)		0.0	0.0	0.0
Other income (expense):
Earnings (loss) from unconsolidated affiliates, net		0.0	0.0	0.0
Interest and debt expense, net		0.0	0.0	0.0
Gain (loss) on modification/extinguishment of debt		0.0	0.0	0.0
Other income, net		0.0
Loss from unconsolidated affiliates		(3.9)	40.2	1,219.0
Net loss		(3.9)	40.2	1,219.0
Net income attributable to non-controlling partners in subsidiary		0.0	0.0	0.0
Net income (loss) attributable to parent		(3.9)	40.2	1,219.0
Net income attributable to preferred units				0.0
Net income (loss) attributable to partners				1,219.0
Parent Company, Crestwood Midstream Partners, LP | Reportable Legal Entities
Revenues:
Revenues		0.0	0.0	0.0
Costs of product/services sold (exclusive of items shown separately below):
Total costs of products/services sold		0.0	0.0	0.0
Expenses:
Operations and maintenance		0.0	0.0	0.0
General and administrative		67.6	66.4	65.3
Depreciation, amortization and accretion		0.0	0.0	0.0
Costs and Expenses		67.6	66.4	65.3
Loss on long-lived assets, net		0.0	0.0	0.0
Goodwill impairment		0.0	0.0	0.0
Loss on contingent consideration		0.0
Operating income (loss)		(67.6)	(66.4)	(65.3)
Other income (expense):
Earnings (loss) from unconsolidated affiliates, net		0.0	0.0	0.0
Interest and debt expense, net		(99.4)	(125.1)	(130.5)
Gain (loss) on modification/extinguishment of debt		(37.7)	10.0	(18.9)
Other income, net		0.0
Loss from unconsolidated affiliates		3.9	(40.2)	(1,219.0)
Net loss		(200.8)	(221.7)	(1,433.7)
Net income attributable to non-controlling partners in subsidiary		0.0	0.0	0.0
Net income (loss) attributable to parent		(200.8)	(221.7)	(1,433.7)
Net income attributable to preferred units				23.1
Net income (loss) attributable to partners				(1,456.8)
Guarantor Subsidiaries | Reportable Legal Entities
Revenues:
Revenues		3,880.9	2,520.5	2,632.8
Costs of product/services sold (exclusive of items shown separately below):
Total costs of products/services sold		3,374.7	1,925.1	1,883.5
Expenses:
Operations and maintenance		136.0	155.0	188.7
General and administrative		25.5	19.2	40.3
Depreciation, amortization and accretion		202.7	240.5	278.5
Costs and Expenses		364.2	414.7	507.5
Loss on long-lived assets, net		(65.6)	(65.6)	(227.8)
Goodwill impairment		(38.8)	(162.6)	(1,149.1)
Loss on contingent consideration		0.0
Operating income (loss)		37.6	(47.5)	(1,135.1)
Other income (expense):
Earnings (loss) from unconsolidated affiliates, net		0.0	0.0	0.0
Interest and debt expense, net		0.0	0.0	0.0
Gain (loss) on modification/extinguishment of debt		0.0	0.0	0.0
Other income, net		0.8
Loss from unconsolidated affiliates		0.0	0.0	0.0
Net loss		38.4	(47.5)	(1,135.1)
Net income attributable to non-controlling partners in subsidiary		0.0	0.0	0.0
Net income (loss) attributable to parent		38.4	(47.5)	(1,135.1)
Net income attributable to preferred units				0.0
Net income (loss) attributable to partners				(1,135.1)
Non-Guarantor Subsidiaries | Reportable Legal Entities
Revenues:
Revenues		0.0	0.0	0.0
Costs of product/services sold (exclusive of items shown separately below):
Total costs of products/services sold		0.0	0.0	0.0
Expenses:
Operations and maintenance		0.0	0.0	0.0
General and administrative		0.0	0.0	0.0
Depreciation, amortization and accretion		0.0	0.0	0.0
Costs and Expenses		0.0	0.0	0.0
Loss on long-lived assets, net		0.0	0.0	0.0
Goodwill impairment		0.0	0.0	0.0
Loss on contingent consideration		(57.0)
Operating income (loss)		(57.0)	0.0	0.0
Other income (expense):
Earnings (loss) from unconsolidated affiliates, net		47.8	31.5	(60.8)
Interest and debt expense, net		0.0	0.0	0.0
Gain (loss) on modification/extinguishment of debt		0.0	0.0	0.0
Other income, net		0.0
Loss from unconsolidated affiliates		0.0	0.0	0.0
Net loss		(9.2)	31.5	(60.8)
Net income attributable to non-controlling partners in subsidiary		25.3	24.2	23.1
Net income (loss) attributable to parent		(34.5)	7.3	(83.9)
Net income attributable to preferred units				0.0
Net income (loss) attributable to partners				(83.9)
CMLP
Revenues:
Revenues		3,880.9	2,520.5	2,632.8
Costs of product/services sold (exclusive of items shown separately below):
Total costs of products/services sold		3,374.7	1,925.1	1,883.5
Expenses:
Operations and maintenance		136.0	155.0	188.7
General and administrative		93.1	85.6	105.6
Depreciation, amortization and accretion		202.7	240.5	278.5
Costs and Expenses		431.8	481.1	572.8
Loss on long-lived assets, net		(65.6)	(65.6)	(227.8)
Goodwill impairment		(38.8)	(162.6)	(1,149.1)
Loss on contingent consideration		(57.0)
Operating income (loss)		(87.0)	(113.9)	(1,200.4)
Other income (expense):
Earnings (loss) from unconsolidated affiliates, net		47.8	31.5	(60.8)
Interest and debt expense, net		(99.4)	(125.1)	(130.5)
Gain (loss) on modification/extinguishment of debt		(37.7)	10.0	(18.9)
Other income, net		0.8
Loss from unconsolidated affiliates		0.0	0.0	0.0
Net loss		(175.5)	(197.5)	(1,410.6)
Net income attributable to non-controlling partners in subsidiary		25.3	24.2	23.1
Net income (loss) attributable to parent		$ (200.8)	$ (221.7)	(1,433.7)
Net income attributable to preferred units				23.1
Net income (loss) attributable to partners				$ (1,456.8)

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Condensed Consolidating Financial Information (Statements Of Cash Flows) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash flows from operating activities		$ 255.9	$ 346.1	$ 440.7
Cash flows from investing activities:
Payments to Acquire Businesses, Net of Cash Acquired		0.0	7.2	0.0
Purchases of property, plant and equipment		(188.4)	(100.7)	(182.7)
Investment in unconsolidated affiliates		(58.0)	(12.4)	(42.0)
Net proceeds from sale of assets		225.2	972.7	2.7
Capital distributions from unconsolidated affiliates		59.9	14.8	9.3
Net cash provided by (used in) investing activities		38.7	867.2	(212.7)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		2,838.6	1,565.3	4,261.8
Payments on long-term debt		(2,913.9)	(2,536.3)	(4,113.0)
Payments on capital leases		(2.7)	(1.9)	(2.2)
Payments for debt-related deferred costs		(1.0)	(3.5)	(17.3)
Payments for Repurchase of Redeemable Noncontrolling Interest	$ (202.7)	(202.7)	0.0	0.0
Financing fees paid for early debt redemption		0.0	0.0	(13.6)
Distributions to partners		(167.6)	(219.8)	(171.5)
Net proceeds from issuance of preferred equity of subsidiary	(175.0)	(175.0)	0.0	0.0
Taxes paid for unit-based compensation vesting		(5.5)	(0.8)	(3.8)
Other		(0.1)	0.0	(1.3)
Net cash used in financing activities		(294.9)	(1,212.2)	(236.3)
Net change in cash		(0.3)	1.1	(8.3)
Cash at beginning of period		1.6	0.5	8.8
Cash at end of period	1.3	1.3	1.6	0.5
Eliminations
Cash flows from operating activities		0.0	0.0	0.0
Cash flows from investing activities:
Payments to Acquire Businesses, Net of Cash Acquired			0.0
Purchases of property, plant and equipment		0.0	0.0	0.0
Investment in unconsolidated affiliates		0.0	0.0	0.0
Net proceeds from sale of assets		0.0	0.0	0.0
Capital distributions from unconsolidated affiliates		0.0	0.0	0.0
Contributions to (Distributions from) Consolidated Affiliates		(4.3)	(26.2)	31.2
Net cash provided by (used in) investing activities		(4.3)	(26.2)	31.2
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		0.0	0.0	0.0
Payments on long-term debt		0.0	0.0	0.0
Payments on capital leases		0.0	0.0	0.0
Payments for debt-related deferred costs		0.0	0.0	0.0
Payments for Repurchase of Redeemable Noncontrolling Interest		0.0
Financing fees paid for early debt redemption				0.0
Distributions to partners		0.0	0.0	0.0
Contributions from (Distributions to) Parent		4.3	26.2	(31.2)
Net proceeds from issuance of preferred equity of subsidiary		0.0
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units				0.0
Taxes paid for unit-based compensation vesting		0.0	0.0	0.0
Change in intercompany balances		0.0	0.0	0.0
Other		0.0		0.0
Net cash used in financing activities		4.3	26.2	(31.2)
Net change in cash		0.0	0.0	0.0
Cash at beginning of period		0.0	0.0	0.0
Cash at end of period	0.0	0.0	0.0	0.0
Parent Company, Crestwood Midstream Partners, LP | Reportable Legal Entities
Cash flows from operating activities		(162.3)	(188.0)	(190.8)
Cash flows from investing activities:
Payments to Acquire Businesses, Net of Cash Acquired			0.0
Purchases of property, plant and equipment		(6.7)	(1.7)	(0.8)
Investment in unconsolidated affiliates		0.0	0.0	0.0
Net proceeds from sale of assets		0.0	0.0	0.0
Capital distributions from unconsolidated affiliates		0.0	0.0	0.0
Contributions to (Distributions from) Consolidated Affiliates		4.3	26.2	(31.2)
Net cash provided by (used in) investing activities		(2.4)	24.5	(32.0)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		2,838.6	1,565.3	3,490.1
Payments on long-term debt		(2,912.6)	(2,535.3)	(2,960.9)
Payments on capital leases		0.0	0.0	0.0
Payments for debt-related deferred costs		(1.0)	(3.5)	(17.3)
Payments for Repurchase of Redeemable Noncontrolling Interest		0.0
Financing fees paid for early debt redemption				(13.6)
Distributions to partners		(174.0)	(227.6)	(808.2)
Contributions from (Distributions to) Parent		0.0	0.0	0.0
Net proceeds from issuance of preferred equity of subsidiary		0.0
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units				(58.8)
Taxes paid for unit-based compensation vesting		0.0	0.0	0.0
Change in intercompany balances		413.4	1,365.8	474.1
Other		0.0		(0.1)
Net cash used in financing activities		164.4	164.7	222.9
Net change in cash		(0.3)	1.2	0.1
Cash at beginning of period		1.3	0.1	0.0
Cash at end of period	1.0	1.0	1.3	0.1
CMLP
Cash flows from operating activities		262.2	353.8	471.8
Cash flows from investing activities:
Payments to Acquire Businesses, Net of Cash Acquired			7.2
Purchases of property, plant and equipment		(188.4)	(100.7)	(182.7)
Investment in unconsolidated affiliates		(58.0)	(12.4)	(41.8)
Net proceeds from sale of assets		225.2	972.7	2.7
Capital distributions from unconsolidated affiliates		59.9	14.8	9.3
Contributions to (Distributions from) Consolidated Affiliates		0.0	0.0	0.0
Net cash provided by (used in) investing activities		38.7	867.2	(212.5)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		2,838.6	1,565.3	3,490.1
Payments on long-term debt		(2,913.9)	(2,536.1)	(2,960.9)
Payments on capital leases		(2.7)	(1.9)	(2.2)
Payments for debt-related deferred costs		(1.0)	(3.5)	(17.3)
Payments for Repurchase of Redeemable Noncontrolling Interest		(202.7)
Financing fees paid for early debt redemption				(13.6)
Distributions to partners		(189.2)	(242.8)	(819.5)
Contributions from (Distributions to) Parent		0.0	0.0	0.0
Net proceeds from issuance of preferred equity of subsidiary		(175.0)
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units				(58.8)
Taxes paid for unit-based compensation vesting		(5.5)	(0.8)	(2.1)
Change in intercompany balances		0.0	0.0	0.0
Other		0.2		(0.1)
Net cash used in financing activities		(301.2)	(1,219.8)	(266.8)
Net change in cash		(0.3)	1.2	(7.5)
Cash at beginning of period		1.3	0.1	7.6
Cash at end of period	1.0	1.0	1.3	0.1
Non-Guarantor Subsidiaries | Reportable Legal Entities
Cash flows from operating activities		45.3	39.0	12.6
Cash flows from investing activities:
Payments to Acquire Businesses, Net of Cash Acquired			0.0
Purchases of property, plant and equipment		0.0	0.0	0.0
Investment in unconsolidated affiliates		(58.0)	(12.4)	(41.8)
Net proceeds from sale of assets		0.0	0.0	0.0
Capital distributions from unconsolidated affiliates		59.9	14.8	9.3
Contributions to (Distributions from) Consolidated Affiliates		0.0	0.0	0.0
Net cash provided by (used in) investing activities		1.9	2.4	(32.5)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		0.0	0.0	0.0
Payments on long-term debt		0.0	0.0	0.0
Payments on capital leases		0.0	0.0	0.0
Payments for debt-related deferred costs		0.0	0.0	0.0
Payments for Repurchase of Redeemable Noncontrolling Interest		(202.7)
Financing fees paid for early debt redemption				0.0
Distributions to partners		(15.2)	(15.2)	(11.3)
Contributions from (Distributions to) Parent		(4.3)	(26.2)	31.2
Net proceeds from issuance of preferred equity of subsidiary		(175.0)
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units				0.0
Taxes paid for unit-based compensation vesting		0.0	0.0	0.0
Change in intercompany balances		0.0	0.0	0.0
Other		0.0		0.0
Net cash used in financing activities		(47.2)	(41.4)	19.9
Net change in cash		0.0	0.0	0.0
Cash at beginning of period		0.0	0.0	0.0
Cash at end of period	0.0	0.0	0.0	0.0
Guarantor Subsidiaries | Reportable Legal Entities
Cash flows from operating activities		379.2	502.8	650.0
Cash flows from investing activities:
Payments to Acquire Businesses, Net of Cash Acquired			7.2
Purchases of property, plant and equipment		(181.7)	(99.0)	(181.9)
Investment in unconsolidated affiliates		0.0	0.0	0.0
Net proceeds from sale of assets		225.2	972.7	2.7
Capital distributions from unconsolidated affiliates		0.0	0.0	0.0
Contributions to (Distributions from) Consolidated Affiliates		0.0	0.0	0.0
Net cash provided by (used in) investing activities		43.5	866.5	(179.2)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		0.0	0.0	0.0
Payments on long-term debt		(1.3)	(0.8)	0.0
Payments on capital leases		(2.7)	(1.9)	(2.2)
Payments for debt-related deferred costs		0.0	0.0	0.0
Payments for Repurchase of Redeemable Noncontrolling Interest		0.0
Financing fees paid for early debt redemption				0.0
Distributions to partners		0.0	0.0	0.0
Contributions from (Distributions to) Parent		0.0	0.0	0.0
Net proceeds from issuance of preferred equity of subsidiary		0.0
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units				0.0
Taxes paid for unit-based compensation vesting		(5.5)	(0.8)	(2.1)
Change in intercompany balances		(413.4)	(1,365.8)	(474.1)
Other		0.2		0.0
Net cash used in financing activities		(422.7)	(1,369.3)	(478.4)
Net change in cash		0.0	0.0	(7.6)
Cash at beginning of period		0.0	0.0	7.6
Cash at end of period	0.0	0.0	0.0	0.0
CMLP
Cash flows from operating activities		262.2	353.8	471.8
Cash flows from investing activities:
Payments to Acquire Businesses, Net of Cash Acquired		0.0	7.2	0.0
Purchases of property, plant and equipment		(188.4)	(100.7)	(182.7)
Investment in unconsolidated affiliates		(58.0)	(12.4)	(41.8)
Net proceeds from sale of assets		225.2	972.7	2.7
Capital distributions from unconsolidated affiliates		59.9	14.8	9.3
Net cash provided by (used in) investing activities		38.7	867.2	(212.5)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		2,838.6	1,565.3	3,490.1
Payments on long-term debt		(2,913.9)	(2,536.1)	(2,960.9)
Payments on capital leases		(2.7)	(1.9)	(2.2)
Payments for debt-related deferred costs		(1.0)	(3.5)	(17.3)
Payments for Repurchase of Redeemable Noncontrolling Interest		(202.7)	0.0
Financing fees paid for early debt redemption		0.0	0.0	(13.6)
Distributions to partners		(189.2)	(242.8)	(819.5)
Net proceeds from issuance of preferred equity of subsidiary		(175.0)	0.0	0.0
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units		0.0	0.0	(58.8)
Taxes paid for unit-based compensation vesting		(5.5)	(0.8)	(2.1)
Other		0.2	0.0	(0.1)
Net cash used in financing activities		(301.2)	(1,219.8)	(266.8)
Net change in cash		(0.3)	1.2	(7.5)
Cash at beginning of period		1.3	0.1	7.6
Cash at end of period	$ 1.0	$ 1.0	$ 1.3	$ 0.1

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Schedule I - Crestwood Equity Partners LP - Parent Only - Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Condensed Financial Statements, Captions [Line Items]
Cash	$ 1.3	$ 1.6	$ 0.5	$ 8.8
Total current assets	530.5	373.4
Property, plant and equipment, net	1,820.8	2,097.6
Total assets	4,284.9	4,448.9
Accrued expenses	105.9	90.5
Current portion of long-term debt	0.9	1.0
Total current liabilities	505.1	337.3
Long-term debt, less current portion	1,491.3	1,522.7
Other long-term liabilities	104.7	44.6
Total partners’ capital	2,180.5	2,539.0	2,946.9	5,584.5
Total liabilities and partners’ capital	4,284.9	4,448.9
Parent Company
Condensed Financial Statements, Captions [Line Items]
Cash	0.3	0.3	$ 0.4	$ 3.7
Total current assets	0.3	0.3
Property, plant and equipment, net	1.2	1.4
Intangible assets, net	1.4	4.5
Investments in subsidiaries	2,005.1	2,342.7
Other assets	3.5	4.3
Total assets	2,011.5	2,353.2
Accounts payable	2.7	2.7
Accrued expenses	1.2	1.4
Total current liabilities	3.9	4.1
Other long-term liabilities	2.1	2.6
Total partners’ capital	2,005.5	2,346.5
Total liabilities and partners’ capital	$ 2,011.5	$ 2,353.2

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Schedule I - Crestwood Equity Partners LP - Parent Only - Statement of Operations (Details) - USD ($) $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Revenues		$ 3,880.9	$ 2,520.5	$ 2,632.8
Operating income (loss)		(79.4)	(108.7)	(2,084.8)
Interest and debt expense, net		(99.4)	(125.1)	(140.1)
Gain (loss) on modification/extinguishment of debt	$ 10.0	(37.7)	10.0	(20.0)
Other income, net		1.3	0.5	0.6
Loss before income taxes		(167.4)	(191.8)	(2,305.1)
(Provision) benefit for income taxes		0.8	(0.3)	1.4
Net loss		(166.6)	(192.1)	(2,303.7)
Net income attributable to non-controlling partners in subsidiary		25.3	24.2	(636.8)
Net income (loss) attributable to parent		(191.9)	(216.3)	(1,666.9)
Parent Company
Condensed Financial Statements, Captions [Line Items]
Revenues		0.0	0.0	0.0
Costs and Expenses		6.7	6.0	14.5
Operating income (loss)		(6.7)	(6.0)	(14.5)
Interest and debt expense, net		0.0	0.0	(9.6)
Loss from unconsolidated affiliates		(160.4)	(186.6)	(2,279.1)
Gain (loss) on modification/extinguishment of debt		0.0	0.0	(1.1)
Other income, net		0.5	0.5	0.6
Net loss		(166.6)	(192.1)	(2,303.7)
Net income attributable to non-controlling partners in subsidiary		25.3	24.2	(636.8)
Net income (loss) attributable to parent		$ (191.9)	$ (216.3)	$ (1,666.9)

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Schedule I - Crestwood Equity Partners LP - Parent Only - Statement of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Net loss	$ (166.6)	$ (192.1)	$ (2,303.7)
Change in fair value of Suburban Propane Partners, LP units	(0.8)	0.8	(2.7)
Comprehensive loss	(167.4)	(191.3)	(2,306.4)
Comprehensive income (loss) attributable to non-controlling partners	(25.3)	(24.2)	636.8
Comprehensive loss attributable to Crestwood Equity Partners LP	(192.7)	(215.5)	(1,669.6)
Parent Company
Condensed Financial Statements, Captions [Line Items]
Net loss	(166.6)	(192.1)	(2,303.7)
Change in fair value of Suburban Propane Partners, LP units	(0.8)	0.8	(2.7)
Comprehensive loss	(167.4)	(191.3)	(2,306.4)
Comprehensive income (loss) attributable to non-controlling partners	(25.3)	(24.2)	636.8
Comprehensive loss attributable to Crestwood Equity Partners LP	$ (192.7)	$ (215.5)	$ (1,669.6)

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Schedule I - Crestwood Equity Partners LP - Parent Only - Condensed Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Condensed Financial Statements, Captions [Line Items]
Cash flows from operating activities	$ 255.9	$ 346.1	$ 440.7
Cash flows from investing activities	38.7	867.2	(212.7)
Proceeds from the issuance of long-term debt	2,838.6	1,565.3	4,261.8
Payments on long-term debt	(2,913.9)	(2,536.3)	(4,113.0)
Payments for debt-related deferred costs	(1.0)	(3.5)	(17.3)
Distributions to partners	(167.6)	(219.8)	(171.5)
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	(15.0)	0.0	0.0
Net cash provided by (used in) financing activities	(294.9)	(1,212.2)	(236.3)
Net change in cash	(0.3)	1.1	(8.3)
Cash at beginning of period	1.6	0.5	8.8
Cash at end of period	1.3	1.6	0.5
Parent Company
Condensed Financial Statements, Captions [Line Items]
Cash flows from operating activities	(3.6)	(3.5)	(14.7)
Cash flows from investing activities	174.0	227.6	593.8
Proceeds from the issuance of long-term debt	0.0	0.0	771.7
Payments on long-term debt	0.0	(0.2)	(1,152.1)
Distributions to partners	(182.6)	(219.8)	(171.5)
Payments of Ordinary Dividends, Preferred Stock and Preference Stock	15.2	0.0	0.0
Change in intercompany balances	(3.0)	(4.2)	(30.5)
Net cash provided by (used in) financing activities	(170.4)	(224.2)	(582.4)
Net change in cash	0.0	(0.1)	(3.3)
Cash at beginning of period	0.3	0.4	3.7
Cash at end of period	$ 0.3	$ 0.3	$ 0.4

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Schedule I - Crestwood Equity Partners LP - Parent Only - Distributions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Parent Company
Dividends received from CMLP	$ 174.0	$ 227.6	$ 31.4

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Schedule II - Crestwood Equity Partners LP - Valuation and Qualifying Accounts (Details) - Allowance for Doubtful Accounts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Movement in Valuation Allowances and Reserves [Roll Forward]
Valuation Allowances and Reserves, Balance	$ 1.9	$ 0.4	$ 0.1
Valuation Allowances and Reserves, Charged to Cost and Expense	1.5	1.9	0.0
Valuation Allowances and Reserves, Charged to Other Accounts	0.0	0.0	0.4
Valuation Allowances and Reserves, Deductions	(1.0)	(0.4)	(0.1)
Valuation Allowances and Reserves, Balance	$ 2.4	$ 1.9	$ 0.4