Edgar Filing: Crestwood Equity Partners LP

10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K



ý	ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	For the fiscal year ended December 31, 2015



¨	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



700 Louisiana Street, Suite 2550 Houston, Texas		77002
(Address of principal executive offices)		(Zip code)

(832) 519-2200

(Registrant’s telephone number, including area code)

___________________________________________

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

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

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, 2015).



Crestwood Equity Partners LP		$0.5 billion
Crestwood Midstream Partners LP		$1.7 billion

Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date (February 12, 2016).



Crestwood Equity Partners LP	$9.04 per common unit	69,057,459
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.

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CRESTWOOD EQUITY PARTNERS LP

INDEX TO ANNUAL REPORT ON FORM 10-K



		Page
	PART I

Item 1.	Business	7

Item 1A.	Risk Factors	26

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	72

Item 8.	Financial Statements and Supplementary Data	73

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	73

Item 9A.	Controls and Procedures	73

Item 9B.	Other Information	74

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	75

Item 11.	Executive Compensation	80

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	91

Item 13.	Certain Relationships and Related Transactions, and Director Independence	94

Item 14.	Principal Accountant Fees and Services	96

	PART IV

Item 15.	Exhibits, Financial Statement Schedules	97

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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 III of this Annual Report includes separate financial statements (i.e., balance sheets, statements of operations, statement 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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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.
Barrel (Bbl)	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.
Dth	One dekatherm of natural gas.
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.
G&P	Gathering and processing.
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.
LIBOR	London Interbank Offered Rate.
MMbtu	One million British thermal units, which is approximately equal to one Mcf. One British thermal unit is equivalent to an amount of heat required to raise the temperature of one pound of water by one degree.
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).
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.

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Wheeling	The transportation of natural gas from one pipeline to another pipeline through the pipeline facilities of a natural gas storage facility. The gas does not flow into or out of actual storage, but merely uses the surface facilities of the storage operation.
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, (ii) “Crestwood Midstream” and "CMLP" refers to Crestwood Midstream Partners LP and its consolidated subsidiaries following the Crestwood Merger (defined below), (iii) “Legacy Inergy” refers to Inergy, L.P. and its consolidated subsidiaries prior to the Crestwood Merger, (iii) “Inergy Midstream” refers to Inergy Midstream, L.P. and its consolidated subsidiaries prior to the Crestwood Merger, and (iv) “Legacy Crestwood” refers to Crestwood Midstream Partners LP and its consolidated subsidiaries prior to the Crestwood Merger. Unless otherwise indicated, information contained herein is reported as of December 31, 2015.

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 2.6 Bcf/d of gathering capacity, 481 MMcf/d of processing capacity, 40.9 Bcf of certificated working gas storage capacity and 1.3 Bcf/d of firm pipeline transmission capacity;


•	NGL facilities with approximately 24,000 Bbls/d of fractionation capacity and 2.8 million barrels 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 more than 294,000 Bbls/d of NGLs; and


•	crude oil facilities with approximately 125,000 Bbls/d of gathering capacity, approximately 1.5 million barrels of total storage capacity, 48,000 Bbls/d of transportation capacity and 160,000 Bbls/d of rail loading capacity.

Our primary business objective is to maximize the value of Crestwood for all stakeholders.

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Ownership Structure

The diagram below reflects a simplified version of our ownership structure as of December 31, 2015:

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 21% of Crestwood Equity's limited partner and subordinated units as of December 31, 2015.

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 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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Crestwood Merger (2013). In May 2013, Crestwood Holdings and the former owners of Crestwood Equity's general partner entered into a series of transactions that would effectively consolidate and combine the operations of Legacy Crestwood and Legacy Inergy. The parties first completed a series of “upstairs” transactions in June 2013 that resulted in Crestwood Holdings’ acquisition of control of Crestwood Equity. The “downstairs” portion of the strategic business combination was completed in October 2013 when publicly-traded Legacy Crestwood merged with and into publicly-traded Inergy Midstream (the Crestwood Merger) and Inergy Midstream immediately thereafter changed its name to Crestwood Midstream Partners LP.

Simplification Merger (2015). In May 2015, Crestwood Equity, Crestwood Midstream and certain of their affiliates entered into a definitive agreement under which Crestwood Midstream would merge with a wholly-owned subsidiary of Crestwood Equity, with Crestwood Midstream surviving as a wholly-owned subsidiary of Crestwood Equity (the Simplification Merger). On September 30, 2015, the Simplification Merger was completed immediately following the affirmative approval of the merger by Crestwood Midstream's unaffiliated unitholders.

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.

See Part IV, Item 15, Exhibits, Financial Statement Schedules, Notes 1 and 3 for additional information on these related transactions.

Our Assets

Prior to the Simplification Merger, except for the assets comprising our NGL marketing business, all of our operating assets were owned by or through Crestwood Midstream. 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. In connection with the closing of the Simplification Merger on September 30, 2015, Crestwood Equity contributed 100% of its interests in Crestwood Operations to Crestwood Midstream. As a result of this equity contribution, and as of December 31, 2015, all of the Company's consolidated assets are owned by or through Crestwood Midstream.

In conjunction with the Simplification Merger, we modified our segments and our financial statements now reflect three operating and reporting segments: (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) marketing, supply and logistics operations (formerly NGL and crude services operations). Consequently, the results of our Arrow operations are now reflected in our gathering and processing operations for all periods presented and our COLT Hub operations and Powder River Basin Industrial Complex, LLC (PRBIC) investment are now reflected in our storage and transportation operations for all periods presented. These respective operations were previously included in our NGL and crude services 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, Arkansas and Louisiana. This segment primarily includes (i) our crude oil, gas and produced water gathering systems in the Bakken Shale play; (ii) our rich gas gathering systems and processing plants in the Bakken, Marcellus, Barnett, Delaware Permian and Powder River Basin (PRB) Niobrara Shale plays; and (iii) our dry gas gathering systems in the Barnett, Fayetteville, and Haynesville Shale plays.

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The table below summarizes certain information about our G&P systems (including our equity investment) as of December 31, 2015:



Play (State)	Counties / Parishes	Pipeline (Miles)	Gathering Capacity	2015 Average Gathering Volumes	Compression (HP)	Number of In-Service Processing Plants	Processing Capacity (MMcf/d)	Gross Acreage Dedication
Bakken North Dakota	McKenzie and Dunn	590 ⁽¹⁾	100 MMcf/d - natural gas gathering 125 MBbls/d - crude oil gathering 40 MBbls/d - water gathering	43 MMcf/d - natural gas gathering 64 MBbls/d - crude oil gathering 26 MBbls/d - water gathering	18,000	—	—	150,000
Marcellus West Virginia	Harrison, Barbour and Doddridge	80	875 MMcf/d	550 MMcf/d	138,080	—	—	140,000
Barnett Texas	Hood, Somervell, Tarrant, and Denton	507	955 MMcf/d	341 MMcf/d	153,465	1	425	140,000
Fayetteville Arkansas	Conway, Faulkner, Van Buren, and White	173	510 MMcf/d	73 MMcf/d	27,645	—	—	143,000
Permian New Mexico	Eddy	73	50 MMcf/d	17 MMcf/d	955	1	20	107,000
Granite Wash Texas	Roberts	36	36 MMcf/d	27 MMcf/d	12,240	1	36	22,000
Haynesville / Bossier Louisiana	Sabine	57	100 MMcf/d	6 MMcf/d	—	—	—	22,000
PRB Niobrara ⁽²⁾ Wyoming	Converse	211	140 MMcf/d	80 MMcf/d	50,895	1	120,000	388,000


(1)	Consists of 215 miles of natural gas gathering pipeline, 194 miles of crude oil gathering pipeline, and 181 miles of produced water gathering pipeline.


(2)	Our PRB Niobrara 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 the Hiland and Tesoro crude oil pipeline systems. The Arrow system includes approximately 590 miles of gathering lines, a 23-acre central delivery point with 266,000 barrels of crude oil working storage capacity and multiple pipeline take-away outlets, and salt water disposal wells. 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 ten compression and dehydrations stations with 138,080 horsepower. Through these systems, we provide midstream services, primarily to Antero Resources Appalachian 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.

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. The gathering agreement provides for an annual minimum volume commitment of 450 MMcf/d in 2016 through 2018. We gather and ultimately redeliver Antero’s production to MarkWest's Sherwood Gas Processing Plant and various regional pipeline systems,

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including Columbia, EQT, Dominion and Momentum's Stonewall pipeline which was placed into service in December 2015. Our system is currently connected to 233 Antero wells.

In the Western Area, we provide compression and dehydration services to Antero’s gathering facilities predominantly with our West Union and Victoria compressor stations under a seven year, fixed-fee agreement that runs through 2021, subject to Antero’s right to extend the contract term for an additional three years. In the Western Area, Antero provides minimum volume commitments for 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 (i) pipelines that gather rich natural gas produced by customers and deliver the volumes to our plants for processing, (ii) 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, and (iii) the Corvette plant, which extracts NGLs from the natural gas stream and delivers customers’ residue gas and extracted NGLs to unaffiliated pipelines for sale downstream. For the year ended December 31, 2015, our plants had a total average throughput of 128 MMcf/d of natural gas with an average NGL recovery of 10,000 Bbl/d. In June 2015, we shut down the Corvette plant and diverted processing volumes 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 (Van Buren County) and Rose Bud (White County) systems each consist of a gas gathering system and related dehydration and compression facilities. All of our systems gather natural gas produced by customers and deliver customers’ gas to unaffiliated pipelines for downstream sale.

Delaware Permian

We own and operate several gas gathering and processing systems in the fast growing Delaware Permian region. Our systems, located in Eddy County, New Mexico, consists of two dry gas gathering systems (Las Animas systems) and one rich gas gathering system and processing plant (Willow Lake system). In July 2014, we expanded our Willow Lake system to include a 20 MMcf/d processing plant. The Willow Lake expansion was anchored by a 10-year fixed-fee agreement with Concho Resources Inc. (Concho), formerly Legend Production Holdings, LLC.

In late 2015, we expanded the Willow Lake processing plant to 50 MMcf/d, which we completed and placed into service in January 2016. The recent expansion of the Willow Lake system was supported by a seven year contract extension with Mewbourne Oil Co. (Mewbourne) which significantly increased the amount of WolfCamp drilling and rich gas development expected in the area.

Other 100% Owned and Operated Systems

We also own and operate systems in the Granite Wash and the Haynesville/Bossier Shales. Our Indian Creek system, which is located in Roberts County, Texas in the Granite Wash, includes a rich gas gathering system, compression facility and processing plant. Our Sabine system, which is located in Sabine Parish, Louisiana, includes high-pressure gas gathering pipelines that provide gathering and treating services for producers in the Haynesville/Bossier Shale.

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PRB Niobrara Joint Venture

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 and Bucking Horse processing plant, which serves a 388,000 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 the 120 MMcf/d Bucking Horse processing plant, which was placed into service in January 2015. The system connects to 88 well pads and is supported by a 20-year gathering and processing agreement with Chesapeake. Under the agreement, Jackalope receives cost-of-service based fees with annual redeterminations sufficient to provide Jackalope a fixed return on all capital invested to build out and expand the system over the life of the contract. See Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in Jackalope.

The table below summarizes certain contract profile information (including our equity investment) as of December 31, 2015:



Shale Play	Type of Services	Type of Contracts⁽¹⁾	Gross Acreage Dedication	Major Customers	Weighted Average Remaining Contract Terms (in years)
Arrow	Gathering - crude oil, natural gas and water	Fixed-fee	150,000	WPX, Whiting Petroleum, Halcon Resources Corporation, XTO Energy, QEP Resources, Inc., Enerplus	7
Marcellus	Gathering	Fixed-fee⁽²⁾	140,000	Antero	16
	Compression	Fixed-fee	—	Antero	4
Barnett	Gathering	Fixed-fee	140,000	Quicksilver⁽³⁾, Devon Energy	7
	Processing	Fixed-fee	—	Quicksilver⁽³⁾, Devon Energy	7
	Compression	Fixed-fee	—	Quicksilver⁽³⁾, Devon Energy	7
Fayetteville	Gathering	Fixed-fee	143,000	BHP Billiton Petroleum (BHP)	9
	Treating	Fixed-fee	—	BHP	9
Permian	Gathering	Fixed-fee	107,000	Concho	5
	Processing	Mixed	—	Concho, Mewbourne	5
Other⁽⁴⁾	Gathering	Fixed-fee	44,000	Sabine Oil and Gas	8
	Processing	Mixed	—	Sabine Oil and Gas	8
PRB Niobrara⁽⁵⁾	Gathering	Fixed-fee cost-of-service	388,000	Chesapeake	16
	Processing	Fixed-fee cost-of-service	—	Chesapeake	16


(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. Our fixed-fee cost-of-service contracts have fees designed to recover operating costs and capital expenditures plus a fixed return.


(2)	Antero has provided minimum volume commitments under our agreement, which increase from an average of 450 MMcf/d in 2016, 2017 and 2018, respectively.

(3)

Eni SpA and Tokyo Gas own approximately 27.5% and 25%, respectively, of Quicksilver Resources Inc.'s (Quicksilver) Barnett assets. In March 2015, Quicksilver filed for protection under Chapter 11 of the U.S. Bankruptcy Code. We are closely monitoring our exposure to Quicksilver to ensure prompt payment of invoices. For a further discussion of the impact of Quicksilver's bankruptcy to us, see Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations, "Our Company."


(4)	Other shale plays include Granite Wash and Haynesville / Bossier.


(5)	Our PRB Niobrara assets are owned by Jackalope, our 50% equity method investment.

Storage and Transportation

We own and operate five high-performance natural gas storage facilities with an aggregate certificated working gas storage capacity of approximately 79.3 Bcf, including our 50.01% ownership interest in Tres Palacios Gas Storage Company LLC (Tres Palacios), and three natural gas pipeline systems with an aggregate firm transportation capacity of 1.3 Bcf/d. All of our natural gas storage and transportation assets are located near major shale plays and demand markets, and they have low maintenance costs and long useful lives. Our storage and transportation segment also includes our COLT Hub, one of the largest crude-by-rail loading terminal serving Bakken crude oil production, and our 50.01% ownership interest in the Powder River Basis Industrial Complex LLC (PRBIC), which owns a crude-by-rail terminal serving PRB Niobrara crude oil production.

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Storage Facilities. We own and operate four storage facilities located in New York and Pennsylvania. Our storage facilities have comparatively high cycling capabilities and their interconnectivity with interstate pipelines offers significant flexibility to our customers. Each of our storage facilities are fully contracted. Our natural gas storage facilities, each of which generates fee-based revenues, include:

•

Stagecoach, a FERC-certificated 26.2 Bcf multi-cycle, depleted reservoir storage facility owned and operated by our Stagecoach Pipeline & Storage Company LLC (formerly known as Central New York Oil And Gas Company, L.L.C.) (Stagecoach Pipeline) subsidiary. 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 the Millennium Pipeline (Millennium).

•

Thomas Corners, a FERC-certificated 7.0 Bcf multi-cycle, depleted reservoir storage facility owned and operated by our Arlington Storage Company, LLC (Arlington Storage) subsidiary. An 8-mile, 12-inch diameter pipeline lateral connects the storage facility to TGP's 200 Line, and a 8-mile, 8-inch diameter pipeline lateral connects to Millennium. Thomas Corners is also connected to Dominion Transmission Inc. (Dominion) system through our Steuben facility.


•	Seneca Lake, a FERC-certificated 1.5 Bcf multi-cycle, bedded salt storage facility owned and operated by Arlington Storage. 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 Arlington Storage. 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 our Steuben and Thomas Corners storage facilities.

The following provides additional information about our natural gas storage facilities (including our equity investment in Tres Palacios) as of December 31, 2015:



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; 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
Consolidated Total	40.9		423	845
Tres Palacios⁽³⁾	38.4		1,000	2,500	Multiple⁽⁴⁾
Total	79.3		1,423	3,345


(1)	Stagecoach is connected to Transcontinental Gas Pipe Line Corporation's (Transco) Leidy Line through our MARC I Pipeline.


(2)	We have been authorized by the FERC to expand Seneca Lake’s working gas storage capacity to 2 Bcf.


(3)	The Tres Palacios assets are owned by Tres Palacios Holdings LLC (Tres Holdings), our 50.01% equity-method investment.


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

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In December 2014, Crestwood Equity sold 100% of its membership interest in Tres Palacios, which owns a FERC-certificated 38.4 Bcf multi-cycle salt dome natural gas storage facility located in Texas, to Tres Holdings. Crestwood Midstream and Brookfield Infrastructure Group (Brookfield) formed Tres Holdings for the purpose of acquiring owning and operating Tres Palacios and each joint venture member paid approximately $66.4 million of cash to Crestwood Equity for Tres Palacios. As a result of this transaction, Crestwood Midstream owns 50.01% of Tres Palacios and operates its natural gas storage facility. Brookfield owns the remaining 49.99% interest in Tres Palacios.

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 10 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan Inc.'s 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 membership interest in Tres Palacios.

Transportation Facilities. We own three natural gas pipeline systems located in New York and Pennsylvania. Throughput on our interstate and intrastate pipeline systems can be expanded at relatively low capital costs. In 2015, our transportation facilities delivered approximately 1.3 Bcf/d of natural gas on a firm or interruptible basis for our transportation and storage customers. Our natural gas transportation facilities include:

•

North-South Facilities, which include compression and appurtenant facilities installed to expand transportation capacity on the Stagecoach north and south pipeline laterals. The bi-directional interstate facilities, which are owned and operated by Stagecoach Pipeline, provide more than 547 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.

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MARC I Pipeline, a 39-mile, 30-inch diameter interstate natural gas pipeline that connects the Stagecoach south lateral and TGP's 300 Line in Bradford County, Pennsylvania, with Transco’s Leidy Line in Lycoming County, Pennsylvania. The bi-directional pipeline, which is owned and operated by Stagecoach Pipeline, provides more than 716 MMcf/d of firm interstate transportation capacity to shippers. It includes a 16,360 horsepower gas-fired compressor station near the Transco interconnection, and a 15,000 horsepower electric-powered compressor station at the interconnection between the Stagecoach south lateral and TGP’s 300 Line. The MARC I Pipeline generates fee-based revenues under a negotiated rate structure authorized by the FERC.

We completed an open season for an expansion of the MARC I Pipeline in the first quarter of 2015 and have entered into firm service contracts with multiple customers for the expansion capacity. This project includes a new 530 MMcf/d supply point into the MARC I Pipeline (Wilmot Station) through an interconnection with Appalachian Midstream Services and 280 MMcf/d expansion of the existing interconnect between MARC I and Transcontinental Gas Pipe Line Corporation (Transco). The Transco expansion project was completed and placed into service in November 2015.

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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, which is owned by Crestwood Pipeline East, LLC (CPE), runs within three miles of our Stagecoach north lateral's point of interconnection with Millennium. The East Pipeline generates fee-based revenues under a negotiated rate structure authorized by the New York State Public Service Commission (NYPSC).

Rail Loading Facilities. We own or have interest in crude oil rail loading facilities in North Dakota and Wyoming. Our crude oil rail loading facilities include:

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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 million barrels of total 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 Partners, LP (Hiland) crude oil gathering systems at the COLT terminal, and the Enbridge Energy Partners, L.P. and Tesoro Corporation (Tesoro) pipeline systems at Dry Fork.

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•

PRBIC. PRBIC, our 50.01% 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 PRB Niobrara. The joint venture, operated by Twin Eagle Resource Management, LLC (Twin Eagle), sources crude oil production from Chesapeake and other PRB Niobrara producers. PRBIC includes 20,000 Bbls/d of rail loading capacity and 380,000 barrels of crude oil working storage capacity. Additionally, in anticipation of growing PRB Niobrara crude oil volumes, PRBIC expanded its pipeline terminal to include connections to Kinder Morgan's HH Pipeline system in July 2015 and initiated a pipeline project to interconnect with Plains All American Pipeline's Rocky Mountain Pipeline system, which is expected to be completed in March 2016. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in PRBIC.

The table below summarizes our major contract information associated with our storage and transportation facilities (including our equity investment) as of December 31, 2015:



Facility	Type of Services	Type of Contracts⁽¹⁾	Contract Volumes	Major Customers	Weighted Average Remaining Contract Terms (in years)
North-South Facilities	Transportation	Firm	547 MMcf/d	Southwestern Energy, Anadarko Energy Services Company (Anadarko), Chesapeake Energy (Chesapeake), Cabot Oil, Mitsui & Co., Ltd. (Mitsui)	3
MARC I Pipeline	Transportation	Firm	716 MMcf/d	Chesapeake, Statoil Natural Gas, Anadarko, Mitsui, Sequent Energy Management (Sequent)	6
East Pipeline	Transportation	Firm	30 MMcf/d	NY State Electric & Gas Corp	5
Stagecoach	Storage	Firm	22.4 Bcf	Consolidated Edison of NY, New Jersey Natural Gas, Repsol Energy North America Corporation (Repsol), Sequent	2
Thomas Corners	Storage	Firm	7.2 Bcf	Repsol, Tenaska Gas Storage, LLC, Emera Inc.	1
Seneca Lake	Storage	Firm	1.5 Bcf	Dominion Transmission Inc., NY State Electric & Gas Corp, DTE Energy Trading	2
Steuben	Storage	Firm	6.2 Bcf	PSEG Energy Resources & Trade LLC, Repsol, Pivot Utility Holdings	2
Tres Palacios⁽²⁾	Storage	Firm	34.5 Bcf	Brookfield, Anadarko, Repsol, Koch Energy Services LLC, MGI, NJR Energy	2
COLT	Rail Loading	Fixed-fee⁽³⁾	144,300 Bbl/d	Tesoro, U.S. Oil, BP, Sunoco Inc., and Statoil Inc.	2
PRBIC⁽⁴⁾	Rail Loading	Fixed-fee	10,000 Bbl/d	Chesapeake	3


(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.


(2)	The Tres Palacios assets are owned by Tres Holdings, our 50.01% equity-method investment.


(3)	Fixed-fee contracts represent contracts in which our customers agree to pay a flat rate based on the amount of commodity delivered.


(4)	Crestwood Crude Logistics LLC, our wholly-owned subsidiary, owns our 50.01% equity-method investment in PRBIC.

Marketing, Supply and Logistics

Our marketing, supply and logistics segment's operations include our NGL supply and logistics business (including NGL buy-sell, storage, trucking, and terminal services), our crude oil and produced water trucking business, and US Salt, LLC (US Salt).

NGL Supply and Logistics. Our NGL supply and logistics business serves producers, refiners and other customers that produce or consume natural gas liquids, including primarily propane, butane and natural gasoline. To provide these services, we utilize our portfolio of proprietary and third party NGL processing, fractionation, storage, terminal and trucking assets. These assets consist primarily of:


•	our fleet of rail and rolling stock with 294,000 Bbls/d of NGL transmission capacity, which also includes our rail-to-truck terminals located in Florida, New Jersey, New York and Rhode Island, and our truck maintenance facilities located in Indiana, Mississippi, New Jersey and Ohio;

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our West Coast NGL operations, which provides processing, fractionation, storage, transportation and marketing services to producers, refiners and other customers. Located near Bakersfield, California, our West Coast facilities 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 take-away options. We separate NGLs from natural gas, deliver to local natural gas pipelines, and retain NGLs for

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further processing at our fractionation facility, as well as provide butane isomerization and refrigerated storage services. Our isomerization facility chemically changes normal butane to isobutane, which we provide to Western US refineries for motor fuel production;

•

our NGL storage facilities include the Seymour and Bath storage facilities. The Seymour storage facility is located in Seymour, Indiana, and has 21 million gallons of underground NGL storage capacity and 1.2 million gallons of aboveground "bullet" storage capacity. The facility's receipts and deliveries are supported by Enterprise Teppco pipeline, allowing pipeline and truck access. The Bath storage facility is located in Bath, New York and has 1.7 million gallons of underground NGL storage capacity and is supported by both rail and truck terminal facilities capable of loading and unloading 23 rail cars per day and approximately 100 truck transports per day; and


•	NGL pipeline and storage capacity leased from third parties, including more than 500,000 barrels of NGL working storage capacity at major hubs in Mt. Belvieu, Texas and Conway, Kansas.

Crude Oil and Produced Water Trucking. Our crude oil and produced water trucking fleet has 48,000 Bbls/d of crude oil and produced water transportation capacity. These assets were acquired in the first half of 2014. We provide hauling services to customers in North Dakota, Montana, Wyoming, Texas and New Mexico.

US Salt. US Salt is an industry-leading solution mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York. It is one of five major solution mined salt manufacturers in the United States, capable of producing more than 400,000 tons of evaporated salt products for food, industrial and pharmaceutical uses. The solution mining process used by US Salt creates salt caverns that can be converted into natural gas and NGL storage capacity.

Customers

For the year ended December 31, 2015, we had no customer that accounted for more than 10% of our total consolidated revenues. For the year ended December 31, 2014, Tesoro accounted for approximately 12% of our total consolidated revenues. No customer accounted for 10% or more of our total consolidated revenues for the year ended December 31, 2013.

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 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:

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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.

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.

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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.

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.

Salt Manufacturing

According to the United States Geological Survey, approximately 270 million metric tons of salt were produced in the world in 2015. Salt is generally categorized into four types based upon the method of production: evaporated salt, solar salt, rock salt and salt in brine. Dry salt is produced through the following methods: solution mining and mechanical evaporation, solar evaporation or deep-shaft mining. US Salt produces salt using solution mining and mechanical evaporation. In solution mining, wells are drilled into salt beds or domes and then water is injected into the formation and circulated to dissolve the salt. After salt is removed from a solution-mined salt deposit, the empty cavern can be used to store other substances, such as natural gas, NGLs or compressed air.

The salt solution, or brine, is next pumped out of the cavern and taken to a processing plant for evaporation. The brine may be treated to remove minerals and then pumped into vacuum pans in which the brine is boiled, and evaporated until a salt slurry is created. The slurry is then dried and separated. Depending on the type of salt product to be produced, iodine and an anti-caking agent may be added to the salt. Most food grade table salt is produced in this manner.

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 (e.g., 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

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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 our 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.

Our salt operations compete for customers primarily based on price and service. Because transportation costs are a material component of the costs borne by our customers, most of our customers are geographically located east of the Mississippi River.

Regulation

Our operations 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, and we expect this trend to continue for the foreseeable future.

Pipeline Safety

We are subject to pipeline safety regulations imposed by the 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 facilities. Currently, 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 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 that, in the event of a pipeline leak or rupture could affect high-consequence areas, such as areas of high population and areas unusually sensitive to environmental damage. 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, President Obama in January 2012 signed the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (Pipeline Safety Act), which requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the Pipeline Safety Act directs the Secretary of Transportation to promulgate regulations relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, testing to confirm the material strength

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of certain pipelines, and operator verification of records confirming the maximum allowable pressure of certain intrastate gas transmission pipelines. The 2011 Pipeline Safety Act also increases the maximum penalty for violation of pipeline safety regulations from $100,000 to $200,000 per violation per day and also from $1 million to $2 million for a related series of violations. The safety enhancement requirements and other provisions of the 2011 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 transmission pipeline regulations to, among other things, expand the scope of high consequence areas, strengthen integrity management requirements applicable to existing operators; 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 add new regulations to govern the safety of underground natural gas storage facilities, including underground storage caverns and injection or withdrawal well piping that are not regulated today. 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.

Future developments, such as stricter environmental laws or regulations, or more stringent enforcement of existing requirements could directly affect our operations. For example, in January 2015, the Obama Administration announced plans for the EPA to issue final standards in 2016 that would reduce methane emissions from new and modified oil and natural gas production and natural gas processing and transmission facilities by up to 45 percent from 2012 levels by 2025. In October 2015, the EPA reduced the National Ambient Air Quality Standard for ozone from 75 parts per billion to 70 parts per billion. State recommendations for area designations are due on October 1, 2016, and the EPA will finalize the designations by October 1, 2017. In matters that could have an indirect adverse effect on our business by decreasing demand for the services that we offer, the EPA and other federal and state agencies are conducting studies of potential adverse impacts that certain drilling methods (including hydraulic fracturing) may have on water quality and public health, whereas, Congress has considered, and several states have 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 lines, but most 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 Storage and Transportation

Our interstate natural gas storage and transportation operations are subject to regulation by the FERC under the Natural Gas Act, and two of our wholly owned subsidiaries (Stagecoach Pipeline and Arlington Storage) 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 rates charged for services and the terms and conditions of service; the certification and construction of new facilities; the extension or abandonment of services and facilities; the maintenance of accounts and records; the acquisition and disposition of facilities; standards of conduct between affiliated entities; and 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.

The rates and terms and conditions of our natural gas storage and transportation services are found in the FERC-approved tariffs of (i) Stagecoach Pipeline, the owner of the Stagecoach facility, the North-South Facilities and the MARC I Pipeline, (ii) Arlington Storage, the owner of the Thomas Corners, Seneca Lake and Steuben facilities, and (iii) Tres Palacios, the owner of the Tres Palacios 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 us to negotiate rates with individual customers based on market demand, which we then make public. A loss of market-based or negotiated rate authority or any successful complaint or protest against the rates charged or provided by Stagecoach Pipeline or Arlington Storage could have an adverse impact on our revenues.

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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 $1 million per day per violation.

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

Our intrastate pipeline in New York (the East Pipeline) is subject to lightened regulation under NYPSC regulations and policies. Lightened regulation generally exempts us from NYPSC regulation applicable to the provision of retail service. CPE, as the owner and operator of the East Pipeline, remains subject to limited corporate (e.g., obtaining approval prior to any transfer of its ownership interests or the issuance of debt securities) and operational and safety (e.g., filing of vegetation management plan) regulation established and maintained by the NYPSC.

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 that a pipeline is a gathering pipeline and is therefore 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, and 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 by it 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, services provided by such facility would be subject to regulation by the FERC under the Natural Gas Act or the Natural Gas Policy Act. Such regulation could decrease revenue, increase operating costs, and, depending upon the facility in question, could 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 in some instances 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 they 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 of natural gas gathering operations, 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, and 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 TRCC, which requires that our NGL pipelines file tariff publications that contain all the rules and 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.

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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 NYSDEC have jurisdiction over the underground storage of NGLs and well drilling, conversion and 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 and our proposed storage facility near Watkins Glen.

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, determined in August 2011 that the Draft Supplemental Environmental Impact Statement we submitted for the project was complete, and held public hearings on the project in September and November 2011. In early 2012, based on concerns expressed by interested stakeholders and conversations with NYSDEC staff, we informed the agency that we would reduce our environmental footprint and modified our brine pond design. In September 2012, we submitted to the NYSDEC final drawings and plans for our revised project design. In August 2014, the NYDEC announced that it would convene an issues conference to determine if there are any significant issues that require an adjudicatory hearing. The issues conference was held in mid-February 2015, and we are awaiting a ruling from the presiding administrative law judge on whether additional hearings are required for any of the technical issues addressed at the issues conference. We continue to pursue the approvals required to construct our proposed NGL storage facility near Watkins Glen, New York but 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 and to not confer undue preference upon any shipper. The transportation of crude oil by common carrier pipelines on an intrastate 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.

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, 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. Exploration and production operators in the state may be required to install new equipment to satisfy these goals, and any failure by operators subject to the legal requirements to meet these gas capture percentage goals would subject those operators to production restrictions, which developments could reduce the amount of commodities we gather on the Arrow system from those operators who are 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, are subject to regulation by the Mandan, Hidatsa & Arikara Nation (MHA Nation). An entirely separate and distinct set of laws and regulations applies to operators and other parties within the boundaries of Native American reservations in the United States. Various federal agencies within the U.S. Department of the Interior, particularly the Bureau of Indian Affairs, the Office of Natural Resources Revenue and Bureau of Land Management (BLM), and the EPA, together with each Native American tribe, promulgate and enforce regulations pertaining to oil and gas operations on Native American reservations. These regulations include lease provisions, environmental standards, Tribal employment contractor preferences and numerous other matters.

Native American tribes are subject to various federal statutes and oversight by the Bureau of Indian Affairs and BLM. However, each Native American tribe is a sovereign nation and has the right to enact and enforce certain other laws and regulations entirely independent from federal, state and local statutes and regulations, as long as they do not supersede or conflict with such federal statutes. These tribal laws and regulations include various fees, taxes, requirements to employ Native

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American tribal members or use tribal owned service businesses and numerous other conditions that apply to lessees, operators and contractors conducting operations within the boundaries of a Native American reservation. Further, lessees and operators within a Native American reservation are often subject to the Native American tribal court system, unless there is a specific waiver of sovereign immunity by the Native American tribe allowing resolution of disputes between the Native American tribe and those lessees or operators to occur in federal or state court.

We are therefore subject to various 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 Native American requirements, or delays in obtaining necessary approvals or permits necessary to operate on tribal lands pursuant to these regulations, 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 on those lands.

PHMSA is currently reviewing the adequacy of Bakken crude laboratory testing measures used to determine the packaging group selection for shipment of crude by rail. PHMSA's objective is to confirm that crude being offered for shipment by rail has been properly classified and characterized to ensure the safe transport to end users. We, as the owner of a Bakken crude loading terminal, are providing input as this review process progresses through multiple agencies and organizations.

Supply and Logistics

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

IRS Audit

On April 9, 2015, the IRS completed their examination of our 2011 partnership tax return and issued a No Adjustment Letter to us.

Environmental and Occupational Safety and Health Matters

Our operations are subject to stringent federal, regional, state 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 the need to obtain permits to conduct regulated activities; restrict the types, quantities and concentration of materials that can be released into the environment; apply workplace health and safety standards for the benefit of employees; require remedial activities or corrective actions to mitigate pollution from former or current operations; and impose substantial liabilities on us for pollution resulting from our operations. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil and criminal penalties; the imposition of investigatory, remedial and corrective action obligations or the incurrence of capital expenditures; the occurrence of delays in the development of projects; and the 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 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 solid wastes, including 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;


•	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;


•	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;

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•	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 and more detailed Environmental Impact Statements that may be made available for public review and comment;


•	The Endangered Species Act, which restricts activities that may affect federally identified endangered and 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 environmental laws 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. Approximately 28,000 barrels of produced water were released on lands within the boundaries of the Fort Berthold Indian Reservation. We have substantially completed our remediation efforts for the 2014 spills subject to approval by the MHA Nation and the applicable regulatory agencies. In May 2015, we experienced a release of approximately 5,200 barrels of produced water on our Arrow water gathering system. We have also notified our insurance carriers of the releases under our environmental policies and we believe our remediation costs will be recoverable under our insurance policies.

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 have commenced settlement discussion with the EPA concerning the NOPV. On March 3, 2015, we received a grand jury subpoena from the United States Attorney’s Office in Bismarck, North Dakota, seeking documents and information relating to the largest of the three 2014 water releases, and we provided the requested information during the second quarter of 2015. 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 ongoing settlement discussions with the regulatory agencies asserting jurisdiction over the 2014 produced water releases. We cannot predict what the outcome of these investigations will be.

We own a propane storage and distribution facility in Seymour, Indiana. On May 15, 2014, the EPA issued a request relating to our compliance with the chemical accident prevention provision at the facility. We responded to the request on August 6, 2014, and at EPA’s request, we submitted additional documentation of compliance on January 30, 2015. We entered into a consent agreement and final order with the EPA and paid a civil penalty of approximately $0.3 million in December 2015.

Employees

As of February 1, 2016, we had 1,300 full-time employees, 302 of which were general and administrative employees and 998 of which were operational. As of February 1, 2016, US Salt had 126 employees, 99 of which are members of a labor union. We believe that our relationship with our employees (including union labor) 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, 700 Louisiana Street, Suite 2550, 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, 700 Louisiana Street, Suite 2550, 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, 700 Louisiana Street, Suite 2550, 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, in 2015, significantly lower commodity prices have resulted in an industry-wide reduction in capital expenditures by producers and a slowdown in drilling, completion and supply development efforts. This trend has continued in 2016. 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 recent lifting of the crude oil export ban in 2015. 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;


•	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. The duration and magnitude of the recent decline in 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.

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 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.

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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.

Since 2014, the significant decline in energy commodity prices 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 and unsecured debt have substantially decreased in value 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 the current downturn persists, based on current market conditions, it is unlikely that we could issue equity or debt 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 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 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 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.

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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. Given the current low commodity price environment and its anticipated impact on shale production, we expect certain of our producer customers to experience declining cash flows and increased leverage. As a result, we expect many of our producer customers to reduce capital spending and/or shut in production for economic reasons which could result in lower revenues for us. In the event these market conditions persist, this could lead to the loss of a significant customer which could also cause a significant decline in our revenues.

For example, our gathering and processing systems are integral to Quicksilver's operations in the Barnett Shale. In March 2015, Quicksilver filed for protection under Chapter 11 of the U.S. Bankruptcy Code and shut in production of certain wells in conjunction with that filing. As a result of the bankruptcy process, in January 2016, Quicksilver executed an asset purchase agreement with a third party for the sale of its U.S. oil and gas assets. The sale is expected to close on March 31, 2016, pending certain closing conditions. On February 5, 2016, Quicksilver filed a motion to reject its gathering agreements with us. We filed an objection to this motion on February 26, 2016 and a hearing is scheduled in Delaware on March 4, 2016. We are in discussions with the third party regarding those agreements. There is no assurance that we will be able to renegotiate the gathering agreements at acceptable rates or at all. Any such renegotiation or rejection could have a material adverse effect on our gathering and processing revenues and cash flows. We continue to provide services to Quicksilver, and the outcome of its restructuring process could have a significant impact on our G&P segment's results.

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 or 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 affect 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

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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.

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.

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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.

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, 2015, 2014 and 2013, we were required to record $2,217.8 million, $82.0 million and $4.1 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 $2.5 billion of long-term debt outstanding as of December 31, 2015. 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

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all of our debt becoming immediately due and payable and could permit our lenders to foreclose on any of the collateral securing such debt;


•	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 causing 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 could adversely affect our business, financial condition, results of operations and ability to make distributions.

Our revolving credit facility contains 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 certain 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 1.00, and (ii) a senior secured leverage ratio (as defined in its credit agreement) of not more than 3.75 to 1.00.

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.

The provisions of our credit agreement 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 could result in events of default, which could enable our lenders, subject to the terms and conditions of credit agreement, 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 senior notes.

Our credit agreement and indentures contain provisions relating to change of control of Crestwood Equity's general partner, Crestwood Equity, and the general partner of Crestwood Midstream. 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

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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."

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 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 is 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 in the PRB Niobrara and the Texas Gulf Coast through joint ventures that may limit our operational flexibility.

Our operations in the PRB Niobrara and our storage operations in the Texas Gulf Coast market are conducted through joint venture arrangements (including the Jackalope and PRBIC joint ventures in the PRB Niobrara and our Tres Palacios joint venture in the Texas Gulf Coast market), and we may enter 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 forced to offer rights of participation to other joint venture participants in certain areas of mutual interest.

In addition, our 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 and to pay their share of capital and other costs of the joint venture. The performance and ability of the third parties to satisfy their obligations under joint venture arrangements is

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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 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.

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

Our primary exposure to market risk occurs at the time our existing contracts expire and are subject to renegotiation and renewal. As of December 31, 2015, the weighted average remaining term of (i) our consolidated portfolio of natural gas storage and transportation contracts is approximately two years, (ii) our consolidated portfolio of natural gas gathering contracts is approximately 10 years, and (iii) our consolidated portfolio of crude oil gathering contracts is approximately three 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 are subject to extensive regulation by federal, state and local regulatory authorities. For example, because we transport natural gas in interstate commerce and we store natural gas that is transported in interstate commerce, our 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

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prospective change by the FERC. Additionally, rate increases proposed by a regulated pipeline or storage provider may be challenged and such increases may ultimately be rejected by the FERC. We currently hold authority from the FERC to charge and collect (i) market-based rates for interstate storage services provided at the Stagecoach, Thomas Corners, Seneca Lake, Steuben and Tres Palacios facilities and (ii) negotiated rates for interstate transportation services provided by our North-South Facilities and MARC I Pipeline. 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 we will be allowed to continue to operate under such rate structures for the remainder of those assets' operating lives. Any successful challenge against rates charged for our storage and transportation services, or our 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. Our market-based rate authority for our natural gas storage facilities may be subject to review and possible revocation if the FERC determines that we have the ability to exercise market power in our market area. If we were to lose our ability to charge market-based rates, we would be required to file rates based on our cost of providing service, including a reasonable rate of return. Cost-of-service rates may be lower than our current market-based rates.

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 $1,000,000 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 safety laws and regulations that may expose us to significant costs and liabilities.

Our operations are subject to stringent federal, regional, state and local laws and regulations governing health and safety aspects of our operations, the discharge of materials into the environment 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

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comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and the issuance of injunctions restricting or prohibiting some or all of our activities. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where materials or wastes have been disposed or otherwise released. In the course of our operations, generated materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for recycling or disposal.

It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us as well as the industry in general or otherwise adversely affect demand for our services and salt products. For example, pursuant to President Obama's strategy to reduce methane emissions from the oil and gas sector by up to 45 percent from 2012 levels by 2025, in August 2015, the EPA proposed a suite of requirements and draft guidance related to the reduction in methane emissions from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. If finalized, 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 costs, delays or curtailment could adversely affect our business. In addition, in October 2015, the EPA issued a final rule under the federal Clean Air Act lowering the NAAQS for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. The EPA also released a final rule in May 2015 that attempted to clarify federal jurisdiction under the Clean Water Act over waters of the United States, but a number of legal challenges to this rule are pending, and implementation of the rule has been stayed nationwide. To the extent the 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 such new or amended legal requirements could result in our incurring significant additional expense and operating 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 greenhouse gases could result in increased operating and capital costs and reduced demand for our services.

The EPA has determined that emissions of carbon dioxide, methane and other greenhouse gases (GHGs) present an endangerment to public health and the environment because emissions of such gases are, according to the EPA, contributing to warming of the earth's atmosphere and other climatic changes. Based on these findings, the EPA 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. On October 22, 2015, the EPA published a final rule expanding the petroleum and natural gas system sources for which annual GHG emissions reporting is required to include GHG emissions reporting beginning in the 2016 reporting year for 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.

While the United States Congress has considered adopting legislation from time to time to reduce emissions of GHGs, in the absence of any such legislation in recent years, a number of state and regional efforts have emerged that are aimed at tracking or reducing emissions of GHGs primarily through the planned development of GHG emission inventories and/or regional GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, to acquire and surrender emission allowances. On an international level, the United States is one of almost 200 nations that agreed to an international climate change agreement in Paris, France on December 12, 2015, that allows countries to set their own GHG emission targets and disclose the measures each country will use to achieve its GHG emission targets. It is not possible at this time to predict how or when the United States might impose legal requirements as a result of this international agreement.

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

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regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations.

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, which authorized funding for federal pipeline safety programs through 2015, directed the Secretary of Transportation to, among other things, promulgate rules relating to expanded integrity management requirements, automatic or remote-controlled valve use, excess flow valve use, leak detection system installation, pipeline material strength testing, and verification of maximum allowable pressures of certain pipelines. The 2011 Pipeline Safety Act also increased civil penalties for certain violations up to $200,000 per violation per day, with a total cap of $2.0 million. Although a number of the mandates imposed under the 2011 Pipeline Safety Act have yet to be acted upon by PHMSA, those mandates continue to have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs in the future. Legislation that would reauthorize federal pipeline safety programs through 2019, referred to as Safe Pipes, was approved by the Senate Commerce Committee in December 2015. Among other things, the Safe Pipes legislation would require PHMSA to conduct an assessment of its inspection process and integrity management programs for natural gas and hazardous liquid pipelines and likely would require PHMSA to pursue those mandates under the 2011 Pipeline Safety Act that have not yet been acted upon.

In addition to these legislative actions, PHMSA is considering changes to its natural gas transmission pipeline regulations to, among other things, expand the scope of high consequence areas, strengthen integrity management requirements applicable to existing operators, 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 add new regulations to govern the safety of underground natural gas storage facilities, including underground storage caverns and injection or withdrawal well piping that are not regulated today. More recently, in March 2015, PHMSA finalized new rules applicable to gas and hazardous liquid pipelines that, among other changes, impose new post-construction inspections, welding, gas component pressure testing requirements, as well as requirements related to maximum allowable operating pressure calculations. 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, but compliance with such legal requirements could cause us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any one or more of which developments could cause us to incur increased costs or other liabilities that could have a material adverse effect on our results of operations or financial position.

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 natural gas or 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;

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•	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, during 2015 and 2014, we 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.

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.

We are subject to litigation related to the Simplification Merger.

We are subject to litigation related to the Simplification Merger (see "Item 3. Legal Proceedings"). It is possible that additional claims beyond those that have already been filed will be brought by the current plaintiffs or by others in an effort to enjoin the Simplification Merger or seek monetary relief from us. We cannot predict the outcome of these lawsuits, or others, nor can we predict the amount of time and expense that will be required to resolve the lawsuit(s). In addition, the cost to us defending the litigation, even if resolved in our favor, could be substantial.

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.

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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 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 following the quarter ending June 30, 2017, 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 we charge for storage and transportation services and the amount of services our customers purchase from us, 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.

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 following the quarter ending June 30, 2017, 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.

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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.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or its directors, which could reduce the price at which our common units will trade.

Unlike the holders of common stock in a corporation, our common unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management's decisions regarding our business. Our common unitholders will have no right on an annual or ongoing basis to elect our general partner or its board of directors. The board of directors of our general partner, including the independent directors, is chosen entirely by Crestwood Holdings, as a result of it owning our general partner, and not by our common unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our common unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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 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 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.

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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, 2015, Crestwood Holdings and its affiliates beneficially held an aggregate of 14,569,858 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 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 it 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 (1) alters or changes the rights, powers, privileges or preferences or duties and obligations of the preferred units in any material respect, (2) except as contemplated in the partnership agreement, increases or decreases the authorized number of preferred units, or (3) 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.

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 chosen by Crestwood Holdings LLC, the general partner of the sole member of our general partner, Crestwood Holdings LP (Holdings LP), which currently is the only voting member of the general partner of Holdings LP, and effectively has the authority to appoint all of our directors. 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.

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 LLC and various lenders (Holdings Credit Agreement). In the event of a default by Crestwood

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Holdings LLC 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

•

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, 2015, the directors and executive officers of our general partner owned approximately 6% of our common units.

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Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution 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 each 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, which is currently a maximum of 35%, as well as any applicable state or local taxes. 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. For example, the Obama administration’s budget proposal for fiscal year 2017 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2022. From time to time, members of Congress propose and consider such substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, the Obama administration’s proposal or other similar proposals could eliminate the qualifying income exception to the treatment of all publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes.

In addition, the Internal Revenue Service, on May 5, 2015, issued proposed regulations concerning which activities give rise to qualifying income within the meaning of Section 7704 of the Internal Revenue Code. We do not believe the proposed regulations affect our ability to qualify as a publicly traded partnership. However, finalized regulations could modify the amount of our gross income that we are able to treat as qualifying income for the purposes of the qualifying income requirement.

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.

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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. Recently enacted legislation alters the procedures for assessing and collecting taxes due for taxable years beginning after December 31, 2017, in a manner that could substantially reduce cash available for distribution to you.

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.

Recently enacted legislation applicable to us for taxable years beginning after December 31, 2017 alters the procedures for auditing large partnerships and also alters the procedures for assessing and collecting taxes due (including applicable penalties and interest) as a result of an audit. Unless we are eligible to (and choose to) elect to issue revised Schedules K-1 to our partners with respect to an audited and adjusted return, the IRS may assess and collect taxes (including any applicable penalties and interest) directly from us in the year in which the audit is completed under the new rules. If we are required to pay taxes, penalties and interest as the result of audit adjustments, cash available for distribution to our unitholders may be substantially reduced. In addition, because payment would be due for the taxable year in which the audit is completed, unitholders during that taxable year would bear the expense of the adjustment even if they were not unitholders during the audited taxable year.

You will be required to pay taxes on your share of our income, including your share of income from the cancellation of debt, even if you do not receive cash distributions from us.

You will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income, whether or not you receive cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the actual tax liability which results from that income.

In response to current market conditions, we may engage in transactions to delever the Partnership and manage our liquidity that may result in income and gain to you without a corresponding cash distribution. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, you may be allocated taxable income and gain resulting from the sale without receiving a cash distribution. Further, 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 (COD income) being allocated to our unitholders as taxable income. You may be allocated COD income, and income tax liabilities arising therefrom may exceed cash distributions. The ultimate effect of any such allocations will depend on the unitholder's individual tax position with respect to its units. Unitholders are encouraged to consult their tax advisors with respect to the consequences to them of COD 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. 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. 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.

Tax-exempt entities, regulated investment companies and non-U.S. persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax-exempt entities, including employee benefit plans and individual retirement accounts (known as “IRAs”), and non-U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations exempt from federal income tax, including individual retirement accounts and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non-U.S. persons will be reduced by withholding taxes imposed at the highest effective applicable tax rate, and non-U.S. persons will be required to file U. S. federal income tax returns and pay tax on their share of our taxable income. If you are a tax-exempt entity or a non-U.S. person, you should consult your tax advisor before investing in our common units.

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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, instead of on the basis of the date a particular unit is transferred. The U. S. Department of the Treasury recently adopted final Treasury Regulations allowing a similar monthly simplifying convention for taxable years beginning on or after August 3, 2015. However, such regulations do not specifically authorize the use of the proration method we adopted for our 2015 taxable year and may not specifically authorize all aspects of our proration method thereafter. If the IRS were to successfully challenge our proration method or new Treasury Regulations were issued, 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 (e.g., 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.

The sale or exchange of 50% or more of our capital and profits interests within a twelve-month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have constructively terminated as a partnership for federal income tax purposes if there is a sale or exchange within a twelve-month period of 50% or more of the total interests in our capital and profits. For purposes of determining whether the 50% threshold has been met, multiple sales of the same interest will be counted only once. Our termination would, among other things, result in the closing of our taxable year for all unitholders which could result in us filing two tax returns (and unitholders receiving two Schedule K-1s) for one calendar year. Our termination could also result in a deferral of depreciation deductions allowable in computing our taxable income. In the case of a unitholder reporting on a taxable year other than a calendar year, the closing of our taxable year may also result in more than twelve months of our taxable income or loss being includable in its taxable income for the year of termination. Our termination would not affect our classification as a partnership for federal income tax purposes, but instead, we would be treated as a new partnership for federal income tax purposes. If treated as a new partnership, we must make new tax elections and could be subject to penalties if we are unable to determine that a termination occurred. Pursuant to an IRS relief procedure a publicly traded partnership that has technically terminated may request special relief which, if granted by the IRS, among other things, would permit the partnership to provide only a single Schedule K-1 to unitholders for the tax years in which the termination occurs.

Our unitholders will likely be subject to state and local taxes and return filing requirements in states 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 our executive offices in Kansas City, Missouri and Fort Worth, Texas.

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
2015
December 31, 2015	$	18.80	$	22.79	$	1.375
September 30, 2015	22.20		44.50		1.375
June 30, 2015	40.10		70.10		1.375
March 31, 2015	58.00		84.60		1.375
2014
December 31, 2014	$	58.40	$	107.30	$	1.375
September 30, 2014	105.50		154.00		1.375
June 30, 2014	128.50		150.40		1.375
March 31, 2014	124.10		145.10		1.375

On October 22, 2015, the board of directors of our 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, our common unitholders 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.

The last reported sale price of Crestwood Equity's common units on the NYSE on February 12, 2016, was $9.04. As of that date, Crestwood Equity had 69,496,248 common units issued and outstanding, which were held by 281 unitholders of record.

Distribution Policy

Preferred Units. Crestwood Equity is required to make quarterly distributions to its Preferred Unit holders. The holders of the Preferred Units are entitled to receive fixed quarterly distributions of $0.2111 per unit. For the seven quarters following the quarter ended September 30, 2015 (the Initial Distribution Period), distributions on the Preferred Units can be made in additional Preferred Units, cash, or a combination thereof, at our election. If Crestwood Equity elects to pay the quarterly distribution through the issuance of additional Preferred Units, the number of units to be distributed will be calculated as the fixed quarterly distribution of $0.2111 per unit divided by the cash purchase price of $9.13 per unit. Crestwood Equity accrues the fair value of such distribution at the end of the quarterly period and adjust the fair value of the distribution on the date the additional Preferred Units are distributed. Distributions on the Preferred Units following the Initial Distribution Period will be made in cash unless, subject to certain exceptions, (i) there is no distribution being paid on Crestwood Equity's common units and (ii) Crestwood Equity's available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to its Preferred Unit holders. If Crestwood Equity fails to pay the full amount payable to its Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.2567 per unit, and (y) Crestwood Equity will not be permitted to declare or make any distributions to its common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if Crestwood Equity fails to pay in full any Preferred Distribution (as defined in its partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

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:

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•	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;

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 12, 2016, Crestwood Equity paid a distribution of $1.3750 per limited partner unit ($5.50 per limited partner unit on an annualized basis) to its unitholders of record on February 5, 2016.

Issuer Purchases of Equity Securities

For the year ended December 31, 2015, 26,095 Crestwood Equity common units were relinquished 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, 2015:



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	—	$	—	987,605
Total	—	$	—	987,605

Crestwood Midstream. Prior to the Simplification Merger, Crestwood Midstream's common units representing limited partner interests were traded on the NYSE under the symbol “CMLP.” As a result of the completion of the Simplification Merger on September 30, 2015, Crestwood Midstream became a wholly-owned subsidiary of Crestwood Equity, its common units ceased to be issued on the NYSE and its IDRs were eliminated.

The following table sets forth the range of high and low sales prices of the Crestwood Midstream common units prior to the Simplification Merger, 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
2015
June 30, 2015	$	10.84	$	16.90	$	0.410
March 31, 2015	13.03		16.77		0.410
2014
December 31, 2014	$	13.73	$	22.78	$	0.410
September 30, 2014	20.23		24.25		0.410
June 30, 2014	21.25		24.20		0.410
March 31, 2014	21.62		24.88		0.410

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Item 6. Selected Financial Data.

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

Crestwood Equity. The Crestwood Equity 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, 2015 and balance sheet data as of December 31, 2015 and 2014 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, 2012 and the balance sheet data as of December 31, 2013, 2012 and 2011 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. EBITDA is defined as income before income taxes, plus debt-related costs (net interest and debt expense and loss on modification/extinguishment of debt) and depreciation, amortization and accretion expense. In addition, Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates for our proportionate share of their depreciation and interest. Adjusted EBITDA also considers the impact of certain significant items, such as unit-based compensation charges, gains and impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, certain costs related to our 2015 cost savings initiatives, the change in fair value of commodity inventory-related derivative contracts, 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 that these derivatives relate to. 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 an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.

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	Crestwood Equity Partners LP
	Year Ended December 31,
	2015			2014 (1)			2013			2012			2011
	(in million, except per unit data)
Statement of Income Data:
Revenues	$	2,632.8		$	3,931.3		$	1,426.7		$	239.5		$	205.8
Operating income (loss)	(2,084.8		)	117.9			28.2			61.4			71.0
Income (loss) before income taxes	(2,305.1		)	(9.3		)	(49.6		)	25.6			43.4
Net income (loss)	(2,303.7		)	(10.4		)	(50.6		)	24.4			42.1
Net income (loss) attributable to Crestwood Equity Partners LP	(1,666.9		)	56.4			6.7			14.9			7.7

Performance Measures:

Diluted net income (loss) per limited partner unit: ⁽²⁾	$	(54.00	)	$	3.03		$	0.59		$	3.73		$	1.93

Distributions declared per limited partner unit⁽³⁾	$	5.50		$	5.50		$	6.925		$	13.30		$	28.20

Other Financial Data:
EBITDA (unaudited)	$	(1,844.9	)	$	403.1		$	196.2		$	134.6		$	124.9
Adjusted EBITDA (unaudited)	527.4			495.9			297.7			134.4			110.9
Net cash provided by operating activities	440.7			283.0			188.3			102.1			86.3
Net cash used in investing activities	(212.7		)	(483.0		)	(1,042.9		)	(616.6		)	(456.5		)
Net cash provided by (used in) financing activities	(236.3		)	203.6			859.7			513.8			371.0

Balance Sheet Data:
Property, plant and equipment, net	$	3,310.8		$	3,893.8		$	3,905.3		$	1,102.4		$	916.8
Total assets	5,803.7			8,461.4			8,523.2			2,301.6			1,739.2
Total debt, including current portion	2,543.8			2,396.5			2,266.0			685.2			512.5
Other long-term liabilities⁽⁴⁾	47.5			47.2			140.4			17.2			15.5
Partners' capital	2,946.9			5,584.5			5,508.6			1,550.7			1,120.0

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	Crestwood Equity Partners LP
	Year Ended December 31,
	2015			2014			2013			2012			2011
	(in millions)
Reconciliation of Net Income to EBITDA and Adjusted EBITDA:
Net income (loss)	$	(2,303.7	)	$	(10.4	)	$	(50.6	)	$	24.4		$	42.1
Depreciation, amortization and accretion	300.1			285.3			167.9			73.2			53.9
Interest and debt expense, net	140.1			127.1			77.9			35.8			27.6
Loss on modification/extinguishment of debt	20.0			—			—			—			—
Provision (benefit) for income taxes	(1.4		)	1.1			1.0			1.2			1.3
EBITDA	$	(1,844.9	)	$	403.1		$	196.2		$	134.6		$	124.9
Unit-based compensation charges	19.7			21.3			17.4			1.9			0.9
(Gain) loss on long-lived assets, net⁽⁵⁾	821.2			1.9			(5.3		)	—			(1.1		)
Goodwill impairment⁽⁶⁾	1,406.3			48.8			4.1			—			—
(Gain) loss on contingent consideration⁽⁷⁾	—			8.6			31.4			(6.8		)	(17.2		)
Loss from unconsolidated affiliates, net	60.8			0.7			0.1			—			—
Adjusted EBITDA from unconsolidated affiliates, net	25.3			6.9			2.5			—			—
Change in fair value of commodity inventory-related derivative contracts	5.4			(10.3		)	10.7			—			—
Significant transaction and environmental-related costs and other items⁽⁸⁾	33.6			14.9			40.6			4.7			3.4
Adjusted EBITDA	$	527.4		$	495.9		$	297.7		$	134.4		$	110.9

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	Crestwood Equity Partners LP
	Year Ended December 31,
	2015			2014			2013			2012			2011
Reconciliation of Net Cash Provided by Operating Activities to EBITDA and Adjusted EBITDA:
Net cash provided by operating activities	$	440.7		$	283.0		$	188.3		$	102.1		$	86.3
Net changes in operating assets and liabilities	(98.0		)	73.8			(19.6		)	(4.1		)	(4.2		)
Amortization of debt-related deferred costs, discounts and premiums	(8.9		)	(8.5		)	(9.2		)	(5.5		)	(3.5		)
Interest and debt expense, net	140.1			127.1			77.9			35.8			27.6
Market adjustment on interest rate swaps	0.5			2.7			1.7			—			—
Unit-based compensation charges	(19.7		)	(21.3		)	(17.4		)	(1.9		)	(0.9		)
Gain (loss) on long-lived assets, net⁽⁵⁾	(821.2		)	(1.9		)	5.3			—			1.1
Goodwill impairment⁽⁶⁾	(1,406.3		)	(48.8		)	(4.1		)	—			—
Gain (loss) on contingent consideration⁽⁷⁾	—			(8.6		)	(31.4		)	6.8			17.2
Earnings (loss) from unconsolidated affiliates, net	(73.6		)	(0.7		)	(0.1		)	—			—
Deferred income taxes	3.6			5.2			2.8			—			—
Provision (benefit) for income taxes	(1.4		)	1.1			1.0			1.2			1.3
Other non-cash income	(0.7		)	—			1.0			0.2			—
EBITDA	$	(1,844.9	)	$	403.1		$	196.2		$	134.6		$	124.9
Unit-based compensation charges	19.7			21.3			17.4			1.9			0.9
(Gain) loss on long-lived assets, net⁽⁵⁾	821.2			1.9			(5.3		)	—			(1.1		)
Goodwill impairment⁽⁶⁾	1,406.3			48.8			4.1			—			—
(Gain) loss on contingent consideration⁽⁷⁾	—			8.6			31.4			(6.8		)	(17.2		)
Loss from unconsolidated affiliates, net⁽⁸⁾	60.8			0.7			0.1			—			—
Adjusted EBITDA from unconsolidated affiliates, net	25.3			6.9			2.5			—			—
Change in fair value of commodity inventory-related derivative contracts	5.4			(10.3		)	10.7			—			—
Significant transaction and environmental-related costs and other items⁽⁹⁾	33.6			14.9			40.6			4.7			3.4
Adjusted EBITDA	$	527.4		$	495.9		$	297.7		$	134.4		$	110.9


(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, 2013, 2013 and 2012 were restated to reflect the 1-for-10 reverse split.


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


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

(5)

During 2014, we recorded a gain of approximately $30.6 million on the sale of our investment in Tres Palacios Gas Storage LLC. For a further discussion of this transaction see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6. In addition, during 2015 and 2014, we recorded property, plant and equipment impairments of approximately $501.7 million and $13.2 million and intangible asset impairments of approximately $316.6 million and $21.3 million, respectively. 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 2015, 2014 and 2013, 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 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 Jackalope and PRBIC investments of approximately $51.4 million and $23.4 million, respectively. 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 6.


(9)	Significant transaction and environmental-related costs and other items for the years ended December 31, 2015, 2014 and 2013, primarily includes costs incurred related to our 2015 cost savings initiatives, the Simplification Merger, Crestwood Merger and Arrow Acquisition.

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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 our existing businesses and acquisitions;


•	environmental claims;


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


•	interest rates; and


•	the price and availability of debt and equity financing; and


•	the ability to sell or monetize assets in the current market, to reduce indebtedness or for other general partnership purposes.

We have described under Item Part I, 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 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. 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 as of December 31, 2015. Crestwood Midstream's general partner, Crestwood Midstream GP LLC, is a wholly-owned subsidiary of Crestwood Equity.

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Our Company

We provide broad-ranging services to customers across the crude oil, NGL and natural gas 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 2.6 Bcf/d of gathering capacity, 481 MMcf/d of processing capacity, 40.9 Bcf of certificated working gas storage capacity and 1.3 Bcf/d of firm transmission capacity;


•	NGL facilities with approximately 24,000 Bbls/d of fractionation capacity and 2.8 million barrels 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 more than 294,000 Bbls/d of NGLs; and


•	crude oil facilities with approximately 125,000 Bbls/d of gathering capacity, approximately 1.5 million barrels of total storage capacity, 48,000 Bbls/d of transportation capacity, and 160,000 Bbls/d of rail loading capacity.

On May 5, 2015, Crestwood Equity, Crestwood Midstream and certain of its affiliates entered into a definitive agreement under which CMLP agreed to merge with a wholly-owned subsidiary of Crestwood Equity (the Simplification Merger). On September 30, 2015, CMLP's unitholders approved the Simplification Merger and we completed the merger on that date. As part of the merger consideration, CMLP's common and preferred unitholders (other than the Company and our subsidiaries) received 2.75 common or preferred units of the Company for each common or preferred unit of CMLP held upon completion of the merger. Contemporaneously with the closing of the Simplification Merger, Crestwood Equity contributed 100% of its interest in Crestwood Operations to Crestwood Midstream. Crestwood Operations' assets consist primarily of the assets utilized by our NGL supply and logistics business, including our West Coast NGL operations, our Seymour NGL storage facility and our fleet of NGL transportation and related rail-to-truck terminal assets. As a result of these transactions, Crestwood Equity is a holding company and all of our operating assets and investments are owned by or through Crestwood Midstream.

In conjunction with the Simplification Merger, we modified our business segments and our financial statements now reflect three operating and reporting segments: (i) gathering and processing (G&P), 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 (formerly NGL and crude services operations), which includes our NGL supply and logistics business, crude oil storage and rail loading facilities and fleet, and salt production business. Consequently, the results of our Arrow operations are now reflected in our gathering and processing operations for all periods presented and our COLT and PRBIC operations are now reflected in our storage and transportation operations for all periods presented. These respective operations were previously included in our NGL and crude services operations. All of our operations are conducted by or through Crestwood Midstream. Below is a discussion of events that highlight our core business and financing activities.

Gathering and Processing

Our G&P operations provide gathering, compression, treating, and processing services to producers in multiple unconventional resource plays across the United States 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 shale plays positions us well to (i) generate greater returns in the near term while commodity prices remain depressed, (ii) capture greater upside economics when commodity prices normalize, and (iii) in general, better manage through commodity price cycles and production changes associated therewith.

Our G&P operations primarily include:

•

Bakken Shale. We own and operate an integrated crude oil, natural gas and produced water gathering system (the Arrow system) on Fort Berthold Indian Reservation in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota. The Arrow system consists of 590 miles of low-pressure gathering pipeline capable of gathering 100 MMcf/d of natural gas, 125 MBbls/d of crude oil, and 40 MBbls/d of produced water. We also have approximately 266,000 barrels of crude oil working storage capacity at the Arrow central delivery point;


•	Marcellus Shale. 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 138,080 horsepower of compression;

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•

Barnett Shale. 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 530 MMcf/d of dry natural gas produced by our customers in Tarrant and Denton Counties, Texas;


•	Fayetteville Shale. 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;


•	Delaware Permian. We own and operate low-pressure dry gas and rich natural gas systems with a primary focus on the Willow Lake system that includes a gathering and processing system with approximately 50 MMcf/d of capacity to serve our customers in Eddy County, New Mexico (Willow Lake system);

•

Other 100% Owned and Operated Systems. We own and operate (i) 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 (Granite Wash system); and (ii) high-pressure natural gas gathering pipelines with a gathering capacity of approximately 100 MMcf/d that provide gathering and treating services to our customers located in Sabine Parish, Louisiana (Haynesville/Bossier system); and

•

PRB Niobrara Shale. We own a 50% ownership interest in the Jackalope joint venture with Williams, which we account for under the equity method of accounting. The joint venture, operated by Williams, owns the Jackalope gas gathering system and Bucking Horse processing plant. The Jackalope system is supported by a 20-year gathering and processing agreement with Chesapeake under an area of dedication of approximately 388,000 gross acres in the core of the PRB Niobrara.

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. During 2015, two of our G&P customers, Quicksilver and Sabine filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In January 2016, Quicksilver executed an asset purchase agreement with a third party for the sale of its U.S. oil and gas assets. The sale is expected to close on March 31, 2016, pending certain closing conditions. On February 5, 2016, Quicksilver filed a motion to reject its gathering agreements with us. We filed an objection to this motion on February 26, 2016 and a hearing is scheduled in Delaware on March 4, 2016. We are in discussions with the third party regarding those agreements. We continue to provide services to Quicksilver, and the outcome of its restructuring process could have a material impact on our G&P segment's results of operations. Sabine continues to work with the bankruptcy court on its bankruptcy filing, and we continue to monitor their proceedings, and the outcome could impact our G&P segment's results of operations in the future.

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 fixed-fee and, to a lesser extent, percent-of-proceeds contracts. We have historically taken title to the crude oil and natural gas volumes gathered under Arrow's fixed-fee contracts, and we remit netbacks to our producer customers based on the market prices at which we sell the crude oil and natural gas. On our other G&P systems, we do not take title to natural gas or NGLs under our fixed-fee contracts, whereas under our percent-of-proceeds contracts, we take title to the residue gas, NGLs and condensate and remit a portion of the sale proceeds to the producer based on prevailing commodity prices. 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.

Storage and Transportation

Our storage and transportation segment consists of our natural gas storage and transportation assets as follow:

•

Northeast Storage and Transportation. We have four natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake) and three transportation pipelines (North/South Facilities, MARC I and the East Pipeline) located in the Northeast in or near the Marcellus Shale. Our storage facilities provide 40.9 Bcf of certificated firm storage capacity and 1.3 Bcf/d of firm transportation capacity to producers, utilities, marketers and other customers. We believe the location of our storage and transportation assets in the Northeast relative to New York City and other premium demand markets along the East Coast helps to insulate our operations from production and commodity price changes that can more easily impact storage and transportation operators in other geographic regions, including Texas;

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•

COLT Hub. 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 and which complements our Arrow acquisition. Located approximately 60 miles away from Arrow’s central delivery point, the COLT Hub interconnects with the Arrow system through the Hiland and Tesoro pipeline systems. The hub, which can be sourced by numerous pipeline systems or truck, is capable of loading up to 160,000 Bbls/d and has approximately 1.2 million barrels of total crude oil storage capacity; and

•

PRBIC. 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 PRB Niobrara. The joint venture, operated by Twin Eagle, sources crude oil production from Chesapeake and other PRB Niobrara producers. PRBIC includes 20,000 Bbls/d of rail loading capacity and 380,000 barrels of crude oil working storage capacity. Additionally, in anticipation of growing PRB Niobrara crude oil volumes, PRBIC expanded its pipeline terminal to include connections to Kinder Morgan's HH Pipeline system in July 2015 and initiated a pipeline project to interconnect with Plains All American Pipeline's Rocky Mountain Pipeline system, which is expected to be completed in March 2016.

•

Tres Holdings. We own a 50.01% ownership interest in Tres Holdings LLC (Tres Holdings), a joint venture between Crestwood Midstream and an affiliate of Brookfield, which owns the remaining 49.99% interest in Tres Holdings. Tres Holdings owns Tres Palacios, which owns a FERC-certificated 38.4 Bcf multi-cycle, salt dome natural gas storage facility. Its 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 10 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan Inc.'s Houston central processing plant. In December 2014, Crestwood Equity sold its 100% membership interest in Tres Palacios to Tres Holdings. As a result of the sale, effective December 1, 2014, Crestwood Equity deconsolidated Tres Palacios' operations. We account for the investment in Tres Holdings under the equity method of accounting. Brookfield and Tres Palacios entered into a five-year, fixed fee contract under which Tres Palacios will make 15 Bcf of firm storage capacity and 150,000 Dth/d of enhanced interruptible services available to Brookfield.

The cash flows from our storage and transportation operations are predominantly fee-based under contracts with an original term ranging from 1-10 years. Our cash flows from interruptible and other hub services tends to increase during the peak winter season. Our current cash flows from crude-by-rail facilities are largely supported by take-or-pay contracts with refiners and, to a lesser extent, marketer customers and are not significantly affected in the short term by changing commodity prices, seasonality or weather fluctuations. We are working to renew long-term storage and loading contracts associated with our COLT Hub operations. Several of these contracts expire in 2016 and we expect to extend the contract terms for several of our existing customers. We are also pursuing multiple pipeline and storage projects at the COLT terminal supported by long-term take-or-pay contracts.

Marketing, Supply and Logistics

Our marketing, supply and logistics segment consists of our NGL supply and logistics business and US Salt. We utilize our over-the-road and rail fleet, processing and storage facilities, and contracted pipeline capacity on a portfolio basis to provide integrated supply and logistics solutions to producers, refiners and other customers.

Our marketing, supply and logistics operations primarily include:

•

NGL Supply and Logistics Business. Our NGL supply and logistics business serves producers, refiners and other customers that produce or consume natural gas liquids, including primarily propane, butane and natural gasoline. To provide these services, we utilize our portfolio of proprietary and third party NGL processing, fractionation, storage, terminal and trucking assets including our fleet of rail and rolling stock, rail-to-truck terminals, West Coast processing, fractionation and storage operations, NGL storage facilities, and contracted capacity (including leased storage capacity at major hubs and leased transportation capacity on major NGL pipelines);


•	Crude Oil and Produced Water Trucking. Our crude oil and produced water trucking fleet has 48,000 Bbls/d of crude oil and produced water transportation capacity. These assets were acquired in the first half of 2014. We provide hauling services to customers in North Dakota, Montana, Wyoming, Texas and New Mexico; and


•	US Salt. Our salt production business, which has a plant near Watkins Glen, New York, is capable of producing more than 400,000 tons of evaporated salt products annually. US Salt’s solution mining process creates underground caverns that can be developed into natural gas and NGL storage capacity.

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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. The cash flows from our salt operations represent sales to creditworthy customers typically under contracts that are less than one year in duration, and are relatively stable and not subject to seasonal or cyclical variation due to the use of, and demand for, salt products in everyday life.

Outlook and Trends

Our business objective is to create long-term value for our stakeholders by maximizing throughput on our assets, expanding our services and exercising prudent control of operating and administrative costs, resulting in stable operating margins and improving cash flows from operations. Our business strategy further depends on our ability to provide increased services to our customers at competitive fees and develop growth projects that can be financed appropriately.

We have positioned the Company to generate consistent results in a low commodity price environment. Many of our assets are located on long-term, core acreage dedications in shale plays which are economic to varying degrees based upon natural gas, NGL and crude oil prices, the availability of midstream infrastructure to flow production to market and the operational and financial condition of our diverse customer base. We believe the diversity of our asset portfolio, wide range of services provided and extensive customer portfolio, taken together, provides us with a positive forward view of our ability to be successful in the current market which has been impacted by prolonged low commodity prices. In addition, a substantial portion of the midstream services we provide to customers in the shale plays are based on fixed fee, take-or-pay or cost-of-service agreements that ensure a minimum level of cash flow regardless of actual commodity prices or volumetric throughput. We are actively working with our customers to further improve the profitability of their operations through the services we offer, and in certain instances, by adjusting our rate, service and/or volume commitment structures to incentivize them to utilize our services in the short-term while preserving long-term flexibility in a challenging market. In particular, we are in active discussions with a number of our customers regarding amendments and/or extensions of their contracts, and these discussions will continue into 2016.

In 2016, we are evaluating strategic actions to substantially de-risk the investment profile of Crestwood and position the Company to emerge from this challenging market environment as a stronger, better capitalized company. These are designed to address our near-term cost of capital limitations and position the Company for long-term value creation for all stakeholders when the market improves and include reducing capital expenditures, further reducing costs, divesting of assets, evaluating distributions and strengthening the balance sheet including repayment of indebtedness.

During 2015, we completed a number of cost-reduction efforts, including the Simplification Merger, and we decreased our on-going expenses related to operations, maintenance and general and administrative matters by $26.4 million during the year ended December 31, 2015 compared to 2014, excluding $29.4 million of upfront costs related to this cost savings initiative and the Simplification Merger. We continue to pursue additional opportunities to further reduce costs in 2016, which we believe will result in lower expenses in 2016 compared to 2015. In addition, we expect our 2016 capital expenditures to be limited to previously committed contractual projects around our existing asset footprint of approximately $50 million to $75 million in 2016.

Based on current operations, we expect financial results in 2016 that are relatively consistent with our 2015 results, despite continued anticipated depressed commodity prices. Through the execution of strategic efforts described above, we expect to reposition the Company for increasing stability and strength through a continued challenging market environment, which will over the long-term, best position us to achieve our chief business objective to create long-term value for our stakeholders.

Regulatory Matters

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

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How We Evaluate Our Operations

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

EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company's operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. 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 (net interest and debt expense and loss on modification/extinguishment of debt) and depreciation, amortization and accretion expense. In addition, Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates for our proportionate share of their depreciation and interest. Adjusted EBITDA also considers the impact of certain significant items, such as unit-based compensation charges, gains and impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, certain costs related to our 2015 cost savings initiatives, the change in fair value of commodity inventory-related derivative contracts, 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 that these derivatives relate to. 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 an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.

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

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Results of Operations

In conjunction with the closing of the Simplification Merger on September 30, 2015, CEQP contributed 100% of its interest in Crestwood Operations to CMLP, and as a result of this equity contribution, CMLP controls the operating and financial decisions of Crestwood Operations. CMLP accounted for this transaction as a reorganization of entities under common control and the accounting standards related to such transactions requires CMLP to retroactively adjust its historical results to reflect the operations of Crestwood Operations as being acquired on June 19, 2013, the date in which CMLP and Crestwood Operations came under common control. The contribution of Crestwood Operations to CMLP had no impact on CEQP's results of operations.

The following table summarizes our results of operations for each of the three years ended December 31 (in millions).



	Crestwood Equity									Crestwood Midstream
	Year Ended December 31,									Year Ended December 31,
	2015			2014			2013			2015		2014
Revenues	$	2,632.8		$	3,931.3		$	1,426.7		2,632.8		3,917.5
Costs of product/services sold	1,883.5			3,165.3			1,002.3			1,883.5		3,154.8
Operations and maintenance	190.2			203.3			104.6			188.7		195.4
General and administrative	116.3			100.2			93.5			105.6		91.7
Depreciation, amortization and accretion	300.1			285.3			167.9			278.5		255.4
Gain (loss) on long-lived assets, net	(821.2		)	(1.9		)	5.3			(227.8	)	(35.1	)
Goodwill impairment	(1,406.3		)	(48.8		)	(4.1		)	(1,149.1	)	(48.8	)
Loss on contingent consideration	—			(8.6		)	(31.4		)	—		(8.6	)
Operating income (loss)	(2,084.8		)	117.9			28.2			(1,200.4	)	127.7
Loss from unconsolidated affiliates, net	(60.8		)	(0.7		)	(0.1		)	(60.8	)	(0.7	)
Interest and debt expense, net	(140.1		)	(127.1		)	(77.9		)	(130.5	)	(111.4	)
Loss on modification/extinguishment of debt	(20.0		)	—			—			(18.9	)	—
Other income, net	0.6			0.6			0.2			—		—
(Provision) benefit for income taxes	1.4			(1.1		)	(1.0		)	—		(0.9	)
Net income (loss)	(2,303.7		)	(10.4		)	(50.6		)	(1,410.6	)	14.7
Add:
Interest and debt expense, net	140.1			127.1			77.9			130.5		111.4
Loss on modification/extinguishment of debt	20.0			—			—			18.9		—
Provision (benefit) for income taxes	(1.4		)	1.1			1.0			—		0.9
Depreciation, amortization and accretion	300.1			285.3			167.9			278.5		255.4
EBITDA	(1,844.9		)	403.1			196.2			(982.7	)	382.4
Unit-based compensation charges	19.7			21.3			17.4			18.1		18.1
(Gain) loss on long-lived assets, net	821.2			1.9			(5.3		)	227.8		35.1
Goodwill impairment	1,406.3			48.8			4.1			1,149.1		48.8
Loss on contingent consideration	—			8.6			31.4			—		8.6
Loss from unconsolidated affiliates, net	60.8			0.7			0.1			60.8		0.7
Adjusted EBITDA from unconsolidated affiliates, net	25.3			6.9			2.5			25.3		6.9
Change in fair value of commodity inventory-related derivative contracts	5.4			(10.3		)	10.7			5.4		(10.3	)
Significant transaction and environmental-related costs and other items⁽¹⁾	33.6			14.9			40.6			28.5		13.9
Adjusted EBITDA	527.4			495.9			297.7			532.3		504.2

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	Crestwood Equity									Crestwood Midstream
	Year Ended December 31,									Year Ended December 31,
	2015			2014			2013			2015			2014
EBITDA:
Net cash provided by operating activities	$	440.7		$	283.0		$	188.3		471.8			437.3
Net changes in operating assets and liabilities	(98.0		)	73.8			(19.6		)	(107.9		)	(47.9		)
Amortization of debt-related deferred costs, discounts and premiums	(8.9		)	(8.5		)	(9.2		)	(8.1		)	(7.3		)
Interest and debt expense, net	140.1			127.1			77.9			130.5			111.4
Market adjustment on interest rate swaps	0.5			2.7			1.7			—			—
Unit-based compensation charges	(19.7		)	(21.3		)	(17.4		)	(18.1		)	(18.1		)
Gain (loss) on long-lived assets, net	(821.2		)	(1.9		)	5.3			(227.8		)	(35.1		)
Goodwill impairment	(1,406.3		)	(48.8		)	(4.1		)	(1,149.1		)	(48.8		)
Gain (loss) on contingent consideration	—			(8.6		)	(31.4		)	—			(8.6		)
Earnings (loss) from unconsolidated affiliates, net, adjusted for cash distributions	(73.6		)	(0.7		)	(0.1		)	(73.6		)	(0.7		)
Deferred income taxes	3.6			5.2			2.8			0.3			(0.7		)
Provision (benefit) for income taxes	(1.4		)	1.1			1.0			—			0.9
Other non-cash income (expense)	(0.7		)	—			1.0			(0.7		)	—
EBITDA	$	(1,844.9	)	$	403.1		$	196.2		$	(982.7	)	$	382.4
Unit-based compensation charges	19.7			21.3			17.4			18.1			18.1
(Gain) loss on long-lived assets, net	821.2			1.9			(5.3		)	227.8			35.1
Goodwill impairment	1,406.3			48.8			4.1			1,149.1			48.8
(Gain) loss on contingent consideration	—			8.6			31.4			—			8.6
Loss from unconsolidated affiliates, net	60.8			0.7			0.1			60.8			0.7
Adjusted EBITDA from unconsolidated affiliates, net	25.3			6.9			2.5			25.3			6.9
Change in fair value of commodity inventory-related derivative contracts	5.4			(10.3		)	10.7			5.4			(10.3		)
Significant transaction and environmental-related costs and other items⁽¹⁾	33.6			14.9			40.6			28.5			13.9
Adjusted EBITDA	$	527.4		$	495.9		$	297.7		$	532.3		$	504.2

(1) Significant transaction and environmental-related costs and other items for the years ended December 31, 2015, 2014 and 2013, primarily includes costs incurred related to our 2015 cost savings initiatives, the Simplification Merger, the Crestwood Merger and the Arrow Acquisition.

Segment Results

In conjunction with the Simplification Merger, we modified our segments and our financial statements now reflect three operating and reporting segments: (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) marketing, supply and logistics operations (formerly NGL and crude services operations). Consequently, the results of our Arrow operations are now reflected in our gathering and processing operations for all periods presented and our COLT operations and PRBIC investment are now reflected in our storage and transportation operations for all periods presented. These respective operations were previously included in our NGL and crude services operations.

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



Crestwood Equity	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics
Revenues	$	1,381.0		$	266.3		$	985.5
Intersegment revenue	66.7			—			(66.7		)
Costs of product/services sold	1,103.9			20.1			759.5
Operations and maintenance expense	89.0			31.7			69.5
Loss on long-lived assets, net	(787.3		)	(1.6		)	(32.3		)
Goodwill impairment	(329.7		)	(623.4		)	(453.2		)
Loss from unconsolidated affiliates	(43.4		)	(17.4		)	—
EBITDA for the year ended December 31, 2015	$	(905.6	)	$	(427.9	)	$	(395.7	)

Revenues	$	2,166.8		$	264.6		$	1,499.9
Intersegment revenue	50.0			—			(50.0		)
Costs of product/services sold	1,859.9			33.3			1,272.1
Operations and maintenance expense	102.8			28.8			71.7
Gain (loss) on long-lived assets	(32.7		)	33.8			(3.0		)
Goodwill impairment	(18.5		)	—			(30.3		)
Loss on contingent consideration	(8.6		)	—			—
Earnings (loss) from unconsolidated affiliates	0.5			(1.2		)	—
EBITDA for the year ended December 31, 2014	$	194.8		$	235.1		$	72.8

Revenues	$	510.0		$	130.9		$	785.8
Costs of product/services sold	267.5			19.7			715.1
Operations and maintenance expense	58.7			14.2			31.7
Gain (loss) on long-lived assets	5.4			—			(0.1		)
Goodwill impairment	(4.1		)	—			—
Loss on contingent consideration	(31.4		)	—			—
Earnings (loss) from unconsolidated affiliates	0.1			(0.2		)	—
EBITDA for the year ended December 31, 2013	$	153.8		$	96.8		$	38.9



Crestwood Midstream
Revenues	$	1,381.0		$	266.3		$	985.5
Intersegment revenue	66.7			—			(66.7		)
Costs of product/services sold	1,103.9			20.1			759.5
Operations and maintenance expense	89.0			30.2			69.5
Loss on long-lived assets, net	(194.1		)	(1.4		)	(32.3		)
Goodwill impairment	(72.5		)	(623.4		)	(453.2		)
Loss from unconsolidated affiliates	(43.4		)	(17.4		)	—
EBITDA for the year ended December 31, 2015	$	(55.2	)	$	(426.2	)	$	(395.7	)

Revenues	$	2,166.8		$	250.8		$	1,499.9
Intersegment revenue	50.0			—			(50.0		)
Costs of product/services sold	1,859.9			22.8			1,272.1
Operations and maintenance expense	102.8			22.1			70.5
Gain (loss) on long-lived assets	(32.7		)	0.6			(3.0		)
Goodwill impairment	(18.5		)	—			(30.3		)
Loss on contingent consideration	(8.6		)	—			—
Earnings (loss) from unconsolidated affiliates	0.5			(1.2		)	—
EBITDA for the year ended December 31, 2014	$	194.8		$	205.3		$	74.0

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Segment Results

Below is a discussion of the factors that impacted EBITDA by segment for the three years ended December 31, 2015, 2014 and 2013.

Gathering and Processing

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

EBITDA for CMLP's G&P segment decreased by approximately $250.0 million for the year ended December 31, 2015 compared to 2014 primarily due to property, plant and equipment, intangible asset and goodwill impairments of approximately $265.5 million recorded during 2015 related to our Fayetteville, Granite Wash and Haynesville operations, compared to $51.7 million of impairments during the year ended December 31, 2014. For a further discussion of these impairments, see Part IV, Item 15. Financial Statements Schedules, Note 2.

Also contributing to CMLP's EBITDA decrease was a $769.1 million decrease in revenues, offset by a $756.0 million decrease in costs of products/services sold and a $13.8 million decrease in operations and maintenance expense. The revenue and costs of product/services sold decreases were primarily driven by our Arrow operations, which experienced a decrease in product revenues of $742.9 million partially offset by a decrease in its costs of product/services sold of $738.4 million. The decrease in product revenues and costs of product/services sold was driven by the decreases in market prices on crude oil, which caused average crude oil prices on our crude oil sales to decrease by approximately 50% during the year ended December 31, 2015 compared to 2014. We experienced a $21.7 million increase in Arrow's service revenues due to an increase of 14%, 30% and 49% in its crude oil, natural gas and water volumes, respectively, during the year ended December 31, 2015 compared to 2014, as new wells were connected to the system.

During the year ended December 31, 2015, we experienced a decrease in our G&P segment's operations and maintenance expense of approximately $13.8 million compared to 2014 resulting from cost-reduction efforts undertaken in 2015, which is further described in Outlook and Trends above.

CMLP's G&P segment EBITDA was also impacted by an $8.6 million loss on contingent consideration recorded for the year ended December 31, 2014. The loss on contingent consideration that reflected the fair value of an earn-out premium associated with the original acquisition of our Marcellus G&P assets from Antero Resources Appalachian Corporation (Antero) in 2012. The earn-out provision, which was settled in February 2015, allowed Antero to receive an additional $40.0 million payment when gathering volumes exceeded a certain threshold as defined in the acquisition agreements.

During the year ended December 31, 2015, we recorded a $51.4 million impairment of our Jackalope Gas Gathering Services, L.L.C. (Jackalope) equity investment. Offsetting this impairment, our equity earnings from Jackalope increased by approximately $7.5 million for the year ended December 31, 2015 compared to 2014. The increase was primarily attributable to Jackalope placing its Bucking Horse processing plant in service in January 2015.

EBITDA for CEQP's G&P segment decreased by approximately $1,100.4 million for the year ended December 31, 2015 compared to 2014, due to all of the factors as discussed above for CMLP. In addition to the impairments described above, CEQP's G&P segment EBITDA was impacted by $850.5 million of property, plant and equipment, intangible asset and goodwill impairments related to our Barnett operations. For a further discussion of these impairments, see Part IV, Item 15. Financial Statement Schedules, Note 2.

Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

EBITDA for CEQP's G&P segment EBITDA increased by approximately $41.0 million for the year ended December 31, 2014 compared to 2013, primarily due to our 2014 results having a full year of operations from our Arrow assets compared to two months in 2013. Arrow contributed EBITDA of approximately $55.8 million and $4.1 million for the years ended December 31, 2014 and 2013.

Revenues increased by approximately $1,706.8 million during the year ended December 31, 2014 compared to 2013, primarily due to our Arrow operations as discussed above. Arrow contributed revenues of approximately $1,884.3 million and $218.8 million for the years ended December 31, 2014 and 2013. The remaining revenue increase was primarily driven by higher gathering and compression volumes during the year ended December 31, 2014 compared to 2013. We gathered approximately 1.2 Bcf/d of natural gas on our G&P systems during 2014 compared to 1.0 Bcf/d during 2013. Our compression volumes increased from 0.3 Bcf/d during 2013 to 0.5 Bcf/d in 2014. The increases in our G&P gathering and compression volumes

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were primarily due to several new compressor stations placed in service during 2013 and 2014 in the Marcellus Shale and new wells connected to our systems during 2014.

Partially offsetting the increases described above were higher costs of product/services sold and operations and maintenance expense for the year ended December 31, 2014 compared to 2013 of approximately $1,592.4 million and $44.1 million primarily due to our Arrow operations as discussed above. The remaining increase in our costs of product/services sold was primarily due to higher volumes gathered on our New Mexico gathering systems under a gathering and processing agreement we entered into with Trinity River Energy in April 2014 and increased production at Granite Wash due to new wells connected during 2014.

In addition to the higher costs discussed above, CEQP's G&P segment's EBITDA was impacted by an $8.6 million and $31.4 million loss on contingent consideration recorded during the years ended December 31, 2014 and 2013 as described above.

We recorded impairments of $51.7 million for the year ended December 31, 2014 related to our Granite Wash and Fayetteville operations compared to $4.1 million of impairments recorded for the year ended December 31, 2013 related to our Haynesville operations. For a further discussion of these impairments, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

Storage and Transportation

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

EBITDA for CMLP's storage and transportation segment decreased by approximately $631.5 million for the year ended December 31, 2015 compared to 2014, primarily due to a $623.4 million goodwill impairment recorded related to our COLT Hub operations. For a further discussion of this goodwill impairment, see Part IV, Item 15. Financial Statements Schedules, Note 2.

Also contributing to the decrease in CMLP's storage and transportation segment's EBITDA were higher operations and maintenance expenses of approximately $8.1 million for the year ended December 31, 2015 compared to 2014, primarily due to the expansion of the COLT Hub facility (including the release and departure tracks placed in service in December 2014) and other expansion projects placed in service during the last half of 2014 and the first half of 2015, primarily the NS-1 Expansion project.

Partially offsetting the decrease in CMLP's storage and transportation segment's EBITDA described above were higher revenues of approximately $15.5 million and lower costs of product/services sold of approximately $2.7 million. The increase in CMLP's storage and transportation segment's revenues was primarily driven by higher volumes on our COLT Hub as a result of our expansion of the facility discussed above and increased utilization of non-firm capacity on the system, which resulted in an increase in revenues of approximately $17.9 million for the year ended December 31, 2015 compared to 2014. For the year ended December 31, 2015, we loaded approximately 117 MBbls/d of crude on rail cars entering the facility compared to 110 MBbls/d in 2014. Also contributing to the revenue increase was additional firm transportation services resulting from expansion projects placed in service during the last half of 2014 and the first half of 2015 which increased volumes delivered into Millennium Pipeline. Partially offsetting these revenue increases, was a reduction in firm storage revenues due to recontracting efforts yielding rates which were lower in 2015 compared to 2014. For the years ended December 31, 2015 and 2014, total firm throughput from our Northeast storage and transportation services averaged 1.5 Bcf/d in both years.

Also impacting CMLP's storage and transportation segment's EBITDA was a $23.4 million impairment of our PRBIC equity investment. Offsetting this impairment, our equity earnings from our PRBIC investment increased by $4.9 million.

In December 2014, Crestwood Midstream and Brookfield formed the Tres Holdings joint venture and during the years ended December 31, 2015 and 2014, we recorded equity earnings of approximately $2.5 million and $0.2 million from Tres Holdings.

EBITDA for CEQP's storage and transportation segment decreased by approximately $663.0 million for the year ended December 31, 2015 compared to 2014, due to all of the factors as discussed above for CMLP. In addition, in December 2014, CEQP sold its 100% interest in Tres Palacios to the newly formed joint venture between Crestwood Midstream and Brookfield for total cash consideration of approximately $132.8 million (of which approximately $66.4 million was paid by Crestwood Midstream), and as a result, CEQP deconsolidated Tres Palacios. Tres Palacios generated approximately $0.4 million of EBITDA to CEQP's storage and transportation segment's EBITDA prior to its deconsolidation on December 1, 2014. CEQP recognized a gain of approximately $30.6 million on the portion of the sale related to Brookfield. For a further discussion of our investment in Tres Holdings, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6.

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Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Our storage and transportation segment results were included in our consolidated results of operations beginning June 19, 2013 (the date that Crestwood Holdings acquired control of CEQP's general partner), which should be considered in the following discussion of the results of operations of our storage and transportation segment for the year ended December 31, 2014 compared to the year ended December 31, 2013.

EBITDA for CEQP's storage and transportation segment increased by approximately $138.3 million during the year ended December 31, 2014 compared to 2013. The increase in CEQP's storage and transportation segment's EBITDA was due to our 2014 results having a full year of operating results compared to only six months in 2013. In addition, during the year ended December 31, 2014, we recognized a gain of approximately $30.6 million on the sale of our Tres Palacios membership interest as discussed above.

We experienced an increase in demand for our storage and transportation services as evidenced by higher usage on our firm storage and transportation contracts and increased volumes from interruptible services, resulting from increased producer activity and increased locational basis spreads in the Northeast, which was the primary driver for the increase in revenues of approximately $88.7 million year over year. During the year ended December 31, 2014, total firm throughput from our Northeast storage and transportation services averaged approximately 1.5 Bcf/d compared to 1.4 Bcf/d during 2013. The remaining increase in revenues of approximately $45.0 million was due primarily to having a full year of operations from our COLT Hub assets in 2014 compared to six months in 2013. In addition, we experienced higher volumes on our COLT Hub as a result of the expansion of the facility and increased utilization of non-firm capacity on the system. During 2014 and 2013, we loaded approximately 110 MBbls/d and 82 MBbls/d of crude oil on rail cars entering the facility.

Partially offsetting the increases in CEQP's storage and transportation segment's revenues were higher costs of product/services sold primarily related to higher throughput volumes at our North-South and MARC I facilities and higher operations and maintenance expense due to having a full year of storage and transportation operations in 2014 compared to six months in 2013.

Marketing, Supply and Logistics

Year Ended December 31, 2015 Compared to Year Ended December 31, 2014

EBITDA for CMLP's marketing, supply and logistics segment decreased by approximately $469.7 million for the year ended December 31, 2015 compared to 2014, primarily due to impairments of property, plant and equipment and goodwill of approximately $484.4 million related to our West Coast, Watkins Glen, supply and logistics, storage and terminals and trucking operations. During the year ended December 31, 2014, we recorded goodwill and intangible asset impairments of $31.6 million related to Watkins Glen and US Salt operations. For a further discussion of these impairments, see Part IV, Item 15. Financial Statements Schedules, Note 2.

Also contributing to the decrease in CMLP's marketing, supply and logistics segment's EBITDA was a year over year decrease in revenues of approximately $531.1 million, partially offset by lower costs of product/services sold of approximately $512.6 million. These revenue and costs of product/services sold decreases were primarily driven by our NGL terminalling, supply and logistics operations, and include approximately $18.9 million and $51.2 million of gains on our commodity-based derivatives during the years ended December 31, 2015 and 2014.

Revenues from our NGL terminalling, supply and logistics operations decreased by $541.8 million during the year ended December 31, 2015 compared 2014, compared to a decrease of $527.2 million in its costs of product/services sold year over year. These decreases were driven by decreased demand for propane and butane at our NGL terminals and other facilities resulting from lower commodity prices, and the fact that we experienced a milder winter during early 2015 compared to the unusually cold winter during 2014, which reduced our opportunities to capture incremental demand and margin opportunities in these operations.

Our marketing, supply and logistics segment's operations and maintenance expenses were relatively flat for the year ended December 31, 2015 compared to 2014.

EBITDA for CEQP's marketing, supply and logistics segment decreased by approximately $468.5 million for the year ended December 31, 2015 compared to 2014, due to all of the factors as discussed above for CMLP.

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Year Ended December 31, 2014 Compared to Year Ended December 31, 2013

Our marketing, supply and logistics segment results were included in our consolidated results of operations beginning June 19, 2013 (the date that Crestwood Holdings acquired control of CEQP's general partner), which should be considered in the following discussion of the results of operations of our NGL and crude services segment for the year ended December 31, 2014 compared to the year ended December 31, 2013.

CEQP's marketing, supply and logistics segment's EBITDA increased by approximately $33.9 million during the year ended December 31, 2014 compared to 2013, primarily due to higher revenues of $664.1 million, partially offset by higher costs of product/services sold and operations and maintenance expense of $597.0 million. Our costs of product/services sold included $51.2 million of gains and $11.2 million of losses on our commodity-based derivatives during the years ended December 31, 2014 and 2013, respectively. In addition, we recorded $31.6 million of impairments of our Watkins Glen and US Salt reporting units in 2014. For a further discussion of these impairments, see Part IV, Item 15. Financial Statements Schedules, Note 2.

Our NGL terminalling, supply and logistics operations produced CEQP EBITDA of $75.6 million and $25.2 million for the years ended December 31, 2014 and 2013. The increase was due primarily to our 2014 results having a full year of operating compared to six months in 2013.

Other EBITDA Results

As discussed in Part IV, Item 15. Exhibits, Financial Statement Schedule, Note 17, our corporate operations include all general and administrative expenses that are not allocated to our reporting segments, however such expenses impact our consolidated EBITDA.

During the year ended December 31, 2015, CEQP incurred costs of $32.4 million primarily related to our 2015 cost savings initiative and the Simplification Merger. Offsetting the impact of these costs, general and administrative expenses related to CEQP's Corporate operations decreased by approximately $16.3 million for the year ended December 31, 2015 compared to 2014. CEQP's general and administrative expenses increased by approximately $6.7 million for the year ended December 31, 2014 compared to 2013, primarily due to our 2014 results having a full year of expenses related to the Crestwood Merger and Arrow Acquisition, partially offset by approximately $40.6 million of transaction costs incurred in 2013 primarily related to the Crestwood Merger and Arrow Acquisition.

During the year ended December 31, 2015, CMLP incurred costs of $23.9 million primarily related to our 2015 cost savings initiative and the Simplification Merger. Offsetting the impact of these costs, general and administrative expenses related to CMLP's Corporate operations decreased by approximately $10.0 million for the year ended December 31, 2015 compared to 2014.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense - During the year ended December 31, 2015, our depreciation, amortization and accretion expense increased compared to 2014 and 2013 primarily due to the assets acquired during 2014 and the Crestwood Merger in June 2013. For a further discussion of our acquisitions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.

Interest and Debt Expense - Interest and debt expense, net increased for the year ended December 31, 2015 compared to 2014 and 2013, primarily due to (i) the issuance of $700 million of 6.25% senior notes in March 2015; (ii) higher outstanding balances on our credit facilities; (iii) the assumption of $1.1 billion of long-term debt due to the Crestwood Merger in June 2013; and (iv) the issuance of $600 million of 6.125% senior notes in November 2013. Partially offsetting these increases were repayments of CEQP's credit facility in conjunction with the Simplification Merger, the redemption of Crestwood Midstream's 2019 Senior Notes and repayments of Crestwood Midstream's $1.0 billion credit facility.

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



	CEQP						CMLP
	Year Ended December 31,						Year Ended December 31,
	2015		2014		2013		2015		2014		2013
Credit facilities	$	25.2	$	31.5	$	25.4	$	17.2	$	18.1	$	19.5
Senior notes	108.4		94.7		49.8		107.8		93.9		49.3
Capital lease interest	—		0.1		0.2		—		0.1		0.2
Other debt-related costs	9.0		8.5		5.9		8.0		6.8		6.1
Gross interest and debt expense	142.6		134.8		81.3		133.0		118.9		75.1
Less: capitalized interest	2.5		7.7		3.4		2.5		7.5		3.4
Interest and debt expense, net	$	140.1	$	127.1	$	77.9	$	130.5	$	111.4	$	71.7

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, credit facilities, debt issuances, and sales of common and preferred units. 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 based on our successful execution of our strategy detailed in Outlook and Trends above.

Contemporaneously with the closing of the Simplification Merger, Crestwood Midstream amended and restated its senior secured credit agreement to provide for a $1.5 billion revolving credit facility (the CMLP Credit Facility), which expires in September 2020. On September 30, 2015, Crestwood Midstream borrowed approximately $720 million under the CMLP Credit Facility to (i) repay all borrowings outstanding under its $1.0 billion credit facility, (ii) fund a distribution to CEQP of approximately $378.3 million for purposes of repaying (or, if applicable, satisfying and discharging) substantially all of its outstanding indebtedness and (iii) pay merger-related fees and expenses. As of December 31, 2015, Crestwood Midstream had $399.0 million of available capacity under its credit facility considering the most restrictive debt covenants in its credit agreement. Crestwood Midstream also has approximately $1.8 billion of senior notes outstanding as of December 31, 2015, with maturities ranging from 2020 to 2023. 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. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 8 for a more detailed discussion of the CMLP Credit Facility.

As of December 31, 2015, we were in compliance with all our debt covenants related to the CMLP credit facility and CMLP senior notes. See Part IV, Item 15. Exhibits and Financial Statement Schedules, Note 9 for a more detailed description of the CMLP Credit Facility and Senior Notes. We believe our current liquidity sources and operating cash flows will be sufficient to fund our future operating and capital requirements.

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



	Year Ended December 31,
	2015			2014			2013
Net cash provided by operating activities	$	440.7		$	283.0		$	188.3
Net cash used in investing activities	(212.7		)	(483.0		)	(1,042.9		)
Net cash provided by (used in) financing activities	(236.3		)	203.6			859.7

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Operating Activities

Our operating cash flows increased approximately $157.7 million for the year ended December 31, 2015 compared to 2014, primarily due to $169.7 million net cash inflow from working capital resulting primarily from lesser working capital requirements of our NGL terminalling, supply and logistics operations, primarily due to lower commodity prices. In addition, we experienced a $1,298.5 million decrease in operating revenues primarily from our G&P and marketing, supply and logistics segments' operations described above, partially offset by lower costs of product/services sold of approximately $1,281.1 million primarily due to the effect of lower commodity prices on our G&P and marketing, supply and logistics segments' operations described above.

For the year ended December 31, 2014 our operating cash flows increased approximately $94.7 million compared to 2013. The increase was primarily attributable to the Crestwood Merger and the acquisition of our Arrow operations which occurred in June 2013 and November 2013, respectively. These acquisitions contributed higher operating revenues of $2,504.6 million, partially offset by higher costs of product/services sold, operations and maintenance expense and general and administrative expense of approximately $2,268.4 million in 2014 compared to 2013. In addition, our interest paid increased approximately $49.5 million during the year ended December 31, 2014 compared to 2013 due to higher outstanding balances on our credit facilities.

Investing Activities

The energy midstream business is capital intensive, requiring significant investments for the acquisition or development of new facilities. We categorize our capital expenditures as either:


•	growth capital expenditures, which are made to construct additional assets, expand and upgrade existing systems, or acquire additional assets; or


•	maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets, extend their useful lives or comply with regulatory requirements.

The following table summarizes our capital expenditures for the year ended December 31, 2015 (in millions). We have identified additional growth capital project opportunities for each of our reporting segments. Additional commitments or expenditures will be made at our discretion, and any discontinuation of the construction of these projects will likely result in less future cash flow and earnings.



Growth capital	$	109.1
Maintenance capital	23.4
Other⁽¹⁾	50.2
Purchases of property, plant and equipment	182.7
Reimbursements of property, plant and equipment	(73.3		)
Net	$	109.4


(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 three years ended December 31, 2015, 2014 and 2013:

Acquisitions. During the years ended December 31, 2014 and 2013, we paid approximately $19.5 million and $555.6 million to acquire our transportation fleet from Red Rock and LT Enterprises in 2014 and our Arrow assets in 2013. For a further discussion of these acquisitions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.

Purchases of Property, Plant and Equipment. Our purchases of property, plant and equipment increased by approximately $77 million during the year ended December 31, 2014 compared to 2013, primarily due to organic growth projects placed in service related to our Marcellus assets.

Investments in Unconsolidated Affiliates. During the year ended December 31, 2013, we acquired a 50% interest in Jackalope and a 50.01% interest in PRBIC for approximately $107.5 million and $22.5 million, respectively. During the years ended December 31, 2015, 2014 and 2013, we contributed approximately $42.0 million, $108.6 million and $21.5 million to our

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equity investments. For a further discussion of our investments in unconsolidated affiliates, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6.

Proceeds from the Sale of Tres Palacios. In December 2014, Crestwood Equity sold its 100% interest in Tres Palacios to Tres Holdings, a newly formed joint venture between Crestwood Midstream's consolidated subsidiary and an affiliate of Brookfield for total cash consideration of approximately $132.8 million. As a result of this transaction, effective December 1, 2014, Crestwood Equity deconsolidated the operations of Tres Palacios. Crestwood Midstream and Brookfield paid approximately $66.4 million each to acquire their respective interests in Tres Palacios. For a further discussion of our sale in Tres Palacios, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6.

Financing Activities

Significant items impacting our financing activities during the years ended December 31, 2015, 2014 and 2013 included the following:

Equity Transactions


•	Increase in distributions to partners of approximately $69.0 million in 2015 compared to 2014 and $34.1 million in 2014 compared to 2013 due to an increase in the number of limited partner units outstanding;


•	Decrease in distributions to non-controlling partners of approximately $62.3 million in 2015 compared to 2014 primarily due to the Simplification Merger and a $92.0 million increase in distributions to non-controlling partners in 2014 compared to 2013 primarily due to the Crestwood Merger;

•

$58.8 million and $430.5 million net proceeds from the issuance of Crestwood Midstream's Class A Preferred Units in 2015 and 2014, respectively, prior to the completion of the Simplification Merger. During the year ended December 31, 2015, CEQP issued 1,372,573 preferred units to its preferred unitholders in lieu of paying a quarterly cash distribution of $12.5 million, and CEQP has the option of continuing to issue preferred units to its preferred unitholders in lieu of paying cash distributions throughout 2016;


•	$53.9 million and $96.1 million net proceeds from the issuance of preferred security units to GE in 2014 and 2013, respectively. During the year ended December 31, 2015, we paid $11.3 million of cash distributions on these units to GE, and no longer have the option to pay distributions by issuing additional preferred units to GE;


•	$129.0 million distribution to Crestwood Holdings for the acquisition of Legacy Crestwood's additional interest in Crestwood Marcellus Midstream LLC in 2013; and


•	$714.0 million net proceeds from the issuance of Crestwood Midstream's common units in 2013.

Debt Transactions


•	$688.3 million net proceeds from Crestwood Midstream's issuance of the 2023 Senior Notes in 2015;


•	$363.6 million redemption of Crestwood Midstream's 2019 Senior Notes in 2015;


•	$332.8 million increase in net repayments of amounts outstanding under our credit facilities in 2015 compared to 2014; and


•	$340.2 million decrease in net borrowings of long-term debt in 2014 compared to 2013.

Off-Balance Sheet Arrangements

None.

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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, 2015 (in millions):



	Less than 1 Year		1-3 Years		3-5 Years		Thereafter		Total
Long-term debt:
Principal	$	1.1	$	2.0	$	1,239.7	$	1,301.0	$	2,543.8
Interest⁽¹⁾	132.4		259.2		220.0		141.5		753.1
Future minimum payments under operating leases⁽²⁾	19.1		31.9		23.3		23.8		98.1
Future minimum payments under capital leases⁽²⁾	1.7		2.0		—		—		3.7
Asset retirement obligations	—		—		—		26.4		26.4
Fixed price commodity purchase commitments⁽³⁾	156.9		31.4		—		—		188.3
Standby letters of credit	62.2		—		—		—		62.2
Purchase commitments and other contractual obligations⁽⁴⁾	27.4		—		—		—		27.4
Total contractual obligations	$	400.8	$	326.5	$	1,483.0	$	1,492.7	$	3,703.0


(1)	$735.0 million of our long-term debt is variable interest rate debt at prime rate or LIBOR plus an applicable spread. These rates plus their applicable spreads were between 2.70% and 5.00% at December 31, 2015. 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, the development of a rail terminal project, certain upgrades to the US Salt facility, 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.

Critical Accounting Estimates and Policies

Our significant accounting policies are described in Note 1 to the Consolidated Financial Statements included in Part IV, Item 15. Exhibits, Financial Statement Schedules of this annual report on Form 10-K.

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

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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.

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.

Commodity prices have continued to decline since late 2014, and that decline 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 2015 and 2014. The following table summarizes the goodwill of our various reporting units (in millions):



	Goodwill at December 31, 2014		Goodwill Impairments during the Year Ended December 31, 2015		Goodwill at December 31, 2015
Gathering and Processing
Fayetteville	$	72.5	$	72.5	$	—
Marcellus	8.6		—		8.6
Arrow	45.9		—		45.9
Storage and Transportation
Northeast Storage and Transportation	726.3		—		726.3
COLT	668.3		623.4		44.9
Marketing, Supply and Logistics
West Coast	85.9		85.9		—
Supply and Logistics	266.2		99.0		167.2
Storage and Terminals	104.2		53.7		50.5
US Salt	12.6		—		12.6
Trucking	177.9		148.4		29.5
Watkins Glen	66.2		66.2		—
Total Crestwood Midstream	$	2,234.6	$	1,149.1	$	1,085.5
Barnett (Gathering and Processing)	257.2		257.2		—
Total Crestwood Equity	$	2,491.8	$	1,406.3	$	1,085.5

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 discount rates ranging from 10% to 16% to determine the fair value of our reporting units as of December 31, 2015.

We continue to monitor the remaining goodwill described in the table above, 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 businesses that recorded goodwill impairments in 2015 could have resulted in an additional $45 million and $55 million of goodwill impairments as of December 31, 2015, respectively. For more information about the market for our common equity, see Item 5. Market for Registrant's Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities.

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In addition, a 5% decrease in the forecasted cash flows or a 1% increase in the discount rate utilized to determine the fair value of our Northeast Storage and Transportation business could result in the fair value of that business falling below the carrying value of the business, which could result in a goodwill impairment.

Long-Lived Assets

Our long-lived assets consist primarily of property, plant and equipment and intangible assets that have been obtained through multiple historical business combinations. 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 2015 and 2014, we recorded the following impairments of our intangible assets and property, plant and equipment:

•

During 2015 and 2014, we incurred $8.5 million and $33.2 million of impairments of our intangible assets and 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 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 $185.5 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.

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Our other operations that incurred goodwill impairments during 2015 did not incur significant impairments on their long-lived assets based on our assessment that the undiscounted cash flows related to those assets exceeded their carrying value at December 31, 2015.

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 acquired our Jackalope and PRBIC equity-method investments in 2013, which required us to record the respective investments at fair value on the date they were acquired. 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.

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.

Revenue Recognition

We gather, treat, compress, process, store, transport and sell various commodities pursuant to fixed-fee and percent-of-proceeds contracts. We recognize revenue on these contracts when certain criteria are met, the most important of which is that the delivery of the service has been performed. Certain of our contracts in our gathering and processing segment and storage and transportation segment contain minimum volume features under which the customers must deliver a set quantity of crude or gas or pay a deficiency fee based on the amount the customers’ actual volume is short of the contractual minimum volume. The

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minimum volume feature generally allows customers a recoupment period in subsequent periods to make up certain previous volumetric shortfalls by delivering additional crude or gas above their minimum threshold. We recognize revenue from these contracts based on the physical volume that is delivered to our systems in the current period and any minimum volume deficiency amounts billable to customers under the minimum volume features are recorded as a deferred revenue liability until we determine that the revenue is earned. We will recognize the deferred revenue as income at such time as the customer does not have the physical ability to make up the deficiency due to system capacity limitations or the contractually allowed recoupment period expires. At December 31, 2015 and 2014, we had deferred revenue of approximately $14.2 million and $12.2 million, which is reflected as accrued expenses and other liabilities on our consolidated balance sheets.

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, 2015, the carrying value and fair value of our fixed rate debt instruments (including debt fair value adjustments) was approximately $1.8 billion and $1.3 billion, respectively. As of December 31, 2014, the carrying value and fair value of our fixed rate debt instruments was approximately $1.5 billion and $1.4 billion, respectively. For a further discussion of our fixed rate debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules, Note 9.

The CMLP Credit Facility is subject to the risk of loss associated with changes in interest rates. At December 31, 2015, we had obligations totaling $735.0 million outstanding under this 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 CMLP Credit Facility were to fluctuate by 1% from the rate as of December 31, 2015, our annual interest expense would have changed by a total of $7.4 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); (iii) crude oil and natural gas purchased from our Arrow, Granite Wash and Willow Lake producer customers (G&P segment); and (iv) line pack and base gas that we purchase for our natural gas storage and transportation facilities (storage and transportation 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 (e.g., 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

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assets from price risk management activities as of December 31, 2015 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.

The fair value of the derivatives contracts related to price risk management activities as of December 31, 2015 were assets of $32.6 million and liabilities of $7.4 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 $2.9 million change in the market value of these contracts as there were 73.1 million gallons of net unbalanced positions at December 31, 2015. Inventory positions of 74.8 million gallons would substantially offset this theoretical change at December 31, 2015.

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.

On March 17, 2015, Quicksilver, a significant customer in our gathering and processing operations in the Barnett Shale, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. Although Quicksilver is current on all amounts we invoiced them through January 2016, we are closely monitoring our exposure to Quicksilver to ensure they continue to promptly pay invoices, including those billed to them in February 2016.

Throughout 2015, low commodity prices created a challenging environment for our producer customers and we expect that trend to continue through 2016. As a result, the credit profile for a few of our customers has weakened in 2015 and could deteriorate further in 2016. 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 customers' credit profiles and will pursue our rights for credit assurances under our contracts as appropriate to further limit any potential credit exposure to our customers.

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, 2015, 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

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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, 2015.

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 2015 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, 2015. 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, 2015, 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 26, 2016, on the effectiveness of our internal control over financial reporting, which is included herein.

Item 9B. Other Information.

None.

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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 operation. 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	61	President, Chief Executive Officer and Director
J. Heath Deneke	42	President and Chief Operating Officer, Pipeline Services Group
William C. Gautreaux	52	President and Chief Marketing Officer, Supply and Logistics Group
Robert T. Halpin	32	Senior Vice President, Chief Financial Officer
Steven M. Dougherty	43	Senior Vice President, Chief Accounting Officer
Joel C. Lambert	47	Senior Vice President, General Counsel and Corporate Secretary
William H. Moore	36	Senior Vice President, Strategy and Corporate Development
Alvin Bledsoe	67	Director
Michael G. France	38	Director
Warren H. Gfeller	63	Director
David Lumpkins	61	Director
John J. Sherman	60	Director
John W. Somerhalder II	60	Director

Robert G. Phillips was elected Chairman, President and Chief Executive Officer of our general partner and CMLP's 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 1999-2004, 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

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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 governance committee. He is also an Advisory Director of Triten Corporation, a leading international engineering firm and alloy products manufacturer. Mr. Phillips holds a 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 and Chief Operating Officer, Pipeline Services Group in June 2015. He served as President, Natural Gas Business Unit of our general partner and CMLP's 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.

William C. Gautreaux was appointed President and Chief Marketing Officer, Supply and Logistics Group in June 2015. He served as President, Liquids and Crude Business Unit of our general partner and CMLP's general partner from October 2013 to June 2015 and as President - Inergy Services from November 2011until October 2013. He was with Legacy Inergy since its inception in 1997 and was previously employed by Ferrellgas and later co-founded and managed supply and risk management for LPG Services Group, Inc., which was acquired by Dynegy, Inc. in 1996.

Robert T. Halpin has served as the Senior Vice President - Chief Financial Officer of our general partner and CMLP’s general partner since March 2015. He previously served as 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 and CMLP's 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 Corporate Secretary of our general partner and CMLP's general partner in October 2013. 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 and CMLP's 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. Since June 2011, Mr. Bledsoe has also served as a director of SunCoke Energy, Inc. 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

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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. Since 2007, Mr. France has served as a Director of First Reserve Corporation, a private equity company which invests exclusively in the energy industry. 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. Gfeller has 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 also 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 was appointed as a member of CMLP's general partner's board of directors in October 2013, and of CEQP's general partner's board of directors in November 2015. He is currently a private investor. He was the co-founder, and previously served as the Executive Chairman,of PetroLogistics GP LLC, the general partner of PetroLogistics LP until it was sold to Flint Hills Resources LLC in July 2014. Mr. Lumpkins was previously affiliated with the private equity firm Lindsay Goldberg starting 2000, during which time he was involved in a number of investment opportunities in the petrochemical and energy midstream industries. Prior to his affiliation with Lindsay Goldberg, 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' extensive experience in the petrochemical, energy midstream and finance industries adds significant value to the boards of directors of our general partners.

John J. Sherman has served as a director of our general partner since March 2001 and as a director of CMLP GP since December 2011. 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 and is currently 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 served as a director of Legacy Crestwood from July 2007 to October 2013. Mr. Somerhalder served 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 31, 2015 and as Chairman of the Board of AGL Resources from November 2007 to December 31, 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

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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.

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, 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 Crestwood Equity GP LLC, as well as the compensation plans described below. The current members of the compensation committee are Warren Gfeller and Alvin Bledsoe. David Wood and Warren Gfeller served as members of the compensation committee during 2015 prior to Mr. Wood's resignation from the board on February 11, 2016. Our compensation committee charter may be found on our website at www.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. A 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 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,

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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.

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, 700 Louisiana Street, Suite 2550, 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, 2015, 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 Crestwood Midstream GP LLC, the general partner of Crestwood Midstream Partners LP 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. 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. As a result of this merger, Crestwood Midstream ceased as a separate publicly-traded partnership and the Compensation Committee at CMLP GP was terminated. Our general partner has entered into an Omnibus Agreement with us, Crestwood Midstream GP LLC and Crestwood Midstream Partners LP wherein our general partner is reimbursed for, among other things, salaries and related benefits and expenses of persons employed by our general partner or its affiliates who render services to Crestwood Midstream Partners LP and its affiliates.

For purposes of this Compensation Discussion and Analysis our NEOs for Fiscal 2015 were comprised of:


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


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


•	J. Heath Deneke, our President and Chief Operating Officer, Pipeline Services Group;


•	Joel C. Lambert, our Senior Vice President, General Counsel and Secretary; and


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

Michael J. Campbell is also included as a NEO because he served as our Senior Vice President and Chief Financial Officer until March 31, 2015.

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 named executive officer’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 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 the assistance from management’s consultant provides the CEO with data from the annual proxy statements 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.

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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 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 package of the executive officers. The CEO's performance and compensation is reviewed, evaluated and established separately by the Compensation Committee 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 data from the approved comparator group and published compensation data. For the CEO, in fiscal 2015 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 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

For the fiscal year 2015, Aon Hewitt (the Compensation Consultant) was engaged on behalf of management as our compensation consultant. Our Compensation Committee and management believed it was beneficial to have an independent third-party analysis to assist in evaluating and setting executive compensation. Management, in consultation with the Compensation Committee, chose the Compensation Consultant because of the Compensation Consultant's extensive experience in providing executive compensation advice, including specific experience in the oil and gas industry. The Compensation Consultant 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 the Compensation Consultant in order to make compensation decisions.

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, the Compensation Consultant with the assistance of management proposed certain peer group companies for our Compensation Committee's review.

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After discussion with the Compensation Consultant and reviewing the Compensation Consultant's recommendation of a peer group based on companies with annual revenues, assets and net income similar to ours taking into account geographic footprint and employee count, our Compensation Committee agreed that the peer group listed below is the most appropriate for purposes of executive compensation analyses. This peer group is unchanged from last year's except for two peers that we removed due to mergers in 2015. The Compensation Consultant 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 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.

In 2015, the Compensation Consultant collected and presented to the Compensation Committee peer group data for the following 11 midstream master limited partnerships (MLPs):



Boardwalk Pipeline Partners LP	MarkWest Energy Partners L.P.
DCP Midstream Partners, LP	Regency Energy Partners LP
Enable Midstream Partners, LP	Summit Midstream Partners, LP
EnLink Midstream Partners, LP	Tallgrass Energy Partners, LP
EQT Midstream Partners, LP	Targa Resources Partners LP
	Western Gas Partners, LP

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 may be eligible to receive incentive units from Crestwood Holdings, 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 future potential). The initial base salaries for our NEOs was determined in 2013 in connection with the Crestwood Merger 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 targeted objective between the 50th and 75th percentiles of the market data, the following base salary changes were made in 2015:


•	Increased Mr. Deneke's base salary from $435,000 to $475,000 as a result of his promotion to Chief Operating Officer and President of the Pipeline Services Group;


•	Increased Mr. Halpin's base salary from $375,000 to $400,000 as a result of his promotion to Senior Vice President and Chief Financial Officer; and


•	Increased Mr. Lambert's base salary from $360,000 to $375,000 due to his additional duties overseeing Human Resources and Government Relations.

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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 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. Based on our targeted objective between the 50th and 75th percentiles of the market data, the Compensation Committee approved an increase in Mr. Halpin's target bonus amount from 80% of base salary to 90% of base salary as a result of his promotion to Senior Vice President and Chief Financial Officer. No other changes were made to the NEOs' target bonus amounts in 2015.

Actual bonuses for 2015 were determined based on our achievement of Compensation Committee approved key performance indicators (KPIs) and a board discretionary component. The KPIs for fiscal 2015 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 or decrease the total recommended bonus pool by 20-25% based on qualitative factors deemed relevant by the board.

Long-Term Incentive Plan Awards

Prior to the Simplification Merger, long-term incentive awards for the NEOs were granted under both the Crestwood Equity Partners LP Long Term Incentive Plan and the Crestwood Midstream 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. These plans were designed to align the economic interests of key employees and directors with those of our common unitholders and the common unitholders of us and Crestwood Midstream Partners LP and to provide an incentive to management for continuous employment with the general partner and its affiliates. Long-term incentive compensation was based upon the common units representing limited partnership interests in us and in Crestwood Midstream Partners LP. For fiscal 2015, our awards consisted of grants of restricted common units and phantom units which vest based upon continued service. Restricted units and phantom units are designed to attract and retain executive talent and to align their economic interests with those of common unitholders.

As a result of the completion of the Simplification Merger on September 30, 2015, each outstanding phantom and restricted unit of Crestwood Midstream Partners LP was converted into 2.75 Crestwood Equity Partners LP phantom or restricted units, respectively. Crestwood Midstream Partners LP ceased to exist as a separate publicly-traded entity. Accordingly, no further grants will be made under the Crestwood Midstream Partners LP Long Term Incentive Plan.

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.

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Based on our targeted objective between the 50th and 75th percentiles of the market data, the following target equity changes were made in 2015 and will be reflected in 2016 equity grants:


•	Increased Mr. Phillips' annual equity grant target from 250% of base salary to 300% of base salary;


•	Increased Mr. Halpin's annual equity grant target from 140% of base salary to 250% of base salary;


•	Increased Mr. Deneke's annual equity grant target from 175% of base salary to 250% of base salary; and


•	Increased Mr. Dougherty's annual equity grant target from 140% of base salary to 175% of base salary.

In January 2015, the Compensation Committee directed the Compensation Consultant to review the cumulative outstanding unvested equity amounts for certain pre-merger Crestwood executives to assess retention risks of these executives. It was determined that the level of unvested long-term compensation for such officers was below or targeted midpoint between the 50th and 75th percentiles of the market data. Accordingly, for retention purposes, the Compensation Committee approved the grant of phantom units as follows:



Employee	CEQP Units⁽¹⁾	CMLP Units⁽²⁾
Robert G. Phillips	96,102	42,309
Robert T. Halpin	39,286	17,296
J. Heath Deneke	52,858	23,271
Joel C. Lambert	46,249	20,440
Steven M. Dougherty	46,249	20,440

⁽¹⁾Represents number of CEQP phantom units prior to the 1-for-10 reverse unit split effective as of November 23, 2015.

(2) On September 30, 2015, each CMLP phantom unit was converted into 2.75 CEQP units.

The phantom unit awards vest in full three years from the grant date. Distributions on the phantom units are paid in additional phantom units in equal value to the cash distribution amount.

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 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

Effective as of March 31, 2015, Michael J. Campbell resigned as our Senior Vice President, Chief Financial Officer. In connection with his resignation, Mr. Campbell entered into a Separation Agreement and Release (the Separation Agreement). Under the Separation Agreement, Mr. Campbell will receive; (i) up to $1,600,000 of severance payments to be paid in installments over 18 months after his separation date, (ii) reimbursement for the employer contribution portion of elected COBRA coverage for a period of up to 18 months and (iii) accelerated vesting of unvested restricted units granted to Mr. Campbell prior to March 31, 2015. In addition, the Separation Agreement set Mr. Campbell's 2014 annual bonus payout at $300,000 (75% of target) and provided for a 2015 equity award grant to Mr. Campbell in an amount equal to 150% of his base salary.

For a detailed description of the Executive Employment Agreements for our other NEOs, see "Potential Payments upon a Change in Control or Termination during Fiscal 2015."

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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 the same 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.

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, 2015.

David Wood⁽¹⁾

Warren Gfeller

Members of the Compensation Committee


⁽¹⁾	David Wood resigned from the board of directors effective as of February 11, 2016.

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Summary Compensation Table for Fiscal 2015

The following table sets forth the cash and non-cash compensation earned by our NEOs for the fiscal years ended December 31, 2015 and 2014, the Transition Period (October 1, 2013 - December 31, 2013), and September 30, 2013.



Name and Principal Position	Fiscal Year	Salary ($)	Bonus ($)	Unit Awards ($)⁽³⁾	Non-Equity Incentive Plan Compensation ($)	All Other Compensation ($)⁽⁴⁾	Total ($)

Robert G. Phillips President, Chief Executive Officer and Director	2015	655,000	655,000	2,935,211	—	10,093	4,255,304
	2014	655,000	655,000	4,718,155	—	16,788	6,044,943
	Transition⁽¹⁾	176,347	307,450	—	—	—	483,797
	2013	176,347	347,550⁽⁵⁾	—	—	—	523,897
Robert T. Halpin Senior Vice President, Chief Financial Officer	2015	400,000	360,000	1,057,804	—	16,044	1,833,848
J. Heath Deneke President and Chief Operating Officer, Pipeline Services Group	2015	475,000	427,500	1,477,254	—	16,080	2,395,834
	2014	435,000	430,650	752,265	—	15,780	1,633,695
	Transition⁽¹⁾	116,442	391,500	—	—	1,339	509,281
Joel C. Lambert Senior Vice President, General Counsel	2015	375,000	330,000	1,170,957	—	16,158	1,892,115
Steven M. Dougherty Senior Vice President, Chief Accounting Officer	2015	375,000	330,000	1,156,195	—	16,080	1,877,275
Michael J. Campbell⁽²⁾ Former Senior Vice President, Chief Financial Officer	2015	110,769	—	590,225	—	863,419	1,564,413
	2014	400,000	300,000	1,778,745	—	13,282	2,492,027
	Transition⁽¹⁾	96,154	—	—	—	1,119	97,273
	2013	247,115	400,000	789,300	—	6,548	1,442,963


(1)	The transition period covers the time period from October 1, 2013 to December 31, 2013 due to a change in our fiscal year end from September 30 to December 31.


(2)	Michael J. Campbell resigned effective March 31, 2015. The material terms of Mr. Campbell’s Separation Agreement and Release are described in “Compensation Discussion and Analysis - Severance and Change of Control Benefits.”

(3)

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 718, disregarding 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.

(4) “All Other Compensation” for Fiscal Year 2015 consisted of the following:



Name	401(k) Matching Contributions ($)	Group Term Life Insurance ($)	Other ($)	Total ($)
Robert G. Phillips	3,023	1,188	5,882*	10,093
Robert T. Halpin	15,900	144	—	16,044
J. Heath Deneke	15,900	180	—	16,080
Joel C. Lambert	15,888	270	—	16,158
Steven M. Dougherty	15,900	180	—	16,080
Michael J. Campbell	15,900	31	847,488**	863,419


*	Reflects the cost Mr. Phillips' use of the company plane for personal reasons.


**	Payments to Mr. Campbell pursuant to the terms of his Separation Agreement.

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Grants of Plan-Based Awards Table for Fiscal 2015

The following table provides information concerning each grant of an award made to our NEOs during Fiscal 2015.



		Estimated Future Payouts Under Non-Equity Incentive Plan Awards
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)⁽³⁾	All Other Unit Awards(#)⁽¹⁾⁽²⁾	Grant Date Fair Value of Unit and Option Awards ($)
Robert G. Phillips	1/16/2015	—	655,000	655,000	CEQP RSU - 116,964	784,828
	1/16/2015	—	—	—	CEQP Phantom - 96,102	644,844
	1/16/2015	—	—	—	CMLP RSU - 51,494	826,479
	1/16/2015	—	—	—	CMLP Phantom - 42,309	679,059
Robert T. Halpin	1/16/2015	—	360,000	360,000	CEQP RSU - 37,500	251,625
	1/16/2015	—			CEQP Phantom - 39,286	263,609
	1/16/2015	—			CMLP RSU - 16,509	264,969
	1/16/2015	—	—	—	CMLP Phantom - 17,296	277,601
J. Heath Deneke	1/16/2015	—	427,500	427,500	CEQP RSU - 54,375	364,856
	1/16/2015	—	—	—	CEQP Phantom - 52,858	354,677
	1/16/2015	—	—	—	CMLP RSU - 23,939	384,221
	1/16/2015	—	—	—	CMLP Phantom - 23,271	373,500
Joel C. Lambert	1/16/2015	—	270,000	270,000	CEQP RSU - 38,571	258,811
	1/16/2015	—	—	—	CEQP Phantom - 46,429	311,539
	1/16/2015	—	—	—	CMLP RSU - 16.981	272,545
	1/16/2015	—	—	—	CMLP Phantom - 20,440	328,062
Steven M. Dougherty	1/16/2015	—	300,000	300,000	CEQP RSU - 38,571	258,811
	1/16/2015	—	—	—	CEQP Phantom - 46,429	311,539
	1/16/2015	—	—	—	CMLP RSU - 16,981	272,545
	1/16/2015	—	—	—	CMLP Phantom - 20,440	328,062


(1)	The restricted units vest ratably (33.33%) over a three year period beginning on the first anniversary of the grant date. The phantom units vest in full three years from the grant date.


(2)	On September 30, 2015, each outstanding CMLP phantom and restricted unit was converted into 2.75 CEQP phantom and restricted units, respectively. The CEQP units do not reflect the 1-for-10 reverse split effective as of November 23, 2015.


(3)	The "Maximum" amount may be increased by the discretion of the Compensation Committee as described above in the "Compensation Discussion and Analysis - Incentive Awards.":

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.” On January 20, 2015, Crestwood Operations entered into an Amended and Restated Employment Agreement with Robert Halpin to reflect his new compensation package as a result of his promotion to Senior Vice President, Chief Financial Officer. Likewise, on August 28, 2015, Crestwood Operations entered into an Amended and Restated Employment Agreement with Heath Deneke to reflect his new compensation package as a result of his promotion to Chief Operating Officer and President, Pipeline Services Group.

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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.

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

Outstanding Equity Awards at 2015 Fiscal Year-End

The following table summarizes the outstanding equity awards as of the end of Fiscal 2015 for the each of our NEOs. The table includes restricted units and phantom units granted under the Crestwood Equity Partners LP Long Term Incentive Plan.



	OPTION AWARDS				UNIT AWARDS
Name	Number of Securities Underlying Unexercised Options (#) Exercisable	Number of Securities Underlying Unexercised Options (#) Unexercisable	Option Exercise Price($)	Option Expiration Date	Number of Units That Have Not Vested (#)⁽²⁾	Market Value of Units That Have Not Vested ($)⁽¹⁾
Robert G. Phillips	—	—	—	—	77,292	1,066,133
Robert T. Halpin	—	—	—	—	22,825	474,303
J. Heath Deneke	—	—	—	—	28,700	596,382
Joel C. Lambert	—	—	—	—	23,429	483,124
Steven M. Dougherty	—	—	—	—	24,219	503,280
Michael J. Campbell	—	—	—	—	0	0


(1)	Market value for CEQP units based on the NYSE closing price of $20.78 on December 31, 2015.

(2)

Mr. Phillips' restricted units vest as follows: 8,619 on January 16, 2016, 5,220 on January 17, 2016, 10,017 on February 26, 2016, 8,619 on January 16, 2017, 1,740 on January 17, 2017, 10,017 on February 26, 2017 and 8,618 on January 16, 2018. Mr. Halpin's restricted units vest as follows: 2,763 on January 16, 2016, 1,148 on January 17, 2016, 1,095 on August 15, 2016, 824 on October 8, 2016, 2,763 on January 16, 2017, 382 on January 17, 2017, 1,095 on August 15, 2017 and 2,763 on January 16, 2018. Mr. Deneke's restricted units vest as follows: 4,008 on January 16, 2016, 2,428 on January 17, 2016, 4,006 on January 16, 2017, 808 on January 17, 2017 and 4,006 on January 16, 2018. Mr. Lambert's restricted units vest as follows: 2,843 on January 16, 2016, 1,721 on January 17, 2016, 621 on October 1, 2016, 2,842 on January 16, 2017, 573 on January 17, 2017 and 2,841 on January 16, 2018. Mr. Dougherty's restricted units vest as follows: 2,763 on January 16, 2016, 1,450 on January 17, 2016, 1,095 on August 15, 2016, 2,763 on January 16, 2017, 482 on January 17, 2017, 1,095 on August 15, 2017 and 2,763 on January 16, 2018. All of the phantom units for Messrs. Phillips, Halpin, Deneke, Lambert and Dougherty will vest on January 16, 2018.

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Units Vested During Fiscal 2015

The following table provides information regarding restricted unit vesting during Fiscal 2015 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 (#)⁽¹⁾	Value Realized on Vesting ($)
Robert G. Phillips	CEQP - 7,139 CMLP - 42,097	475,606 642,207
Robert T. Halpin	CEQP - 1,877 CMLP - 7,104	84,372 94,378
J. Heath Deneke	CEQP - 1,552 CMLP - 9,063	104,139 145,461
Joel C. Lambert	CEQP - 1,722 CMLP - 6,429	88,036 103,185
Steven M. Dougherty	CEQP - 1,247 CMLP - 8,235	73,082 112,530
Michael J. Campbell	CEQP - 10,892 CMLP - 57,434	667,300 871,412


(1)	CEQP units are adjusted for the 1-for-10 reverse split completed on November 23, 2015. On September 30, 2015, each outstanding CMLP phantom and restricted unit was converted into 2.75 CEQP phantom and restricted units, respectively.

Pension Benefits during Fiscal 2015

We do not offer any pension benefits.

Non-qualified Deferred Compensation during Fiscal 2015

We have no non-qualified deferred compensation plans.

Potential Payments upon a Change in Control or Termination during Fiscal 2015

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, 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.

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, 2015.



Name	Cash Severance ($)⁽¹⁾	Accelerated Vesting of Restricted Units ($)⁽²⁾	Benefit Continuation ($)⁽³⁾	Total ($)
Robert G. Phillips	3,930,000	1,606,133	26,641	5,562,774
Robert T. Halpin	1,490,000	474,303	30,838	1,995,141
J. Heath Deneke	1,808,150	596,382	31,161	2,435,693
Joel C. Lambert	1,323,000	483,123	25,130	1,831,253
Steven M. Dougherty	1,410,000	503,280	31,161	1,944,441


(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

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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.

(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 $20.78 for CEQP units on December 31, 2015.


(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.

Crestwood Equity Director Compensation Table for Fiscal 2015

The following table sets forth the cash and non-cash compensation for Fiscal 2015 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⁾	Total ($)
Alvin Bledsoe	85,000	77,033	162,033
Michael France	15,000	77,033	92,033
Warren Gfeller	85,000	77,033	162,033
Arthur Krause⁽²⁾	83,333	77,033	160,366
David Lumpkins⁽²⁾	25,000		25,000
Randy Moeder⁽²⁾	83,333	77,033	160,366
John Sherman	65,000	77,033	142,033
John Somerhalder II	85,000	77,033	162,033
David Wood⁽³⁾	75,000	77,033	152,033

(1)

Reflects the value of restricted unit awards, calculated in accordance with ASC 718, disregarding estimated forfeitures. See Part IV, Item 15. Exhibits and 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, 2015, our non-employee directors held the following restricted unit awards: Mr. Bledsoe, Mr. France, Mr. Sherman, Mr. Somerhalder II and Mr. Wood each held 2,436 restricted units; Mr. Krause and Mr. Gfeller each held 2,516 restricted units.


(2)	Mr. Krause and Mr. Moeder resigned from the board of directors on November 2, 2015 and Mr. Lumpkins was appointed to the board of directors on November 2, 2015.


(3)	Mr. Wood resigned from the board of directors effective as of February 11, 2016.

Crestwood Equity Compensation of Directors during Fiscal 2015

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; provided, however, that if a non-employee director served on both our board of directors and the board of directors of CMLP prior to the Simplification Merger, the director received annual cash compensation of $60,000 for each board. 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 $80,000 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.

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. David Wood and Warren Gfeller served as the members of the compensation committee during Fiscal 2015, and neither of them was an officer or employee of our company or any of its subsidiaries during Fiscal 2015.

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

The following table sets forth certain information as of February 19, 2016, 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⁾	—	—	34,778,633	55.9%
GSO COF II Holdings Partners LP⁽⁴⁾	—	—	24,849,028	40.0%
FR Crestwood Management Co-Investment LLC⁽⁵⁾	4,984,382	7.2%	—	—
Crestwood Gas Services Holdings LLC^(5)(6)(7)	9,985,462	14.4%	—	—
Crestwood Holdings LLC⁽⁵⁾⁽⁶⁾	686,695	1.0%	—	—
Kayne Anderson Capital Advisors, L.P.⁽⁸⁾	3,665,780	5.4%	—	—
Neuberger Berman Group LLC⁽⁹⁾	4,632,000	6.8%	—	—
Oppenheimer Funds, Inc.⁽¹⁰⁾	3,762,578	5.5%	—	—
Alvin Bledsoe	26,611	*	—	—
J. Heath Deneke	86,842	*	—	—
Steven M. Dougherty	55,284	*	—	—
Michael G. France	10,125	*	—	—
William C. Gautreaux	654,304	*	—	—
Warren H. Gfeller	37,826	*	—	—
Robert T. Halpin	77,162	*	—	—
Joel C. Lambert	51,813	*	—	—
David Lumpkins	27,433	*	—	—
William H. Moore	54,664	*	—	—
Robert G. Phillips	174,481	*	—	—
John J. Sherman	3,217,325	4.7%	—	—
John W. Somerhalder II	5,546	*	—	—
Directors and executive officers as a group (13 persons)	4,479,416	6.5%	—	—

* Indicates less than 1%

(1) Unless otherwise indicated, the contact address for all beneficial owners in this table is 700 Louisiana Street, Suite 2550, 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. (15,530,684), MTP Energy CM LLC (7,830,298), MTP Energy Opportunities Fund LLC (3,727,349), Magnetar Structured Credit Fund, LP (1,541,650), Magnetar Constellation Fund IV LLC (1,287,178), Compass HTV LLC (1,233,617), Magnetar Capital Fund II LP (1,055,177), Blackwell Partners LLC (770,008), Magnetar Global Event Drive Fund LLC (767,137), Magnetar Andromeda Select Fund LLC (621,204), Hipparchus Fund LP (249,910) and Spectrum Opportunities Fund LP (174,457). 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 10,672,157 common units. Crestwood Holdings LLC, Crestwood Gas Services 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 over 15,876,654.


(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 subordinate units. The subordinated units may be converted to common units on a one-for-one basis upon the termination of the subordinate period as set forth in the Crestwood Equity Partners LP Partnership Agreement.

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(8)

According to a Schedule 13G filed by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne with the SEC on January 9, 2016, Kayne Anderson Capital Advisors, L.P. together with Richard A. Kayne have shared voting and dispositive power over 3,665,780 common units. The reported units are owned by investment accounts (investment limited partnerships, a registered investment company and institutional accounts) managed, with discretion to purchase or sell securities, by Kayne Anderson Capital Advisors, L.P., as a registered investment adviser. Kayne Anderson Capital Advisors, L.P., is the general partner (or general partner of the general partner) of the limited partnerships and investment adviser to the other accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of each of the limited partnerships and a shareholder of the registered investment company. Kayne Anderson Capital Advisors, L.P. disclaims beneficial ownership of the units reported, except those units attributable to it by virtue of its general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the units reported, except those units held by him or attributable to him by virtue of his limited partnership interests in the limited partnerships, his indirect interest in the interest of Kayne Anderson Capital Advisors, L.P. in the limited partnerships, and his ownership of common stock of the registered investment company. The address of Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne is 1800 Avenue of the Stars, Third Floor, Los Angeles, CA 90067.


(9)	According to a Schedule 13G/A filed by Neuberger Berman Group LLC, with the SEC on February 9, 2016, Neuberger Berman Group LLC has shared voting power over 4,510,683 common units and shared dispositive power over 4,632,000 common units. The address of Neuberger Berman Group LLC is 605 Third Avenue, New York, NY 10158. Neuberger Berman Group LLC disclaims beneficial ownership of these units.

(10)According to a Schedule 13G/A filed by Oppenheimer Funds, Inc., with the SEC on February 5, 2016, Oppenheimer Funds, Inc. has shared voting and dispositive power over 3,762,578 common units. The address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281. Oppenheimer Funds, Inc. disclaims beneficial ownership of these units.

See Item 5 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

Crestwood Midstream Agreements

In December 2001, we entered into an omnibus agreement and tax sharing agreement with our general partner, CMLP and its general partner that governs certain aspects of our relationship with them, including:


•	the provision by us to CMLP of certain administrative services and CMLP’s agreement to reimburse us for such services;


•	the provision by us of such employees as may be necessary to operate and manage CMLP’s business, and CMLP’s agreement to reimburse us for the expenses associated with such employees;


•	certain indemnification obligations; and


•	CMLP's reimbursement to us for its share of state and local income and other taxes borne by us as a result of CMLP's income being included in a combined or consolidated tax return filed by us.

In conjunction with the completion of the Simplification Merger on September 30, 2015, the omnibus agreement and tax sharing agreements were effectively terminated. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 16 to the financial statements for additional information on related party transactions.

Registration Rights Agreement

In connection with the Crestwood Merger, we entered into a registration rights agreement with John J. Sherman, our former president and chief executive officer who currently serves on our board of directors.

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.

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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;


•	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 (e.g., 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 (the Board) of Directors of Crestwood Equity GP LLC approved the engagement of Ernst & Young LLP (E&Y) as the principal accountant to audit the partnership’s financial statements as of and for the fiscal year ending December 31, 2015. The audit fees for each of the years ended December 31, 2015 and 2014 were $2.7 million, which were primarily for professional audit services rendered by Ernst & Young LLP for the audits of the consolidated financial statements of Crestwood Equity and Crestwood Midstream and for other services.

The audit committee of Crestwood Equity's general partner reviewed and approved all audit and non-audit services provided during 2015. Immediately following the Simplification Merger, Crestwood Midstream became a wholly-owned subsidiary of Crestwood Equity and, as such, 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		Contribution Agreement dated April 25, 2012 by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Services, Inc. and Suburban Propane Partners, L.P. (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.'s Form 8-K filed April 26, 2012)

2.2		Amendment to Contribution Agreement dated June 15, 2012 by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Services, Inc. and Suburban Propane Partners, L.P. (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed June 15, 2012)

2.3		Second Amendment to Contribution Agreement dated July 6, 2012 by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Services, Inc. and Suburban Propane Partners, L.P. (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.'s Form 8-K filed July 6, 2012)

2.4		Third Amendment to Contribution Agreement dated July 19, 2012 by and among Inergy, L.P., Inergy GP, LLC, Inergy Sales & Services, Inc. and Suburban Propane Partners, L.P. (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.'s Form 8-K filed July 19, 2012)

2.5		Contribution Agreement dated May 5, 2013, by and among Crestwood Holdings LLC, Crestwood Gas Services Holdings LLC, Inergy GP, LLC and Inergy, L.P. (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed on May 9, 2013)

2.6		Follow-On Contribution Agreement dated as of May 5, 2013, by and among Crestwood Holdings LLC, Crestwood Gas Services Holdings LLC, Inergy GP, LLC and Inergy, L.P. (incorporated herein by reference to Exhibit 2.2 to Inergy, L.P.’s Form 8-K filed on May 9, 2013)

2.7		Agreement and Plan of Merger, dated as of October 8, 2013 by and among Crestwood Midstream Partners LP, Crestwood Arrow Acquisition LLC, Arrow Midstream Holdings, LLC, the Members, and OZ Midstream Holdings, LLC (incorporated herein by reference to Exhibit 10.2 to Crestwood Midstream Partner LP's Form 10-Q filed on November 8, 2013)

2.8		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)

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)

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Exhibit Number		Description
3.4		Fifth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners 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 September 30, 2015)

3.6		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)

3.7		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)

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

3.9		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)

4.1		Certificate of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.4 to Inergy Midstream, L.P.'s Form S-1/A filed on November 21, 2011)

4.2		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)

4.3		First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P., dated December 21, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)

4.4		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)

4.5		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)

4.6		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)

4.7		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 September 30, 2015)

4.8		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)

4.9		Certificate of Amendment of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.7 to Crestwood Midstream Partners LP's Form S-4 filed on October 28, 2013)

4.10		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)

4.11		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 filed on October 28, 2013)

4.12		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)

Table of Contents



Exhibit Number		Description
4.13		Indenture, dated December 7, 2012, by and among Inergy Midstream, L.P., NRGM Finance Corp., the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to Inergy Midstream, L.P.'s Form 8-K filed on December 13, 2012

4.14		First Supplemental Indenture, dated January 18, 2013, by and among Inergy Midstream, L.P., NRGM Finance Corp., the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.4 to Inergy Midstream, L.P.'s Form 10-Q filed on February 6, 2013)

4.15		Second Supplemental Indenture, dated May 22, 2013, by and among Inergy Midstream, L.P., NRGM Finance Corp., the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to Inergy Midstream, L.P.'s Form 8-K filed on May 29, 2013)

4.16		Third Supplemental Indenture, dated October 7, 2013, by and among Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.), Crestwood Midstream Finance Corp. (f/k/a NRGM Finance Corp.), the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.2 to Crestwood Midstream Partners LP’s Form 8-K filed on October 10, 2013)

4.17		Fourth Supplemental Indenture, dated November 8, 2013, 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 4.2 to Crestwood Midstream Partners LP’s Form 8-K filed on November 12, 2013)

4.18		Indenture, dated November 8, 2013, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the Guarantors named therein and U.S. National Bank Association (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP's Form 8-K filed on November 12, 2013)

4.19		Indenture, dated April 1, 2011, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 8-K filed on April 5, 2011)

4.20		Supplemental Indenture No. 1, dated November 29, 2011 to Indenture dated April 1, 2011, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.3 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2011, filed on March 1, 2012)

4.21		Supplemental Indenture No. 2, dated January 6, 2012 to Indenture dated April 1, 2011, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.4 to the Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2011, filed on March 1, 2012)

4.22		Supplemental Indenture No. 3, dated March 22, 2012, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 10-Q for the quarter ended March 31, 2012, filed on May 9, 2012)

4.23		Supplemental Indenture No. 4, dated April 11, 2013, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.5 to Crestwood Midstream Partners LP’s Form S-4/A filed on April 30, 2013)

4.24		Supplemental Indenture No. 5, dated October 7, 2013, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.), Crestwood Midstream Finance Corp. (f/k/a NRGM Finance Corp.), the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A, (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP's Form 8-K filed on October 10, 2013)

4.25		Supplemental Indenture No. 6, dated November 8, 2013, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A. (incorporated herein by reference to Exhibit 4.3 to Crestwood Midstream Partners LP’s Form 8-K filed on November 12, 2013)

4.26		Registration Rights Agreement, dated June 19, 2013, by and among Inergy Midstream, L.P., John J. Sherman, Crestwood Holdings LLC and Crestwood Gas Services Holdings LLC (incorporated herein by reference to Exhibit 4.1 to Inergy Midstream, L.P.’s Form 8-K filed on June 19, 2013)

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Exhibit Number		Description
4.27		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 6, 2015)

4.28		Registration Rights Agreement, dated as of March 23, 2015, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and Merrill Lynch, Pierce, Fenner & Smith Incorporated, as representative of the several initial purchasers, with respect to the 6.25% Senior Notes due 2023 (incorporated herein by reference to Exhibit 4.3 to Crestwood Midstream Partners LP's Form 8-K filed on March 6, 2015)

4.29		Registration Rights Agreement, dated as of June 17, 2014, by and among Crestwood Midstream Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 4.1 to the Crestwood Midstream Partners LP’s Form 8-K filed on June 19, 2014)

4.30		Registration Rights Agreement dated June 19, 2013, by and among Inergy, L.P., John J. Sherman, Crestwood Holdings LLC and Crestwood Gas Services Holdings LLC (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on June 19, 2013)

*10.1		Employment Agreement between Robert Phillips and Crestwood Operations LLC dated as of January 21, 2014 (incorporated by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on January 27, 2014)

*10.2		Employment Agreement between Joel Lambert and Crestwood Operations LLC dated as of January 21, 2014 (incorporated by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s Form 10-K filed on February 28, 2014)

*10.3		Amended and Restated Employment Agreement between J. Heath Deneke and Crestwood Operations LLC (incorporated herein by reference to Exhibit 10.4 to Crestwood Equity Partners LP’s Form 8-K filed on September 1, 2015)

**10.4		Employment Agreement between Steven M. Dougherty and Crestwood Operations LLC dated as of January 21, 2014

**10.5		Amended and Restated Employee Agreement between Robert T. Halpin and Crestwood Operations LLC dated as of April 1, 2015

*10.6		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)

*10.7		Form of Crestwood Equity Partners LP’s Restricted Unit Award Agreement (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partner LP's Form S-8 filed on January 13, 2015)

*10.8		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)

*10.9		Amended and Restated Inergy Unit Purchase Plan (incorporated herein by reference to Exhibit 10.1 to Inergy L.P.’s Form 10-Q filed on February 13, 2004)

*10.10		Summary of Non-Employee Director Compensation (incorporated herein by reference to Crestwood Equity Partners LP’s Form 10-K filed on February 28, 2014)

*10.11		Inergy Midstream, L.P. Long-Term Incentive Plan, adopted as of December 21, 2011 (incorporated herein by reference to Exhibit 4.3 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)

*10.12		Inergy Midstream, L.P. Long-Term Incentive Plan, adopted as of December 21, 2011 (incorporated herein by reference to Exhibit 4.3 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)

10.13		Amended and Restated Credit Agreement dated as of February 2, 2011 among Inergy, L.P., lenders named therein and JPMorgan Chase Bank, N.A. as administrative agent (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on February 3, 2011)

10.14		Amendment No. 1 to Amended and Restated Credit Agreement, dated as of July 28, 2011 among Inergy, L.P., lenders named therein and JPMorgan Chase Bank, N.A. as administrative agent (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on August 1, 2011)

10.15		Consent and Amendment No. 2 dated as of December 21, 2011 among Inergy, L.P., lenders named therein and JPMorgan Chase Bank, N.A. as administrative agent (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on December 22, 2011)

100

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Exhibit Number		Description
10.16		Consent and Amendment No. 3 dated as of April 13, 2012 among Inergy, L.P., lenders named therein and JPMorgan Chase Bank, N.A. as administrative agent (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on April 19, 2012)

10.17		Consent and Amendment No. 4 dated as of July 26, 2012, to the Amended and Restated Credit Agreement, dated November 24, 2009, as amended and restated as of February 2, 2011, among Inergy, L.P., lenders named therein and JPMorgan Chase Bank, N.A. as administrative agent (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on July 27, 2012)

10.18		Consent, Waiver and Amendment No. 5, dated May 23, 2013, to the Amended and Restated Credit Agreement, dated as of November 24, 2009, as amended and restated as of February 2, 2011, by and among Inergy, L.P., JPMorgan Chase Bank, N.A., as administrative agent, and the financial institutions party thereto (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on May 30, 2013)

10.19		Amendment No. 6, dated August 28, 2013, to the Amended and Restated Credit Agreement, dated as of November 24, 2009, as amended and restated as of February 2, 2011, by and among Inergy, L.P., JPMorgan Chase Bank, N.A., as administrative agent, and the financial institutions party thereto (incorporated herein by reference to Exhibit 10.1 to Inergy, L.P.’s Form 8-K filed on August, 30, 2013)

10.20		Amendment No. 7, dated December 20, 2013, to the Amended and Restated Credit Agreement, dated as of November 24, 2009, as amended and restated as of February 2, 2011, by and among Crestwood Equity Partners LP, JPMorgan Chase Bank, N.A., as administrative agent, and the financial institutions party thereto (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP's Form 8-K filed on December 24, 2013)

10.21		Amendment No. 8, dated September 10, 2014, to the Amended and Restated Credit Agreement, dated as of November 24, 2009, as amended and restated as of February 2, 2011, and as further amended from time to time prior to the date hereof, by and among Crestwood Equity Partners LP, JPMorgan Chase Bank, N.A., as administrative agent, and the financial institutions party thereto (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP's Form 8-K filed on September 12, 2014)

10.22		Contribution, Conveyance and Assumption Agreement dated December 21, 2011, by and among Inergy GP, LLC, Inergy, L.P., Inergy Propane, LLC, MGP GP, LLC, Inergy Midstream Holdings, L.P., NRGM GP, LLC, and Inergy Midstream, L.P. (incorporated by reference to Exhibit 10.2 to Inergy L.P.’s Form 8-K filed on December 22, 2011)

10.23		Omnibus Agreement, dated December 21, 2011 by and among Inergy GP, LLC, Inergy, L.P., NRGM GP, LLC and Inergy Midstream, L.P. (incorporated by reference to Exhibit 10.3 to Inergy L.P.’s Form 8-K filed on December 22, 2011)

10.24		Tax Sharing Agreement, dated December 21, 2011, by and among Inergy, L.P. and Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 10.6 to Inergy Midstream, L.P.'s Form 8-K filed on December 22, 2011)

10.25		Membership Interest Purchase Agreement dated December 21, 2011, by and among Inergy , L.P. and Inergy Holdings GP, LLC (incorporated by reference to Exhibit 10.4 to Inergy L.P.’s Form 8-K filed on December 22, 2011)

10.26		Agreement and Plan of Merger dated May 5, 2013, by and among Inergy Midstream, L.P., NRGM GP, LLC, Intrepid Merger Sub, LLC, Inergy, L.P., Crestwood Holdings LLC, Crestwood Midstream Partners LP and Crestwood Gas Services GP LLC (incorporated herein by reference to Exhibit 10.1 to Inergy L.P.’s Form 8-K filed on May 9, 2013)

10.27		Voting Agreement, dated May 5, 2013, by and among Inergy Midstream, L.P., NRGM GP, LLC, Intrepid Merger Sub, LLC, Crestwood Gas Services GP LLC, Crestwood Gas Services Holdings LLC, Crestwood Holdings LLC and Crestwood Midstream Partners LP (incorporated herein by reference to Exhibit 10.2 to Inergy, L.P.’s Form 8-K filed on May 9, 2013)

10.28		Option Agreement, dated May 5, 2013, by and among Inergy, L.P., Inergy Midstream, L.P., NRGM GP, LLC, Intrepid Merger Sub, LLC, Crestwood Gas Services GP LLC, Crestwood Gas Services Holdings LLC and Crestwood Holdings LLC (incorporated herein by reference to Exhibit 10.3 to Inergy, L.P.’s Form 8-K filed on May 9, 2013)

10.29		Member Interest Purchase Agreement dated as of December 3, 2014 between Tres Palacios Holdings LLC and Crestwood Equity Partners LP (incorporated herein by reference to Exhibit 10.26 to Crestwood Equity Partners LP's Form 10-filed on March 2, 2015)

101

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Exhibit Number		Description
10.30		Credit Agreement, dated October 7, 2013, by and among Crestwood Midstream Partners LP, as borrower, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on October 10, 2013)

10.31		Amendment No. 1 dated as of June 11, 2014, to the Credit Agreement dated as of October 7, 2014, among Crestwood Midstream Partners LP, Wells Fargo Bank, as Administrative Agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 10-Q filed on August 7, 2014)

10.32		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 September 30, 2015)

10.33		Assignment and Conveyance, effective April 30, 2007, between Cowtown Pipeline Partners L.P. and Cowtown Pipeline L.P. (incorporated herein by reference to Exhibit 10.13 to Form S-1/A of Crestwood Midstream Partners LP, File No. 333-140599, filed on July 30, 2007)

10.34		Form of Assignment between Cowtown Pipeline Partners L.P. and Cowtown Pipeline L.P. (incorporated herein by reference to Exhibit 10.14(a) to Form S-1/A of Crestwood Midstream Partners LP, File No. 333-140599, filed on July 30, 2007)

10.35		Schedule of Assignments, effective April 30, 2007, between Cowtown Pipeline Partners L.P. and Cowtown Pipeline L.P. (incorporated herein by reference to Exhibit 10.14(b) to Form S-1/A of Crestwood Midstream Partners LP, File No. 333-140599, filed on July 30, 2007)

10.36		Subordinated Promissory Note, dated August 10, 2007, made by Quicksilver Gas Services LP payable to the order of Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 10.2 Crestwood Midstream Partners LP’s form 8-K filed on August 16, 2007)

10.37		Omnibus Agreement, dated August 10, 2007, among Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 10.4 to Crestwood Midstream Partners LP’s Form 8-K filed on August 16, 2007)

10.38		Omnibus Agreement, dated October 8, 2010, by and among Crestwood Midstream Partners LP, Crestwood Gas Services GP LLC and Crestwood Holdings Partners, LLC (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on October 13, 2010)

10.39		Extension Agreement, dated December 3, 2008, between Quicksilver Gas Services LP and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 10.8 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2009 filed on March 15, 2010)

10.40		Option, Right of First Refusal, and Waiver in Amendment to Omnibus Agreement and Gas Gathering and Processing Agreement, dated June 9, 2009, among Quicksilver Resources Inc., Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC, Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on June 11, 2009)

10.41		Waiver, dated November 19, 2009, by Quicksilver Gas Services GP LLC (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on November 23, 2009)

10.42		Waiver, dated November 19, 2009, by Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 10.2 to Crestwood Midstream Partners LP’s Form 8-K filed on November 23, 2009)

10.43		Contribution, Conveyance and Assumption Agreement, dated August 10, 2007, by and among Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC, Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Quicksilver Gas Services Holdings LLC, Quicksilver Gas Services Operating GP LLC, Quicksilver Gas Services Operating LLC and the private investors named therein (incorporated herein by reference to Exhibit 10.3 to Crestwood Midstream Partners LP’s Form 8-K filed on August 16, 2007)

10.44		Sixth Amended and Restated Gas Gathering and Processing Agreement, dated September 1, 2008, among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 10-Q for the quarter ended September 30, 2008 filed on November 6, 2008)

102

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Exhibit Number		Description
10.45		Second Amendment to the Sixth Amended and Restated Gas Gathering and Processing Agreement, dated as of October 1, 2010, by and among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (incorporated herein by reference to Exhibit 10.16 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2010 filed on February 25, 2011)

10.46		Gas Gathering Agreement, effective December 1, 2009, between Cowtown Pipeline L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on January 8, 2010)

10.47		Amendment to Gas Gathering Agreement, dated as of October 1, 2010, by and between Quicksilver Resources Inc. and Cowtown Pipeline Partners L.P. (incorporated herein by reference to Exhibit 10.18 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2010 filed on February 25, 2011)

10.48		Addendum and Amendment to Gas Gathering and Processing Agreement Mash Unit Lateral, effective as of January 1, 2009, by and among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (incorporated herein by reference to Exhibit 10.15 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2009 filed on March 15, 2010)

10.49		Joint Operating Agreement, dated October 1, 2010, but effective as of July 1, 2010, between Quicksilver Resources Inc., Quicksilver Gas Services LP and Quicksilver Gas Services GP LLC (incorporated herein by reference to Exhibit 10.20 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2010 filed on February 25, 2011)

10.50		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)

10.51		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)

10.52		Purchase and Sale Agreement, dated June 21, 2013 by and between RKI Exploration & Production, LLC, Crestwood Niobrara LLC and Crestwood Midstream Partners LP (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed June 24, 2013)

10.53		Amended and Restated Limited Liability Company Agreement of Crestwood Niobrara LLC, dated July 19, 2013 (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on July 22, 2013)

10.54		Class A Preferred Unit Purchase Agreement, dated as of June 17, 2014, by and among Crestwood Midstream Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP's Form 8-K filed on June 19, 2014)

10.55		Board Representation and Standstill Agreement, dated as of June 17, 2014, by and among Crestwood Midstream GP LLC, Crestwood Midstream Partners LP and the Purchasers named herein (incorporated herein by reference to Exhibit 10.2 to Crestwood Midstream Partners LP's Form 8-K filed on June 19, 2014)

10.56		Support Agreement, dated as of May 5, 2015, by and among Crestwood Equity Partners L.P., 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)

10.57		Support Agreement, dated as of May 5, 2015, by and among Crestwood Equity Partners L.P., Crestwood Midstream Partners LP, Crestwood Holdings LLC and Crestwood Gas Services Holdings(incorporated herein by reference to Exhibit 10.2 to Crestwood Equity Partners LP's Form 8-K filed on May 6, 2015) LLC

10.58		Form of Letter Agreement (incorporated herein by reference to Exhibit 10.3 to Crestwood Equity Partners LP's Form 8-K filed on May 6, 2015)

10.59		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 September 30, 2015)

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Exhibit Number		Description
10.60		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 September 30, 2015)

**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

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


(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.

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Crestwood Equity Partners LP

Crestwood Midstream Partners LP

Consolidated Financial Statements

December 31, 2015 and 2014 and each of the

Three Years in the Period Ended

December 31, 2015

Contents



Crestwood Equity Partners LP

Report of Independent Registered Public Accounting Firm	106

Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial Reporting	107

Audited Consolidated Financial Statements:

Consolidated Balance Sheets	108

Consolidated Statements of Operations	109

Consolidated Statements of Comprehensive Income	111

Consolidated Statements of Partners’ Capital	112

Consolidated Statements of Cash Flows	113

Notes to Consolidated Financial Statements	122

Crestwood Midstream Partners LP

Report of Independent Registered Public Accounting Firm	115

Audited Consolidated Financial Statements:

Consolidated Balance Sheets	116

Consolidated Statements of Operations	117

Consolidated Statements of Partners’ Capital	119

Consolidated Statements of Cash Flows	120

Notes to Consolidated Financial Statements	122

105

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Crestwood Equity GP LLC and Unitholders of Crestwood Equity Partners LP

We have audited the accompanying consolidated balance sheets of Crestwood Equity Partners LP (the Company) as of December 31, 2015 and 2014, 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, 2015. Our audits also included the financial statement schedules listed in the Index at 15(a). These financial statements and schedules are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements and schedules based on our audits.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Crestwood Equity Partners LP at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles. Also, in our opinion, the related financial statement schedules, when considered in relation to the basic financial statements taken as a whole, present fairly in all material respects the information set forth therein.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Crestwood Equity Partners LP’s internal control over financial reporting as of December 31, 2015, 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 26, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 26, 2016

106

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Report of Independent Registered Public Accounting Firm on Internal Control Over Financial Reporting

The Board of Directors of Crestwood Equity GP LLC and Unitholders of Crestwood Equity Partners LP

We have audited Crestwood Equity Partners LP’s internal control over financial reporting as of December 31, 2015, 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). Crestwood Equity Partners LP’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 conducted our audit in accordance with the standards of the Public Company Accounting Oversight Board (United States). 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.

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.

In our opinion, Crestwood Equity Partners LP maintained, in all material respects, effective internal control over financial reporting as of December 31, 2015, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2015 consolidated financial statements of Crestwood Equity Partners LP and our report dated February 26, 2016 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 26, 2016

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

	December 31,
	2015		2014
Assets
Current assets:
Cash	$	0.5	$	8.8
Accounts receivable, less allowance for doubtful accounts of $0.4 million and $0.1 million at December 31, 2015 and December 31, 2014	236.5		379.6
Inventory	44.5		46.6
Assets from price risk management activities	32.6		79.8
Prepaid expenses and other current assets	21.7		23.3
Total current assets	335.8		538.1
Property, plant and equipment (Note 4)	3,747.7		4,273.9
Less: accumulated depreciation and depletion	436.9		380.1
Property, plant and equipment, net	3,310.8		3,893.8
Intangible assets (Note 4)	1,039.1		1,441.9
Less: accumulated amortization	229.0		210.6
Intangible assets, net	810.1		1,231.3
Goodwill	1,085.5		2,491.8
Investments in unconsolidated affiliates (Note 6)	254.3		295.1
Other assets	7.2		11.3
Total assets	$	5,803.7	$	8,461.4

Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	144.1	$	241.2
Accrued expenses and other liabilities (Note 4)	105.6		154.6
Liabilities from price risk management activities	7.4		25.4
Current portion of long-term debt (Note 9)	1.1		3.7
Total current liabilities	258.2		424.9
Long-term debt, less current portion (Note 9)	2,542.7		2,392.8
Other long-term liabilities	47.5		47.2
Deferred income taxes	8.4		12.0
Commitments and contingencies (Note 15)
Partners’ capital (Note 12):
Crestwood Equity Partners LP partners' capital (68,555,305 and 18,640,367 common units issued and outstanding at December 31, 2015 and December 31, 2014)	2,227.6		776.2
Preferred units (60,718,245 units issued and outstanding at December 31, 2015)	535.8		—
Total Crestwood Equity Partners LP partners’ capital	2,763.4		776.2
Interest of non-controlling partners in subsidiaries	183.5		4,808.3
Total partners’ capital	2,946.9		5,584.5
Total liabilities and partners’ capital	$	5,803.7	$	8,461.4

See accompanying notes.

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

	Year Ended December 31,
	2015			2014			2013
Revenues:
Product revenues:
Gathering and processing	$	1,051.2		$	1,831.5		$	273.6
Marketing, supply and logistics	857.5			1,339.4			714.9
	1,908.7			3,170.9			988.5
Service revenues:
Gathering and processing	325.9			332.2			161.5
Storage and transportation	266.3			264.6			130.9
Marketing, supply and logistics	128.0			160.6			70.9
Related party (Note 16)	3.9			3.0			74.9
	724.1			760.4			438.2
Total revenues	2,632.8			3,931.3			1,426.7

Costs of product/services sold (exclusive of items shown separately below):
Product costs:
Gathering and processing	1,074.4			1,816.9			234.5
Marketing, supply and logistics	705.6			1,196.1			681.7
Related party (Note 16)	28.9			42.2			32.5
	1,808.9			3,055.2			948.7
Service costs:
Gathering and processing	0.6			0.8			0.4
Storage and transportation	20.1			33.3			19.7
Marketing, supply and logistics	53.9			76.0			33.5
	74.6			110.1			53.6
Total costs of products/services sold	1,883.5			3,165.3			1,002.3

Expenses:
Operations and maintenance	190.2			203.3			104.6
General and administrative	116.3			100.2			93.5
Depreciation, amortization and accretion	300.1			285.3			167.9
	606.6			588.8			366.0
Other operating income (expense):
Gain (loss) on long-lived assets, net	(821.2		)	(1.9		)	5.3
Goodwill impairment	(1,406.3		)	(48.8		)	(4.1		)
Loss on contingent consideration (Note 15)	—			(8.6		)	(31.4		)
Operating income (loss)	(2,084.8		)	117.9			28.2

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

	Year Ended December 31,
	2015			2014			2013
Loss from unconsolidated affiliates, net	(60.8		)	(0.7		)	(0.1		)
Interest and debt expense, net	(140.1		)	(127.1		)	(77.9		)
Loss on modification/extinguishment of debt	(20.0		)	—			—
Other income, net	0.6			0.6			0.2
Loss before income taxes	(2,305.1		)	(9.3		)	(49.6		)
Provision (benefit) for income taxes	(1.4		)	1.1			1.0
Net loss	(2,303.7		)	(10.4		)	(50.6		)
Net loss attributable to non-controlling partners	636.8			66.8			57.3
Net income (loss) attributable to Crestwood Equity Partners LP	(1,666.9		)	56.4			6.7
Net income attributable to preferred units	(6.2		)	—			—
Net income (loss) attributable to partners	$	(1,673.1	)	$	56.4		$	6.7

Subordinated unitholders' interest in net income	$	—		$	1.3		$	0.3
Common unitholders' interest in net income (loss)	$	(1,673.1	)	$	55.1		$	6.4
Net income (loss) per limited partner unit:
Basic	$	(54.00	)	$	3.03		$	0.59
Diluted	$	(54.00	)	$	3.03		$	0.59
Weighted-average limited partners’ units outstanding (in thousands):
Basic	30,983			18,201			10,914
Dilutive units	—			439			439
Diluted	30,983			18,640			11,353

See accompanying notes.

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

	Year Ended December 31,
	2015			2014			2013
Net loss	$	(2,303.7	)	$	(10.4	)	$	(50.6	)
Change in fair value of Suburban Propane Partners, L.P. units (Note 12)	(2.7		)	(0.5		)	(0.1		)
Comprehensive loss	(2,306.4		)	(10.9		)	(50.7		)
Comprehensive loss attributable to non-controlling interest	636.8			66.8			57.3
Comprehensive income (loss) attributable to Crestwood Equity Partners LP	$	(1,669.6	)	$	55.9		$	6.6

See accompanying notes.

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

	Preferred Units		Partners			Non-Controlling Partners			Total Partners’ Capital
Balance at December 31, 2012	$	—	$	31.7		$	1,519.0		$	1,550.7
Net proceeds from issuance of common units by subsidiaries	—		—			714.0			714.0
Issuance of Legacy Crestwood Class D units to non-controlling interest	—		(126.3		)	126.3			—
Issuance of Legacy Crestwood Class C units to Crestwood Gas Services	—		0.6			(0.6		)	—
Issuance of preferred equity of subsidiary	—		—			96.1			96.1
Issuance of Crestwood Midstream Partners LP units for Arrow acquisition	—		—			200.0			200.0
Change in interest in Crestwood Marcellus Midstream LLC	—		238.9			(238.9		)	—
Gain (loss) on issuance of subsidiary units	—		(12.6		)	12.6			—
Exchange of Crestwood Midstream Partners LP units for CEQP units	—		182.3			(182.3		)	—
Invested capital from Legacy Inergy, net of debt (Note 3)	—		697.1			2,682.3			3,379.4
Contribution from Crestwood Holdings LLC	—		—			10.0			10.0
Distributions to partners	—		(56.6		)	(214.5		)	(271.1		)
Distribution of Legacy Crestwood Class C units to non-controlling interests	—		(0.1		)	0.1			—
Distribution for additional interest in Crestwood Marcellus Midstream LLC	—		(129.0		)	—			(129.0		)
Unit-based compensation charges	—		1.7			15.7			17.4
Taxes paid for unit-based compensation vesting	—		(2.8		)	(5.5		)	(8.3		)
Change in fair value of Suburban Propane Partners, L.P. units (Note 12)	—		(0.1		)	—			(0.1		)
Other	—		0.1			—			0.1
Net income (loss)	—		6.7			(57.3		)	(50.6		)
Balance at December 31, 2013	—		831.6			4,677.0			5,508.6
Issuance of preferred equity of subsidiary	—		—			53.9			53.9
Issuance of CMLP Class A preferred units	—		—			430.5			430.5
Change in invested capital from Legacy Inergy, net of debt (Note 3)	—		(10.5		)	(4.8		)	(15.3		)
Distributions to partners	—		(102.5		)	(296.5		)	(399.0		)
Unit-based compensation charges	—		3.9			17.4			21.3
Taxes paid for unit-based compensation vesting	—		(2.3		)	(1.6		)	(3.9		)
Change in fair value of Suburban Propane Partners, L.P. units (Note 12)	—		(0.5		)	—			(0.5		)
Other	—		0.1			(0.8		)	(0.7		)
Net income (loss)	—		56.4			(66.8		)	(10.4		)
Balance at December 31, 2014	—		776.2			4,808.3			5,584.5
Issuance of CMLP Class A preferred units	—		—			58.8			58.8
Acquisition of CMLP non-controlling interest and conversion of preferred units	529.6		3,294.8			(3,824.4		)	—
Distributions to partners	—		(171.5		)	(234.2		)	(405.7		)
Unit-based compensation charges	—		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. (Note 12)	—		(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	$	535.8	$	2,227.6		$	183.5		$	2,946.9

See accompanying notes.

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

	Year Ended December 31,
	2015			2014			2013
Operating activities
Net loss	$	(2,303.7	)	$	(10.4	)	$	(50.6	)
Adjustments to reconcile net loss to net cash provided by operating activities:
Depreciation, amortization and accretion	300.1			285.3			167.9
Amortization of debt-related deferred costs, discounts and premiums	8.9			8.5			9.2
Market adjustment on interest rate swaps	(0.5		)	(2.7		)	(1.7		)
Unit-based compensation charges	19.7			21.3			17.4
(Gain) loss on long-lived assets, net	821.2			1.9			(5.3		)
Goodwill impairment	1,406.3			48.8			4.1
Loss on contingent consideration	—			8.6			31.4
Loss on modification/extinguishment of debt	20.0			—			—
Loss from unconsolidated affiliates, net, adjusted for cash distributions received	73.6			0.7			0.1
Deferred income taxes	(3.6		)	(5.2		)	(2.8		)
Other	0.7			—			(1.0		)
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	119.7			60.4			(39.9		)
Inventory	2.0			26.9			(23.6		)
Prepaid expenses and other current assets	1.8			(11.4		)	11.2
Accounts payable, accrued expenses and other liabilities	(128.0		)	(96.4		)	44.2
Reimbursements of property, plant and equipment	73.3			21.5			—
Change in price risk management activities, net	29.2			(74.8		)	27.7
Net cash provided by operating activities	440.7			283.0			188.3

Investing activities
Acquisitions, net of cash acquired (Note 3)	—			(19.5		)	(555.6		)
Purchases of property, plant and equipment	(182.7		)	(424.0		)	(347.0		)
Investment in unconsolidated affiliates	(42.0		)	(108.6		)	(151.5		)
Capital distributions from unconsolidated affiliates	9.3			—			—
Proceeds from sale of Tres Palacios	—			66.4			—
Proceeds from sale of assets	2.7			2.7			11.2
Net cash used in investing activities	(212.7		)	(483.0		)	(1,042.9		)

See accompanying notes.

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

	Year Ended December 31,
	2015			2014			2013
Financing activities
Proceeds from the issuance of long-term debt	4,261.8			2,823.9			2,466.9
Principal payments on long-term debt	(4,113.0		)	(2,696.0		)	(1,967.6		)
Payments on capital leases	(2.2		)	(3.2		)	(4.3		)
Payments for debt-related deferred costs	(17.3		)	(1.9		)	(33.1		)
Financing fees paid for early debt redemption	(13.6		)	—			—
Distributions to partners	(171.5		)	(102.5		)	(68.4		)
Distributions paid to non-controlling partners	(234.2		)	(296.5		)	(204.5		)
Distribution for additional interest in Crestwood Marcellus Midstream LLC	—			—			(129.0		)
Net proceeds from issuance of Crestwood Midstream Partners LP common units	—			—			714.0
Net proceeds from issuance of preferred equity of subsidiary	—			53.9			96.1
Net proceeds from the issuance of Crestwood Midstream Partners LP Class A preferred units	58.8			430.5			—
Taxes paid for unit-based compensation vesting	(3.8		)	(3.9		)	(10.5		)
Other	(1.3		)	(0.7		)	0.1
Net cash provided by (used in) financing activities	(236.3		)	203.6			859.7

Net change in cash	(8.3		)	3.6			5.1
Cash at beginning of period	8.8			5.2			0.1
Cash at end of period	$	0.5		$	8.8		$	5.2

Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	129.0		$	114.4		$	64.9
Cash paid during the period for income taxes	$	4.7		$	6.6		$	2.5

Supplemental schedule of noncash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(14.1	)	$	(40.6	)	$	(38.0	)

Acquisitions, net of cash acquired:
Current assets				$	0.5		$	409.6
Property, plant and equipment				13.5			2,487.2
Intangible assets				9.4			660.9
Goodwill				3.6			2,195.4
Other assets				—			32.1
Current liabilities				(2.7		)	(420.6		)
Debt				(3.5		)	(1,079.3		)
Invested capital of Crestwood Equity Partners LP, net of debt (Note 3)				—			(3,579.4		)
Other liabilities				(1.3		)	(150.3		)
Total acquisitions, net of cash acquired				$	19.5		$	555.6

See accompanying notes.

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Report of Independent Registered Public Accounting Firm

The Board of Directors of Crestwood Equity GP LLC

We have audited the accompanying consolidated balance sheets of Crestwood Midstream Partners LP (the Company) as of December 31, 2015 and 2014, and the related consolidated statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2015. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. We were not engaged to perform an audit of the Company's internal control over financial reporting. Our audits included consideration of internal control over financial reporting as a basis for designing audit procedures that are appropriate in the circumstances, 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. An audit also includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Crestwood Midstream Partners LP at December 31, 2015 and 2014, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2015, in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Houston, Texas

February 26, 2016

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

	December 31,
	2015		2014
Assets
Current assets:
Cash	$	0.1	$	7.6
Accounts receivable, less allowance for doubtful accounts of $0.4 million and $0.1 million at December 31, 2015 and December 31, 2014, respectively	236.5		379.3
Inventory	44.5		46.6
Assets from price risk management activities	32.6		79.8
Prepaid expenses and other current assets	19.9		23.3
Total current assets	333.6		536.6
Property, plant and equipment (Note 4)	4,077.7		4,144.6
Less: accumulated depreciation and depletion	552.0		398.6
Property, plant and equipment, net	3,525.7		3,746.0
Intangible assets (Note 4)	1,022.6		1,123.7
Less: accumulated amortization	220.3		154.1
Intangible assets, net	802.3		969.6
Goodwill	1,085.5		2,234.6
Investments in unconsolidated affiliates (Note 6)	254.3		295.1
Other assets	3.1		3.3
Total assets	$	6,004.5	$	7,785.2

Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	141.4	$	235.0
Accrued expenses and other liabilities (Note 4)	103.3		150.1
Liabilities from price risk management activities	7.4		25.4
Current portion of long-term debt (Note 9)	0.9		0.8
Total current liabilities	253.0		411.3
Long-term debt, less current portion (Note 9)	2,542.7		2,014.5
Other long-term liabilities	43.3		38.3
Deferred income taxes	0.4		0.7
Commitments and contingencies (Note 15)
Partners’ capital (Note 12):
Class A preferred units (17,917,870 units issued and outstanding at December 31, 2014)	—		447.7
Partners' capital (187,965,105 common units issued and outstanding at December 31, 2014)	2,981.6		4,701.0
Total Crestwood Midstream Partners LP partners’ capital	2,981.6		5,148.7
Interest of non-controlling partners in subsidiary	183.5		171.7
Total partners’ capital	3,165.1		5,320.4
Total liabilities and partners’ capital	$	6,004.5	$	7,785.2

See accompanying notes.

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

	Year Ended December 31,
	2015			2014			2013
Revenues:
Product revenues:
Gathering and processing	$	1,051.2		$	1,831.5		$	273.6
Marketing, supply and logistics	857.5			1,339.4			714.9
	1,908.7			3,170.9			988.5

Service revenues:
Gathering and processing	325.9			332.2			161.5
Storage and transportation	266.3			250.8			116.8
Marketing, supply and logistics	128.0			160.6			70.9
Related party (Note 13)	3.9			3.0			74.9
	724.1			746.6			424.1
Total revenues	2,632.8			3,917.5			1,412.6

Costs of product/services sold (exclusive of items shown separately below):
Product costs:
Gathering and processing	1,074.4			1,816.9			234.5
Marketing, supply and logistics	705.6			1,196.1			681.7
Related party (Note 13)	28.9			42.2			32.5
	1,808.9			3,055.2			948.7

Service costs:
Gathering and processing	0.6			0.8			0.4
Storage and transportation	20.1			22.8			12.8
Marketing, supply and logistics	53.9			76.0			33.5
	74.6			99.6			46.7
Total costs of products/services sold	1,883.5			3,154.8			995.4

Expenses:
Operations and maintenance	188.7			195.4			103.4
General and administrative (Note 13)	105.6			91.7			84.1
Depreciation, amortization and accretion	278.5			255.4			139.4
	572.8			542.5			326.9
Other operating income (expense):
Gain (loss) on long-lived assets, net	(227.8		)	(35.1		)	5.3
Goodwill impairment	(1,149.1		)	(48.8		)	(4.1		)
Loss on contingent consideration (Note 12)	—			(8.6		)	(31.4		)
Operating income (loss)	(1,200.4		)	127.7			60.1

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

	Year Ended December 31,
	2015			2014			2013
Loss from unconsolidated affiliates, net	(60.8		)	(0.7		)	(0.1		)
Interest and debt expense, net	(130.5		)	(111.4		)	(71.7		)
Loss on modification/extinguishment of debt	(18.9		)	—			—
Income (loss) before income taxes	(1,410.6		)	15.6			(11.7		)
Provision for income taxes	—			0.9			0.7
Net income (loss)	(1,410.6		)	14.7			(12.4		)
Net income attributable to non-controlling partners	(23.1		)	(16.8		)	(4.9		)
Net loss attributable to Crestwood Midstream Partners LP	(1,433.7		)	(2.1		)	(17.3		)
Net income attributable to Class A preferred units	(23.1		)	(17.2		)	—
Net loss attributable to partners	$	(1,456.8	)	$	(19.3	)	$	(17.3	)

See accompanying notes.

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CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (in millions)

	Crestwood Midstream Partners LP
	Class A Preferred Units			Partners			Non-controlling Partners			Total Partners’ Capital
Balance at December 31, 2012	$	—		$	859.7		$	—		$	859.7
Net proceeds from issuance of common units	—			714.0			—			714.0
Issuance of common units for Arrow acquisition	—			200.0			—			200.0
Invested capital from Legacy Inergy, net of debt (Note 3)	—			3,827.8			—			3,827.8
Contributions from general partner	—			15.5			—			15.5
Distributions to partners	—			(419.7		)	—			(419.7		)
Unit-based compensation charges	—			15.8			—			15.8
Taxes paid for unit-based compensation vesting	—			(5.5		)	—			(5.5		)
Issuance of preferred equity of subsidiary	—			—			96.1			96.1
Net income (loss)	—			(17.3		)	4.9			(12.4		)
Balance at December 31, 2013	—			5,190.3			101.0			5,291.3
Change in invested capital from Legacy Inergy, net of debt (Note 3)	—			(15.3		)	—			(15.3		)
Issuance of Class A preferred units	430.5			—			—			430.5
Issuance of preferred equity of subsidiary	—			—			53.9			53.9
Distributions to partners	—			(470.5		)	—			(470.5		)
Unit-based compensation charges	—			18.1			—			18.1
Taxes paid for unit-based compensation vesting	—			(1.6		)	—			(1.6		)
Other	—			(0.7		)	—			(0.7		)
Net income (loss)	17.2			(19.3		)	16.8			14.7
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

See accompanying notes.

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

	Year Ended December 31,
	2015			2014			2013
Operating activities
Net income (loss)	$	(1,410.6	)	$	14.7		$	(12.4	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion	278.5			255.4			139.4
Amortization of debt-related deferred costs, discounts and premiums	8.1			7.3			9.1
Unit-based compensation charges	18.1			18.1			15.8
(Gain) loss on long-lived assets, net	227.8			35.1			(5.3		)
Goodwill impairment	1,149.1			48.8			4.1
Loss on contingent consideration	—			8.6			31.4
Loss on modification/extinguishment of debt	18.9			—			—
Loss from unconsolidated affiliates, net, adjusted for cash distributions received	73.6			0.7			0.1
Deferred income taxes	(0.3		)	0.7			—
Other	0.7			—			0.1
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	119.4			60.4			(39.9		)
Inventory	2.1			26.9			(23.6		)
Prepaid expenses and other current assets	3.7			(11.9		)	5.9
Accounts payable, accrued expenses and other liabilities	(119.8		)	25.8			101.3
Reimbursements of property, plant and equipment	73.3			21.5			—
Change in price risk management activities, net	29.2			(74.8		)	27.7
Net cash provided by operating activities	471.8			437.3			253.7

Investing activities
Acquisitions, net of cash acquired (Note 3)	—			(19.5		)	(561.5		)
Purchases of property, plant and equipment	(182.7		)	(421.7		)	(339.3		)
Investment in unconsolidated affiliates	(41.8		)	(144.4		)	(151.5		)
Capital distributions from unconsolidated affiliates	9.3			—			—
Proceeds from sale of assets	2.7			2.7			11.2
Net cash used in investing activities	(212.5		)	(582.9		)	(1,041.1		)

See accompanying notes.

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

	Year Ended December 31,
	2015			2014			2013
Financing activities
Proceeds from the issuance of long-term debt	3,490.1			2,089.9			2,072.8
Principal payments on long-term debt	(2,960.9		)	(1,950.0		)	(1,634.5		)
Payments on capital leases	(2.2		)	(3.2		)	(4.3		)
Payments for debt-related deferred costs	(17.3		)	(0.1		)	(32.0		)
Financing fees paid for early debt redemption	(13.6		)	—			—
Distributions to partners	(819.5		)	(470.5		)	(419.7		)
Contributions from general partner	—			—			5.5
Net proceeds from issuance of common units	—			—			714.0
Net proceeds from issuance of preferred equity of subsidiary	—			53.9			96.1
Net proceeds from issuance of Class A preferred units	58.8			430.5			—
Taxes paid for unit-based compensation vesting	(2.1		)	(1.6		)	(5.5		)
Other	(0.1		)	(0.8		)	—
Net cash provided by (used in) financing activities	(266.8		)	148.1			792.4

Net change in cash	(7.5		)	2.5			5.0
Cash at beginning of period	7.6			5.1			0.1
Cash at end of period	$	0.1		$	7.6		$	5.1

Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	118.2		$	96.9		$	56.7
Cash paid during the period for income taxes	$	0.6		$	0.4		$	—

Supplemental schedule of noncash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(14.1	)	$	(40.6	)	$	(30.5	)

Acquisitions, net of cash acquired:
Current assets				$	0.5		$	240.0
Property, plant and equipment				13.5			2,076.8
Intangible assets				9.4			519.4
Goodwill				3.6			1,583.2
Other assets				—			22.3
Current liabilities				(2.7		)	(243.9		)
Debt				(3.5		)	(745.0		)
Invested capital of Crestwood Midstream Partners LP, net of debt (Note 3)				—			(2,882.3		)
Other liabilities				(1.3		)	(9.0		)
Total acquisitions, net of cash acquired				$	19.5		$	561.5

See accompanying notes.

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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 21% of Crestwood Equity's limited partner units and 438,789 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.

Crestwood Merger (2013). In May 2013, Crestwood Holdings and the former owners of Crestwood Equity's general partner entered into a series of transactions that would effectively consolidate and combine the operations of Legacy Crestwood and Legacy Inergy (both as defined below). The parties first completed a series of "upstairs" transactions in June 2013 that resulted in Crestwood Holdings' acquisition of control of Crestwood Equity. The "downstairs" portion of the strategic business combination was completed in October 2013 when publicly-traded Legacy Crestwood merged with and into publicly-traded Inergy Midstream (the Crestwood Merger) and Inergy Midstream immediately thereafter changed its name to Crestwood Midstream Partners LP. Additionally, Legacy Crestwood unitholders (other than Crestwood Holdings) received a one-time $34.9 million cash payment at the closing of the merger in October 2013, or $1.03 per unit, $24.9 million of which was paid by Inergy Midstream and $10 million of which was paid by Crestwood Holdings.

Following the closing of the Crestwood Merger on October 7, 2013, Crestwood Holdings exchanged 7,100,000 common units of Crestwood Midstream for 14,300,000 of CEQP common units pursuant to an option granted to Crestwood Holdings when it acquired CEQP's general partner.

Simplification Merger (2015). In May 2015, CEQP, Crestwood Midstream and certain of their affiliates entered into a definitive agreement under which Crestwood Midstream would merge with a wholly-owned subsidiary of CEQP, with Crestwood Midstream surviving as a wholly-owned subsidiary of CEQP (the Simplification Merger). On September 30, 2015, the Simplification Merger was completed immediately following the affirmative approval of the merger by Crestwood Midstream's unaffiliated unitholders and Crestwood Midstream completed the merger on that date. As part of the merger consideration, Crestwood Midstream's common and preferred unitholders (other than CEQP and its subsidiaries) received 2.75 common or preferred units of CEQP for each common or preferred unit of Crestwood Midstream held upon the completion of the merger.

Prior to the Simplification Merger, CEQP indirectly owned a non-economic general partnership interest in CMLP and 100% of its incentive distribution rights (IDRs), which entitled CEQP to receive 50% of all distributions paid by Crestwood Midstream in excess of its initial quarterly distribution of $0.37 per common unit. Crestwood Midstream's common units were also listed on the New York Stock Exchange (NYSE) under the listing symbol "CMLP." Upon becoming a wholly-owned subsidiary of CEQP as a result of the Simplification Merger, Crestwood Midstream's IDRs were eliminated and its common units ceased to be listed on the NYSE.

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The diagram below reflects a simplified version of our ownership structure as of December 31, 2015:

During the fourth quarter of 2015, Crestwood Holdings acquired 3,458,912 CEQP units from the public in a series of purchases. In January 2016, Crestwood Holdings acquired an additional 1,525,430 units from the public.

Unless otherwise indicated, references in this report to “we,” “us,” “our,” “ours,” “our company,” the “partnership,” the “Company,” “Crestwood Equity,” 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 (i) the Crestwood Merger refers to the October 7, 2013 merger of the Company’s wholly-owned subsidiary with and into Legacy Crestwood, with Inergy Midstream continuing as the surviving legal entity; (ii) Legacy Inergy refers to either Inergy, L.P. itself or Inergy, L.P. and its consolidated subsidiaries prior to the Crestwood Merger, (iii) Inergy Midstream and NRGM refer to either Inergy Midstream, L.P. itself or Inergy Midstream, L.P. and its consolidated subsidiaries prior to the Crestwood Merger, (iv) Legacy Crestwood and Legacy CMLP refer to either Crestwood Midstream Partners LP itself or Crestwood Midstream Partners LP and its consolidated subsidiaries prior to the Crestwood Merger, and (v) Crestwood Midstream and CMLP refers to

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Crestwood Midstream Partners LP and its consolidated subsidiaries following the Crestwood Merger. See Note 3 for additional information on the Crestwood Merger.

Description of Business

Prior to the Simplification Merger, except for the assets comprising our proprietary NGL marketing business, all of our operating assets were owned by or through Crestwood Midstream. Crestwood Operations LLC (Crestwood Operations), a wholly-owned subsidiary of CEQP, owned and operated the assets comprising our proprietary NGL marketing business, consisting mainly of our West Coast NGL assets, our Seymour NGL storage facility, and our NGL transportation terminals and fleet. In connection with the closing of the Simplification Merger on September 30, 2015, CEQP contributed 100% of its interest in Crestwood Operations to Crestwood Midstream. As a result of this equity contribution, and as of December 31, 2015, substantially all of the Company's consolidated assets are owned by or through Crestwood Midstream.

In conjunction with the Simplification Merger described above, we modified our segments and our financial statements now reflect three operating and reporting segments: (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) marketing, supply and logistics operations (formerly NGL and crude services operations). Consequently, the results of our Arrow operations are now reflected in our gathering and processing operations for all periods presented and our COLT operations and Powder River Basin Industrial Complex, LLC (PRBIC) investment are now reflected in our storage and transportation operations for all periods presented. These respective operations were previously included in our NGL and crude services operations. Below is a description of our operating and reporting segments.

•

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 Arkansas, Louisiana, New Mexico, North Dakota, Texas, West Virginia, and Wyoming. This segment primarily includes (i) our crude oil, gas and produced water gathering systems in the Bakken Shale play; (ii) our rich gas gathering systems and processing plants in the Bakken, Barnett, Marcellus, Delaware Permian and Powder River Basin (PRB) Niobrara Shale plays; and (iii) our dry gas gathering systems in the Barnett, Fayetteville, and Haynesville Shale plays.

•

Storage and Transportation: our storage and transportation (S&T) operations provide natural gas and crude oil storage and transportation services to producers, utilities and other customers. This segment primarily includes (i) our natural gas storage facilities (Stagecoach, Thomas Corners, Steuben, Seneca Lake and Tres Palacios, our equity investment); (ii) our regulated natural gas transportation facilities (the North-South Facilities, the MARC I Pipeline and the East Pipeline) in New York and Pennsylvania; and (iii) our crude oil rail loading facilities (the COLT Hub located in North Dakota and PRBIC, our equity investment located 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, New Jersey, New York and Rhode Island, and our truck maintenance facilities located in Indiana, Mississippi, Newy Jersey and Ohio; (ii) our West Coast processing and fractionation operations located near Bakersfield, California; (iii) our NGL storage facilities in Bath, New York and Seymour, Indiana; (iv) our crude oil and produced water transportation assets; and (v) our solution-mining and salt production company (US Salt).

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. Our consolidated financial statements for prior periods include reclassifications that were made 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.

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. The acquisition of Legacy Crestwood GP was accounted for as a reverse acquisition under the purchase method of accounting in accordance with accounting standards for business

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combinations. The accounting for the reverse acquisition resulted in the legal acquiree (Legacy Crestwood GP) being the acquirer for accounting purposes. Crestwood Equity's accounting acquiree (inclusive of Legacy Inergy) was subject to the purchase method of accounting and its balance sheet was adjusted to fair market value as of June 19, 2013. Although Legacy Crestwood GP was the acquiring entity for accounting purposes, Crestwood Equity was the acquiring entity for legal purposes.

Crestwood Midstream. Crestwood Midstream's consolidated financial statements were originally the financial statements of Legacy Crestwood, prior to the Crestwood Merger and the merger of Legacy Crestwood with and into Inergy Midstream on October 7, 2013. The merger of Legacy Crestwood and Inergy Midstream on October 7, 2013 was accounted for as a reverse merger amongst entities under common control with Legacy Crestwood continuing as the surviving entity for accounting purposes and Inergy Midstream continuing as the surviving entity for legal purposes. As the reverse merger was amongst entities under common control, the Crestwood Midstream financial statements were recast to reflect the operations of Inergy Midstream as being acquired by Legacy Crestwood on June 19, 2013, the date in which Inergy Midstream and Legacy Crestwood came under common control.

In connection with the closing of the Simplification Merger on September 30, 2015, CEQP contributed 100% of its interest in Crestwood Operations to Crestwood Midstream. As a result of this equity contribution, 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.

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. 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. We use the cost method of accounting where we are unable to exert significant influence over the entity.

In December 2014, Crestwood Equity sold its 100% interest in Tres Palacios Gas Storage Company LLC (Tres Palacios) to Tres Palacios Holdings LLC (Tres Holdings), a newly formed joint venture between Crestwood Midstream and an affiliate of Brookfield Infrastructure Group (Brookfield); consequently, Crestwood Equity deconsolidated Tres Palacios and began accounting for the investment in Tres Holdings under the equity method of accounting through its indirect ownership in Crestwood Midstream. See Note 6 for additional information related to the sale of Tres Palacios.

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 our storage and transportation operations and our marketing, supply and logistics operations are stated at the lower of cost or market and are computed predominantly using the average cost method. Our inventory consisted primarily of NGLs of approximately $35.4 million and $37.5 million at December 31, 2015 and 2014.

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

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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	20
Facilities and equipment	20 – 25
Buildings, rights-of-way and easements	20 – 40
Office furniture and fixtures	5 – 10
Vehicles	5

We deplete salt deposits included in our property, plant and equipment utilizing the unit of production method.

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 2015 and 2014, we recorded the following impairments for our property, plant and equipment included in gain (loss) on long-lived assets in our consolidated statements of operations:

•

During 2015 and 2014, we incurred $8.5 million and $13.2 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 Granite Wash in the near future given current and future anticipated market conditions related to normal gas and NGLs. The fair value of our property, plant and equipment related to our Granite Wash operations was $11.2 million as of December 31, 2015.

•

During 2015, Crestwood Equity incurred $354.4 million of impairments of its property, plant and equipment related to its Barnett gathering and processing operations, which resulted from the recent 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. The fair value of our property, plant and equipment related to our Barnett operations was $298.5 million as of December 31, 2015.

•

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. The fair value of our property, plant and equipment related to our Fayetteville and Haynesville operations was $59.3 million and $3.8 million, respectively, as of December 31, 2015.

•

During 2015, we incurred $31.2 million of impairments on our property, plant and equipment related to our Watkins Glen development project in our marketing, supply and logistics segment, which resulted from continued delays and uncertainties in the permitting of our proposed NGL storage facility. The fair value of our property, plant and equipment related to our Watkins Glen development project was $6.7 million as of December 31, 2015.

The remaining carrying value related to the property, plant and equipment associated with these assets represents the fair value of the property, plant and equipment as of December 31, 2015, which is a Level 3 fair value measurement. 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. 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.

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Identifiable Intangible Assets

Our identifiable intangible assets consist of customer accounts, covenants not to compete, trademarks, certain revenue contracts and deferred financing costs. 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. Deferred financing costs represent financing costs incurred in obtaining financing and are being amortized over the term of the related debt using a method which approximates the effective interest method and has a weighted average life of six years. 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 2015 and 2014, we recorded the following impairments of our intangible assets included in gain (loss) on long-lived assets in our consolidated statements of operations:

•

During 2014, we fully impaired $20 million of intangible assets 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 Granite Wash in the near future given current and future anticipated market conditions related to natural gas and NGLs.


•	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 recent 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.

The remaining carrying value related to these intangible assets represents the fair value of the intangible assets as of December 31, 2015, which is a Level 3 fair value measurement. 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. 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	22
Covenants not to compete	5
Trademarks	6

Goodwill

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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.



	Goodwill at December 31, 2013		Final Purchase Price Allocation Adjustments			Goodwill Impairments during the Year Ended December 31, 2014		Goodwill at December 31, 2014		Goodwill Impairments during the Year Ended December 31, 2015⁽¹⁾		Goodwill at December 31, 2015
Gathering and Processing
Fayetteville	$	76.8	$	—		$	4.3	$	72.5	$	72.5	$	—
Granite Wash	14.2		—			14.2		—		—		—
Marcellus	8.6		—			—		8.6		—		8.6
Arrow	45.5		0.4			—		45.9		—		45.9
Storage and Transportation
Northeast Storage and Transportation	727.1		(0.8		)	—		726.3		—		726.3
COLT	670.5		(2.2		)	—		668.3		623.4		44.9
Marketing, Supply and Logistics
West Coast	89.1		(3.2		)	—		85.9		85.9		—
Supply and Logistics	269.5		(3.3		)	—		266.2		99.0		167.2
Storage and Terminals	104.7		(0.5		)	—		104.2		53.7		50.5
US Salt	16.1		(1.3		)	2.2		12.6		—		12.6
Trucking	178.4		(0.5		)	—		177.9		148.4		29.5
Watkins Glen	94.6		(0.3		)	28.1		66.2		66.2		—
Total Crestwood Midstream	$	2,295.1	$	(11.7	)	$	48.8	$	2,234.6	$	1,149.1	$	1,085.5
Barnett (Gathering and Processing)	257.2		—			—		257.2		257.2		—
Total Crestwood Equity	$	2,552.3	$	(11.7	)	$	48.8	$	2,491.8	$	1,406.3	$	1,085.5


(1)	Included in these amounts are approximately $515.4 million and $470.6 million of goodwill impairments recorded at Crestwood Equity and Crestwood Midstream, respectively, during the three months ended December 31, 2015, which primarily resulted from the finalization of the preliminary goodwill impairments recorded on these reporting units during the three months ended September 30, 2015.

The goodwill impairments recorded during 2015 and 2014 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

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commodity prices and its impact on the midstream industry and our customers. We utilized discount rates ranging from 10% to 16% to determine the fair value of our reporting units as of December 31, 2015.

The remaining goodwill related to these reporting units represents the fair value of the goodwill as of December 31, 2015, which is a Level 3 fair value measurement.

Investment in Unconsolidated Affiliates

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.

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.

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. The remaining carrying value of $202.4 million and $15.1 million related to our Jackalope and PRBIC equity-method investments, respectively, represents the fair value of the equity-method investments as of December 31, 2015, which is a Level 3 fair value measurement.

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 right-of-way contracts we hold and our facilities whether owned or leased. 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, 2015 and 2014, 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

We gather, 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 marketing, supply and logistics operations, we take title to the underlying commodity. In the current year, we changed our income statement to classify the revenues associated with the products to which we take title as product revenues in our consolidated statement of operations. In addition, we also reclassified our historical consolidated statements of operations for the years ended December 31,2014 and 2013 to reflect this change. We classify all other revenues as service revenues in our consolidated statement of operations.

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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, 2015 and 2014, we had deferred revenue of approximately $14.2 million and $12.2 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.

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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, 2015, 2014 or 2013.

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.

New Accounting Pronouncements Issued But Not Yet Adopted

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

In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Update 2014-09, Revenue from Contracts with Customers, which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers and supersedes current revenue recognition guidance. We expect to adopt the provisions of this standard effective January 1, 2018 and are currently evaluating the impact that this standard will have on our consolidated financial statements.

In February 2015, the FASB issued Accounting Standards Update 2015-02, Consolidation (Topic 810): Amendments to the Consolidation Analysis, which provides additional guidance on the consolidation of limited partnerships and on the evaluation of variable interest entities. We adopted the provisions of this standard effective January 1, 2016 and it is not anticipated to have a material impact on our consolidated financial statements.

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

In February 2016, the FASB issued Accounting Standards Update 2016-02, Leases (Topic 842), which revises the accounting for leases by requiring certain leases to be recognized as assets and liabilities in 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.

Note 3 – Acquisitions

2014 Acquisitions

Crude Transportation Acquisitions (Bakken)

Red Rock. On March 21, 2014, Crestwood Midstream purchased substantially all of the operating assets of Red Rock Transportation Inc. (Red Rock) for approximately $13.8 million, comprised of $12.1 million paid at closing plus deferred

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payments of $1.8 million. Red Rock is a trucking operation located in Watford City, North Dakota which provides crude oil and produced water hauling services to the oilfields of western North Dakota and eastern Montana. The acquired assets include a fleet of approximately 56 trailer tanks, 22 double bottom body tanks and 44 tractors with 28,000 barrels per day of transportation capacity. We finalized the purchase price and allocated approximately $10.6 million of the purchase price to property, plant and equipment and intangible assets and approximately $3.2 million to goodwill. Goodwill recognized related primarily to anticipated operating synergies between the assets acquired and our existing assets. These assets are included in our marketing, supply and logistics segment.

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

The acquisitions of Red Rock and LT Enterprises were not material to our marketing, supply and logistics segment's results of operations for the year ended December 31, 2014. In addition, transaction costs related to these acquisitions were not material for the year ended December 31, 2014.

2013 Acquisitions

Crestwood Merger

As described in Note 2, the acquisition of Legacy Crestwood GP was accounted for as a reverse merger under the purchase method of accounting in accordance with the accounting standards for business combinations. This accounting treatment requires the accounting acquiree (Legacy Inergy) to have its assets and liabilities stated at fair value as well as any other purchase accounting adjustments as of June 19, 2013, the date of the acquisition. The fair value of Legacy Inergy was calculated based on the consolidated enterprise fair value of Legacy Inergy as of June 19, 2013. This consolidated enterprise fair value considered Legacy Inergy and Inergy Midstream's (i) discounted future cash flows based on their operations; (ii) the stock prices of NRGY and NRGM; (iii) the value of their outstanding senior notes based on quoted market prices for same or similar issuances; (iv) the value of their outstanding floating rate debt; and (v) the value of IDRs of Crestwood Midstream.

As discussed in Note 2, the Crestwood Merger was accounted for as a reverse merger amongst entities under common control. This accounting treatment requires the accounting acquiree (Inergy Midstream) to have its assets and liabilities stated at fair value as well as any other purchase accounting adjustments as of June 19, 2013, the date in which Legacy Crestwood and Inergy Midstream came under common control. The fair value of Legacy Inergy was calculated based on the consolidated enterprise value of Inergy Midstream as of June 19, 2013. This consolidated enterprise value considered Inergy Midstream's (i) discounted future cash flows based on its operations; (ii) the stock price of Inergy Midstream; (iii) the value of its outstanding senior notes based on quoted market prices for same or similar issuances; and (iv) the value of its outstanding floating rate debt.

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In June 2014, we finalized the purchase price allocations for these reverse mergers. The following table summarizes the final valuation of the assets acquired and liabilities assumed at the merger date (in millions):



	CEQP		CMLP
Current assets	$	224.5	$	49.1
Property, plant and equipment	2,088.1		1,677.8
Intangible assets	337.5		196.0
Other assets	12.7		2.9
Total identifiable assets acquired	2,662.8		1,925.8

Current liabilities	207.6		30.9
Long-term debt	1,079.3		745.0
Other long-term liabilities	146.6		5.3
Total liabilities assumed	1,433.5		781.2

Net identifiable assets acquired	1,229.3		1,144.6
Goodwill	2,134.8		1,532.7
Net assets acquired	$	3,364.1	$	2,677.3

The amounts in the table above related to CMLP reflect historical purchase price allocation amounts and have not been recasted to reflect the contribution of Crestwood Operations to Crestwood Midstream as described in Note 1. Reductions of approximately $15.3 million from our preliminary estimates of the fair value of CEQP as of December 31, 2013 relate primarily to goodwill and were based on additional valuation information obtained on the components that comprised the enterprise fair value of Legacy Inergy as well as certain of our storage and transportation assets and obligations, primarily related to our Tres Palacios storage operations, which we previously consolidated. Of the $2,134.8 million of goodwill recorded at December 31, 2014 at CEQP as a result of the Crestwood Merger, $740.2 million was reflected in our marketing, supply and logistics segment and $1,394.6 million was reflected in our storage and transportation segment. Of the $1,532.7 million of goodwill recorded at December 31, 2014 at CMLP as a result of the Crestwood Merger, $138.1 million was reflected in our marketing, supply and logistics segment and $1,394.6 million was reflected in our storage and transportation segment. Goodwill recognized related primarily to synergies and new expansion opportunities expected to result from the combination of Legacy Crestwood and Legacy Inergy. During 2015 and 2014, we recorded impairments of goodwill for certain of our reporting units acquired in the Crestwood Merger. See Note 2 for a further discussion of our goodwill impairments.

During the period from June 19, 2013 to December 31, 2013, CEQP and CMLP recognized $916.7 million and $902.6 million of operating revenues, respectively and $23.9 million and $32.8 million of operating income, respectively related to these reverse mergers. In addition, CEQP and CMLP recognized transaction costs related to the reverse mergers of approximately $3.4 million and $2.1 million, respectively for the year ended December 31, 2014 and $30.1 million and $24.7 million, respectively for the year ended December 31, 2013. These costs are reflected in general and administrative expenses in our consolidated statements of operations.

Arrow Acquisition

On November 8, 2013, Crestwood Midstream acquired Arrow Midstream Holdings, LLC (Arrow), a privately-held midstream company, for approximately $750 million, subject to customary capital expenditure and working capital adjustments of approximately $11.3 million, representations, warranties and indemnifications. The acquisition was consummated by merging a wholly-owned subsidiary of Crestwood Midstream with and into Arrow (the Arrow Acquisition), with Arrow continuing as the surviving entity and as a result, a wholly-owned subsidiary of Crestwood Midstream. The base merger consideration consisted of $550 million in cash and 8,826,125 common units of Crestwood Midstream issued to the sellers, subject to adjustment for standard working capital provisions.

Arrow, through its wholly-owned subsidiaries, owns and operates substantial crude oil, natural gas and water gathering systems located on the Fort Berthold Indian Reservation in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota. Arrow also owns salt water disposal wells and a 23-acre central delivery point with multiple pipeline take-away outlets and a fully-automated truck loading facility.

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In June 2014, we finalized the Arrow Acquisition purchase price allocation. The following table summarizes the final valuation of the assets acquired and liabilities assumed at the acquisition date (in millions):



Current assets	$	192.7
Property, plant and equipment	400.5
Intangible assets	323.4
Other assets	19.5
Total identifiable assets acquired	936.1

Current liabilities	215.8
Assets retirement obligations	1.2
Other long-term liabilities	3.7
Total liabilities assumed	220.7

Net identifiable assets acquired	715.4
Goodwill	45.9
Net assets acquired	$	761.3

The $45.9 million of goodwill is reflected in our gathering and processing segment. Goodwill recognized related primarily to anticipated operating synergies between the assets acquired and our existing assets. During the year ended December 31, 2013, we recognized $218.8 million of operating revenues and $1.7 million of operating income related to this acquisition. Transaction costs related to the Arrow Acquisition were approximately $5.4 million and $1.2 million, for the years ended December 31, 2014 and 2013. These costs are included in general and administrative expenses in our consolidated statements of operations.

Unaudited Pro Forma Information

The following table presents unaudited pro forma consolidated revenues, net income and net income per limited partner unit as if the reverse mergers and the Arrow Acquisition had been included in our consolidated results for the entire year ended December 31, 2013 (in millions, except per unit information).



	CEQP		CMLP
Revenues	$	3,449.3	$	3,423.8
Net income (loss)	$	3.9	$	(5.0	)

Net income per limited partner unit:
Basic	$	0.40
Diluted	$	0.40

These amounts have been calculated after applying our accounting policies and adjusting the results of the acquisitions to reflect the depreciation and amortization based on the estimated fair value adjustments to property, plant and equipment and intangible assets.

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Note 4 – Certain Balance Sheet Information

Property, Plant and Equipment

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



	CEQP				CMLP
	December 31,				December 31,
	2015		2014		2015		2014
Gathering systems and pipelines	$	1,070.4	$	1,410.9	$	1,213.2	$	1,279.5
Facilities and equipment	1,505.9		1,648.3		1,691.0		1,653.8
Buildings, land, rights-of-way, storage contracts and easements	833.4		841.5		837.1		840.0
Vehicles	46.3		45.2		44.6		43.5
Construction in process	114.5		156.5		114.5		156.5
Base gas	37.3		37.5		37.3		37.5
Salt deposits	120.5		120.5		120.5		120.5
Office furniture and fixtures	19.4		13.5		19.5		13.3
	3,747.7		4,273.9		4,077.7		4,144.6
Less: accumulated depreciation and depletion	436.9		380.1		552.0		398.6
Total property, plant and equipment, net	$	3,310.8	$	3,893.8	$	3,525.7	$	3,746.0

Depreciation. CEQP's depreciation expense totaled $195.1 million, $184.2 million and $109.9 million for the years ended December 31, 2015, 2014 and 2013. CMLP's depreciation expense totaled $186.7 million, $170.9 million and $99.9 million for the years ended December 31, 2015, 2014 and 2013. Depletion expense at both CEQP and CMLP totaled $0.7 million, $0.7 million and $0.4 million for the years ended December 31, 2015, 2014 and 2013.

Capitalized Interest. During the year ended December 31, 2015, 2014 and 2013 CEQP capitalized interest of $2.5 million, $7.7 million and $3.4 million related to certain expansion projects. During the year ended December 31, 2015, 2014 and 2013 CMLP capitalized interest of $2.5 million, $7.5 million and $3.4 million related to certain expansion projects.

Capital Leases. We have a treating facility and certain auto leases which are accounted for as capital leases. Our treating facility lease is reflected in facilities and equipment in the above table. We had capital lease assets of $2.4 million and $5.3 million included in property, plant and equipment, net at December 31, 2015 and 2014.

Intangible Assets

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



	CEQP				CMLP
	December 31,				December 31,
	2015		2014		2015		2014
Customer accounts	$	583.7	$	583.7	$	583.7	$	583.7
Covenants not to compete	6.6		9.6		5.6		8.6
Gas gathering, compression and processing contracts	325.2		730.2		325.2		431.4
Acquired storage contracts	29.0		29.0		29.0		29.0
Trademarks	31.3		32.2		15.8		16.7
Deferred financing costs	63.3		57.2		63.3		54.3
	1,039.1		1,441.9		1,022.6		1,123.7
Less: accumulated amortization	229.0		210.6		220.3		154.1
Total intangible assets, net	$	810.1	$	1,231.3	$	802.3	$	969.6

The following table summarizes the total of accumulated amortization of intangible assets by the type of intangible asset at December 31, 2015 and 2014:

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	CEQP				CMLP
	December 31,				December 31,
	2015		2014		2015		2014
Customer accounts	$	130.1	$	72.5	$	130.1	$	72.5
Covenants not to compete	2.5		3.2		1.7		2.6
Gas gathering, compression and processing contracts	44.3		98.0		44.3		47.9
Acquired storage contracts	18.5		12.7		18.5		12.7
Trademarks	11.2		6.7		3.3		2.0
Deferred financing costs	22.4		17.5		22.4		16.4
Total accumulated amortization	$	229.0	$	210.6	$	220.3	$	154.1

Crestwood Equity's amortization and interest expense related to its intangible assets for the years ended December 31, 2015, 2014 and 2013, was approximately $114.0 million, $109.8 million and $66.7 million. Crestwood Midstream's amortization and interest expense related to its intangible assets for the years ended December 31, 2015, 2014 and 2013 was approximately $100.0 million, $92.1 million and $49.0 million.

Estimated amortization of our intangible assets for the next five years is as follows (in millions):



	CEQP		CMLP
Year Ending December 31,
2016	$	82.9	$	79.6
2017	69.8		66.7
2018	57.4		55.9
2019	53.8		53.8
2020	52.6		52.6

Accrued Expenses and Other Liabilities

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



	CEQP				CMLP
	December 31,				December 31,
	2015		2014		2015		2014
Accrued expenses	$	46.4	$	52.5	$	44.1	$	50.0
Accrued property taxes	4.8		2.2		4.8		2.2
Accrued product purchases payable	1.5		0.7		1.5		0.7
Tax payable	0.5		1.6		0.5		1.2
Interest payable	26.2		23.5		26.2		21.9
Accrued additions to property, plant and equipment	10.4		20.0		10.4		20.0
Commitments and contingent liabilities (Note 15)	—		40.0		—		40.0
Capital leases	1.6		1.9		1.6		1.9
Deferred revenue	14.2		12.2		14.2		12.2
Total accrued expenses and other liabilities	$	105.6	$	154.6	$	103.3	$	150.1

Note 5 - Asset Retirement Obligations

We have legal obligations associated with right-of-way contracts we hold and at our facilities whether owned or leased. 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, 2015 and 2014 (in millions):



	December 31,
	2015		2014
Net asset retirement obligation at January 1	$	23.8	$	15.1
Liabilities incurred	1.1		4.6
Acquisitions	—		1.2
Accretion expense	1.5		1.1
Changes in estimate	—		1.8
Net asset retirement obligation at December 31	$	26.4	$	23.8

We did not have any material assets that were legally restricted for use in settling asset retirement obligations as of December 31, 2015 and 2014.

Note 6 - Investments in Unconsolidated Affiliates

Net Investments and Earnings (Loss)



	Ownership Percentage			Investment				Earnings (Loss) from Unconsolidated Affiliates
	December 31,			December 31,				Year Ended December 31,
	2015			2015		2014		2015				2014			2013
Jackalope Gas Gathering Services, L.L.C.⁽¹⁾	50.00	%	⁽⁴⁾	$	202.4	$	232.9	$	(43.4	)	⁽⁵⁾	$	0.5		$	0.1
Tres Palacios Holdings LLC⁽²⁾	50.01	%		36.8		36.0		2.5				0.2			—
Powder River Basin Industrial Complex, LLC⁽³⁾	50.01	%		15.1		26.2		(19.9		)	⁽⁵⁾	(1.4		)	(0.2		)
Total				$	254.3	$	295.1	$	(60.8	)		$	(0.7	)	$	(0.1	)

(1)

As of December 31, 2015, our equity in the underlying net assets of Jackalope exceeded our investment balance by approximately $0.9 million. We amortize this amount over 20 years, which represents the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake), and we reflect the amortization as a reduction of our earnings from unconsolidated affiliates. We recorded amortization of approximately $3.0 million, $3.1 million and $1.4 million for the years ended December 31, 2015, 2014 and 2013.

(2)

As of December 31, 2015, our equity in the underlying net assets of Tres Holdings exceeded our investment balance by approximately $29.1 million. We amortize and generally assess the recoverability of this amount over the life of the Tres Palacios Gas Storage LLC (Tres Palacios) sublease agreement, and we reflect the amortization as an increase in our earnings from unconsolidated affiliates. We recorded amortization of approximately $1.3 million and $0.1 million for the years ended December 31, 2015 and 2014.

(3)

As of December 31, 2015, our equity in the underlying net assets of PRBIC exceeded our investment balance by approximately $23.4 million. We amortize this amount over the life of PRBIC's property, plant and equipment and its agreement with Chesapeake. During the three months ended June 30, 2015, we recorded additional equity earnings of approximately $3.2 million related to a gain associated with the adjustment of our member's capital account by our equity investee.


(4)	Excludes non-controlling interests related to our investment in Jackalope. See Note 12 for a further discussion of our non-controlling interest related to our investment in Jackalope.


(5)	During the year ended December 31, 2015, we recorded impairments of our Jackalope and PRBIC equity investments of approximately $51.4 million and $23.4 million. For a further discussion of these impairments, see Note 2.

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Description of Investments

Jackalope. In July 2013, Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, acquired its 50% ownership interest in Jackalope for approximately $107.5 million. Williams Partners LP operates and owns the remaining 50% interest in Jackalope. Crestwood Niobrara manages the commercial operations of the Jackalope system, and we account for our investment in Jackalope under the equity method of accounting. Our Jackalope investment is included in our gathering and processing segment.

We entered into a construction agreement with Jackalope, pursuant to which we assumed the responsibility to construct a truck terminal and storage facility. Under this agreement, Jackalope reimburses us for all costs incurred on its behalf, therefore, no revenues are recognized under this agreement.

Tres Palacios Holdings LLC

In December 2014, CEQP sold its 100% interest in Tres Palacios to Tres Holdings, a newly formed joint venture between Crestwood Midstream's consolidated subsidiary and an affiliate of Brookfield, for total cash consideration of approximately $132.8 million, of which $66.4 million was paid by Crestwood Midstream. As a result of this transaction, effective December 1, 2014, CEQP deconsolidated the operations of Tres Palacios. Crestwood Midstream owns 50.01% of Tres Holdings and is the operator of Tres Palacios and its assets. Brookfield owns the remaining 49.99% interest in Tres Holdings. We account for our investment in Tres Holdings under the equity method of accounting, and the investment is included in our storage and transportation segment.

The sale of CEQP's 100% interest in Tres Palacios was accounted for under the accounting standards related to in substance real estate transactions. The accounting for the sale of real estate results in the recognition of a gain to the extent the sale is to an independent buyer. Since CEQP retained 50.01% of its interest in Tres Palacios through its ownership in Crestwood Midstream, CEQP recognized only the portion of the gain related to sale to Brookfield of approximately $30.6 million and, as a result, no gain was recognized on the portion of the sale between Crestwood Midstream and CEQP. The sale of CEQP's interest in Tres Palacios to Crestwood Midstream was considered a transaction between entities under common control and, as a result, Crestwood Midstream reflected its investment at approximately $35.8 million, which represented 50.01% of CEQP's historical basis in Tres Palacios.

Tres Palacios owns a FERC-certificated 38.4 Bcf multi-cycle, salt dome natural gas storage facility. Its 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 10 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan Inc.'s Houston central processing plant.

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. During the years ended December 31, 2015 and 2014, Tres Palacios reimbursed us approximately $2.8 million and $0.2 million under this agreement. These reimbursements are reflected as a reduction of operations and maintenance expense in our consolidated statements of operations. In addition to our operating agreement, CEQP also entered into an indemnification agreement with Tres Palacios to indemnify Tres Palacios for property tax liabilities associated with periods prior to the sale. Pursuant to the indemnification agreement, any property tax refunds received by Tres Palacios will be payable to CEQP.

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. Our PRBIC investment is included in our storage and transportation segment.

In September 2013, Crude Logistics and Enserco Midstream, LLC formed PRBIC to construct, own and operate an integrated crude oil loading, storage and pipeline terminal located in Douglas County, Wyoming. The terminal was placed in manifest service in August 2013 and unit train in service in May 2014. Crude Logistics paid approximately $22.5 million to acquire its interest in PRBIC.

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Distributions and Contributions

Jackalope. Jackalope is required, within 30 days following the end of each quarter, to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the year ended December 31, 2015 we received cash distributions of approximately $12.5 million from Jackalope. During the year ended December 31, 2014, Jackalope did not make any distributions to its members. In February 2016, we received a cash distribution of approximately $5.1 million from Jackalope. During the years ended December 31, 2015 and 2014, we contributed approximately $25.4 million and $105.2 million to Jackalope.

Tres Holdings. Tres Holdings is required, within 30 days following the end of each quarter, to make quarterly distributions of its available cash (as defined in its limited liability company agreement) to its members based on their respective ownership percentage. During the year ended December 31, 2015, we received cash distributions of approximately $7.4 million from Tres Holdings. During the year ended December 31, 2015, we contributed approximately $5.7 million to Tres Holdings.

PRBIC. PRBIC is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the year ended December 31, 2015, we received cash distributions of approximately $1.9 million from PRBIC. During the year ended December 31, 2014, PRBIC did not make any distributions to its members. In January 2016, we received a cash distribution of approximately $0.6 million from PRBIC. During the years ended December 31, 2015 and 2014, Crude Logistics contributed approximately $10.7 million and $3.4 million to PRBIC.

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. We also periodically utilize derivative instruments to manage our exposure to fluctuations in interest rates, which is discussed in Note 9. 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 to energy related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of NGLs, heating oil and crude oil. We will periodically enter into offsetting positions to economically hedge against the exposure our customer contracts create. Certain of these contracts and positions are derivative instruments. We do not designate any of our commodity-based derivatives as hedging instruments for accounting purposes. Our commodity-based derivatives are reflected at fair value in the consolidated balance sheets, and changes in the fair value of these derivatives that impact the consolidated statements of operations are reflected in costs of product/services sold. During the years ended December 31, 2015, 2014 and 2013, the impact to the statement of operations related to our commodity-based derivatives reflected in costs of product/services sold was a gain of $18.9 million, a gain of $51.2 million and a loss of $11.2 million. We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. This balance in the contractual portfolio significantly reduces the volatility in costs of product/services sold related to these instruments.

Commodity Price and Credit Risk

Notional Amounts and Terms

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



	December 31, 2015		December 31, 2014
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	9.1	10.9	6.8	8.4
Natural gas (MMBTU’s)	—	—	0.2	0.1

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

All contracts subject to price risk had a maturity of 36 months or less; however, 84% of the contracts expire within 12 months.

Credit Risk

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, 2015 and 2014, was $3.3 million and $5.2 million. At December 31, 2014 we posted $1.8 million of collateral in the normal course of business. We did not post collateral at December 31, 2015 for our commodity derivative instruments with credit-risk-related contingent features. In addition, at December 31, 2015 and 2014, we had a New York Mercantile Exchange (NYMEX) related net derivative liability position of $20.8 million and $36.9 million, for which we posted $26.7 million and $41.9 million of cash collateral in the normal course of business. At December 31, 2015 and 2014, we also received collateral of $16.8 million and $33.6 million in the normal course of business. All collateral amounts have been netted against the asset or liability with the respective counterparty and is reflected in our consolidated balance sheets as assets and liability 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 physical exchanges and interest rate swaps.


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

Credit Facilities

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

Senior Notes

We estimate the fair value of our senior notes primarily based on quoted market prices for the same or similar issuances (representing a Level 2 fair value measurement). The following table reflects the carrying value and fair value of the senior notes (in millions):



	December 31, 2015				December 31, 2014
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
CEQP Senior Notes	$	—	$	—	$	11.4	$	11.6
Crestwood Midstream 2019 Senior Notes	$	—	$	—	$	351.0	$	360.5
Crestwood Midstream 2020 Senior Notes	$	503.3	$	382.3	$	504.0	$	481.6
Crestwood Midstream 2022 Senior Notes	$	600.0	$	437.4	$	600.0	$	568.5
Crestwood Midstream 2023 Senior Notes	$	700.0	$	491.8	$	—	$	—

Financial Assets and Liabilities

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

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

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

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

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

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



	December 31, 2015
	Fair Value of Derivatives
	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	$	0.5	$	57.8	$	—	$	58.3	$	(13.7	)	$	(12.0	)	$	32.6
Suburban Propane Partners, L.P. units⁽²⁾	3.4		—		—		3.4		—			—			3.4
Total assets at fair value	$	3.9	$	57.8	$	—	$	61.7	$	(13.7	)	$	(12.0	)	$	36.0

Liabilities
Liabilities from price risk management	$	0.2	$	41.3	$	—	$	41.5	$	(13.7	)	$	(20.4	)	$	7.4
Total liabilities at fair value	$	0.2	$	41.3	$	—	$	41.5	$	(13.7	)	$	(20.4	)	$	7.4

	December 31, 2014
	Fair Value of Derivatives
	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	$	0.5	$	146.7	$	—	$	147.2	$	(28.8	)	$	(38.6	)	$	79.8
Suburban Propane Partners, L.P. units⁽²⁾	6.1		—		—		6.1		—			—			6.1
Total assets at fair value	$	6.6	$	146.7	$	—	$	153.3	$	(28.8	)	$	(38.6	)	$	85.9

Liabilities
Liabilities from price risk management	$	1.6	$	99.2	$	—	$	100.8	$	(28.8	)	$	(46.6	)	$	25.4
Interest rate swaps⁽³⁾	—		1.6		—		1.6		—			—			1.6
Total liabilities at fair value	$	1.6	$	100.8	$	—	$	102.4	$	(28.8	)	$	(46.6	)	$	27.0


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


(2)	Amount is reflected in other assets on the Crestwood Equity Partners LP consolidated balance sheet.


(3)	Our interest rate swaps are only reflected in the consolidated results of Crestwood Equity. See Note 9 for a further discussion of our interest rate swaps.

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Note 9 – Long-Term Debt

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



	December 31, 2015		December 31, 2014
CMLP Credit Facility	$	735.0	$	555.0
Crestwood Midstream 2019 Senior Notes	—		350.0
Premium on Crestwood Midstream 2019 Senior Notes	—		1.0
Crestwood Midstream 2020 Senior Notes	500.0		500.0
Fair value adjustment of Crestwood Midstream 2020 Senior Notes	3.3		4.0
Crestwood Midstream 2022 Senior Notes	600.0		600.0
Crestwood Midstream 2023 Senior Notes	700.0		—
Other	5.3		5.3
Total Crestwood Midstream debt	2,543.6		2,015.3
CEQP Credit Facility	—		369.0
CEQP Senior Notes	—		11.4
Other	0.2		0.8
Total Crestwood Equity debt	2,543.8		2,396.5
Less: current portion	1.1		3.7
Total long-term debt, less current portion	$	2,542.7	$	2,392.8

Crestwood Equity Long-Term Debt

CEQP Credit Facility. Prior to the completion of the Simplification Merger, we utilized a secured credit facility (the CEQP Credit Facility) with an aggregate revolving loan capacity of $495.0 million to fund working capital requirements, capital expenditures and acquisitions and for general partnership purposes. All borrowings under the CEQP Credit Facility, which would have expired in July 2016, were generally secured by substantially all of our assets and the equity interests in all of our wholly-owned subsidiaries.

In conjunction with the closing of the Simplification Merger, we terminated the CEQP Credit Facility, repaid all borrowings and retired all standby letters of credit outstanding under the facility. We recognized a loss on extinguishment of debt of approximately $0.9 million in conjunction with the termination of the CEQP Credit Facility. At December 31, 2014, our outstanding standby letters of credit were $56.7 million. The interest rates on the CEQP Credit Facility were based on the prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 2.91% and 5.00% at December 31, 2014. The weighted-average interest rate as of December 31, 2014 was 3.02%.

CEQP Interest Rate Swaps. We entered into interest rate swaps to reduce our exposure to variable interest payments due under the CEQP Credit Facility. These swap agreements required us to make quarterly payments to the counterparty on an aggregate notional amount based on fixed rates. In exchange, the counterparty was required to make quarterly floating interest rate payments on the same date to us based on the three-month LIBOR applied to the same aggregate notional amount. In February 2015, five of our interest rate swaps matured, with an aggregate notional amount of $175.0 million and fixed rates ranging from 0.84% to 2.35%. In conjunction with the completion of the Simplification Merger, we terminated and settled amounts outstanding under our remaining swaps which would have matured in 2016. During the years ended December 31, 2015, 2014 and 2013, we recorded a gain of approximately $0.5 million, $2.7 million and $1.7 million associated with these interest rate swaps. We reflected these gains as a reduction of our interest and debt expense, net on our consolidated statements of operations.

CEQP Senior Notes

During the year ended December 31, 2015, we repaid the balance outstanding under our senior notes, the majority of which were scheduled to mature on October 1, 2018. We recognized a loss on extinguishment of debt of approximately $0.2 million for the year ended December 31, 2015 in conjunction with the redemption of our senior notes.

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Crestwood Midstream Long-Term Debt

CMLP Credit Facility. Contemporaneously with the closing of the Simplification Merger on September 30, 2015, Crestwood Midstream amended and restated its senior secured credit agreement (the CMLP 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 LLC (Crestwood Niobrara), PRBIC 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, Crestwood Midstream had a five-year $1.0 billion senior secured revolving credit facility, which would have expired October 2018. We recognized a loss on extinguishment of debt of approximately $1.8 million 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, 2015, the balance outstanding under the CMLP Credit Facility was $735.0 million and its outstanding standby letters of credit were $62.2 million. At December 31, 2015, Crestwood Midstream had $399.0 million of available capacity under the CMLP Credit Facility considering the most restrictive debt covenants in its credit agreement. Borrowings under the CMLP Credit Facility accrue interest at prime or Eurodollar based rates plus applicable spreads, which resulted in interest rates between 2.70% and 5.00% at December 31, 2015. The weighted-average interest rate as of December 31, 2015 was 2.70%. At December 31, 2014, the balance outstanding under the Crestwood Midstream $1.0 billion credit facility was $555.0 million and its outstanding letters of credit were $15.1 million. Borrowings under the $1.0 billion credit facility accrued interest at prime or LIBOR-based rates plus applicable spreads, which resulted in interest rates between 2.66% and 4.75% at December 31, 2014. The weighted-average interest rate as of December 31, 2014 was 2.86%.

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.

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

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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, 2015, the net debt to consolidated EBITDA was approximately 4.75 to 1.0, the consolidated EBITDA to consolidated interest expense was approximately 3.99 to 1.0, and the senior secured leverage ratio was 1.37 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.

Crestwood Midstream Senior Notes

2019 Senior Notes. The $350 million 7.75% Senior Notes due 2019 (the 2019 Senior Notes) were scheduled to mature on April 1, 2019, and interest was payable semi-annually in arrears on April 1 and October 1 of each year. On April 8, 2015, Crestwood Midstream redeemed its 2019 Senior Notes for approximately $364.1 million, including accrued interest of $0.5 million and a call premium of $13.6 million. Crestwood Midstream utilized approximately $315 million of its $1.0 billion credit facility to redeem all of its outstanding 2019 Senior Notes. In conjunction with the redemption of the 2019 Senior Notes, Crestwood Midstream recorded a loss on extinguishment of debt of approximately $17.1 million.

2020 Senior Notes. The $500 million 6.0% Senior Notes due 2020 (the 2020 Senior Notes) mature on December 15, 2020, and interest is payable semi-annually in arrears on June 15 and December 15 of each year. We recorded an adjustment in conjunction with Legacy Crestwood GP's reverse acquisition of us to adjust the debt to fair value. The adjustment is being amortized over the remaining life of the 2020 Senior Notes.

2022 Senior Notes. In November 2013, Crestwood Midstream completed an offering of $600 million in aggregate principal amount of 6.125% Senior Notes due 2022 (the 2022 Senior Notes) in a private offering exempt from registration requirements of the Securities Act of 1933. The 2022 Senior Notes mature on March 1, 2022, and interest is payable semi-annually on March 1 and September 1 of each year.

On July 17, 2014, Crestwood Midstream filed a registration statement with the SEC under which it offered to exchange the 2022 Senior Notes for any and all outstanding 2022 Senior Notes. Crestwood Midstream completed the exchange offer on August 29, 2014. The terms of the exchange notes are substantially identical to the terms of the 2022 Senior Notes, except that the exchange notes are freely tradable.

2023 Senior Notes. In March 2015, Crestwood Midstream issued $700 million of 6.25% unsecured senior notes due 2023 (the 2023 Senior Notes) in a private offering. The 2023 Senior Notes will mature on April 1, 2023, and interest is payable semi-annually in arrears on April 1 and October 1 of each year, beginning October 1, 2015. The net proceeds from this offering of approximately $688.3 million were used to pay down borrowings under the Crestwood Midstream $1.0 billion credit facility and for Crestwood Midstream's general partnership purposes.

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 Crestwood Midstream Revolver.

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

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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, 2015, 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 $2,981.6 million as of December 31, 2015.

Notes Payable and Other Obligations

CEQP's non-interest bearing obligations due under noncompetition agreements and other note payable agreements consisted of agreements between Legacy Inergy and the sellers of certain companies acquired from 2003 through 2014 with payments due through 2027 and imputed interest ranging from 5.02% to 8.00%. At December 31, 2015 and 2014, CEQP's non-interest bearing obligations consisted of $6.8 million and $7.4 million in total payments due under agreements, less unamortized discount based on imputed interest of $1.3 million in both periods.

CMLP's non-interest bearing obligations due under noncompetition agreements consisted of agreements between Crestwood Midstream and sellers of certain companies acquired in 2014 with payments due through 2027 and imputed interest ranging from 5.02% to 8.00%. Non-interest bearing obligations consisted of $6.6 million and $6.5 million in total payments due under agreements, less unamortized discount based on imputed interest of $1.3 million and $1.2 million at December 31, 2015 and 2014, respectively.

Maturities

The aggregate maturities of principal amounts on our outstanding long-term debt and other notes payable as of December 31, 2015 for the next five years and in total thereafter are as follows (in millions):



	CEQP		CMLP
2016	$	1.1	$	0.9
2017	1.0		1.0
2018	1.0		1.0
2019	1.1		1.1
2020	1,238.6		1,238.6
Thereafter	1,301.0		1,301.0
Total debt	$	2,543.8	$	2,543.6

Residual Value Guarantee

In August 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 directly to, or to 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 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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Note 10 - Earnings Per Limited Partner Unit

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. The accounting standards related to earnings per share requires an entity to 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 adjusted to reflect the 1-for-10 reverse split.

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 Class A 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 year ended December 31, 2015, we excluded a weighted-average of 1,547,060 common units (representing preferred units), a weighted-average of 438,789 common units (representing subordinated units), and a weighted-average of 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.

Note 11 - Income Taxes

The provision (benefit) for income taxes for the years ended December 31, 2015, 2014, and 2013 consisted of the following (in millions):



	CEQP									CMLP
	Year Ended December 31,									Year Ended December 31,
	2015			2014			2013			2015			2014		2013
Current:
Federal	$	1.6		$	5.0		$	2.5		$	—		$	—	$	—
State	0.6			1.3			1.3			0.3			0.2		0.7
Total current	2.2			6.3			3.8			0.3			0.2		0.7
Deferred:
Federal	(2.9		)	(5.3		)	(2.5		)	—			—		—
State	(0.7		)	0.1			(0.3		)	(0.3		)	0.7		—
Total deferred	(3.6		)	(5.2		)	(2.8		)	(0.3		)	0.7		—
Provision (benefit) for income taxes	$	(1.4	)	$	1.1		$	1.0		$	—		$	0.9	$	0.7

The effective rate differs from the statutory rate for the years ended December 31, 2015 and 2014, 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.

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Components of our deferred income taxes at December 31, 2015 and 2014 are as follows (in millions).



	CEQP						CMLP
	December 31,						December 31,
	2015			2014			2015			2014
Deferred tax asset:
Basis difference in stock of company	$	0.5		$	—		$	—		$	—
Total deferred tax asset	0.5			—			—			—
Deferred tax liability:
Basis difference in stock of acquired company	(8.9		)	(12.0		)	(0.4		)	(0.7		)
Total deferred tax liability	(8.9		)	(12.0		)	(0.4		)	(0.7		)
Net deferred tax liability	$	(8.4	)	$	(12.0	)	$	(0.4	)	$	(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. Tax positions with respect to tax at the partnership level deemed not to meet the more likely than not threshold 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 operations for the years ended December 31, 2015, 2014 and 2013 and that no provision for income tax was required for these consolidated financial statements. However, our conclusions regarding the evaluation are subject to review and may change based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof.

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.

Immediately following the Simplification Merger and the transactions described above, as of December 31, 2015, CEQP owns a 99.9% limited partnership interest in Crestwood Midstream and CEQP's wholly-owned subsidiary, CGS GP, owns a 0.1% limited partnership interest in Crestwood Midstream.

Common Units

Historically, Crestwood Midstream periodically sold common units in public offerings to generate funds to reduce the indebtedness under its credit facility and to fund acquisitions. The table below presents limited partner unit issuances by Legacy Crestwood, Inergy Midstream and Crestwood Midstream.



Issuer	Issuance Date	Units		Per Unit Gross Price	Per Unit Net Price ⁽¹⁾	Net Proceeds (in millions)
Legacy Crestwood	March 22, 2013	5,175,000	⁽²⁾	23.90	23.00	118.5
Inergy Midstream	September 13, 2013	11,773,191	⁽³⁾	22.50	21.69	255.2
Crestwood Midstream	October 23, 2013	16,100,000	⁽⁴⁾	N/A	21.19	340.3


(1)	Price is net of underwriting discounts.


(2)	Includes 675,000 units that were issued in April 2013.


(3)	Includes 773,191 units that were issued on October 7, 2013.


(4)	Includes 2,100,000 units that were issued on October 30, 2013.

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During 2013, Legacy Crestwood issued Class D units representing limited partner units. Legacy Crestwood had the option to pay distributions to its Class D unitholders with cash or by issuing additional paid-in-kind units based upon the volume common unit weighted-average price for 10 trading days immediately preceding the date the distribution was declared. On April 1, 2013, the outstanding Legacy Crestwood Class C units converted to common units on a one-for-one basis. In conjunction with the Crestwood Merger, Legacy Crestwood unitholders received 1.07 units of Inergy Midstream units for each unit of Legacy Crestwood they owned and as a result, there were no common or Class D units outstanding immediately following the Crestwood Merger. During 2013, Legacy Crestwood issued 183,995 and 292,660 additional Class C and Class D units in lieu of paying a quarterly cash distribution.

Preferred Units

On June 17, 2014, Crestwood Midstream entered into definitive agreements with a group of investors, including Magnetar Financial, affiliates of GSO Capital Partners LP and GE Energy Financial Services (the Class A Purchasers). Under these agreements, Crestwood Midstream agreed to sell to the Class A Purchasers and the Class A Purchasers have agreed to purchase from Crestwood Midstream up to $500 million of Class A Preferred Units (CMLP Preferred Units) at a fixed price of $25.10 per unit on or before September 30, 2015. Through December 31, 2014, the Class A Purchasers purchased 17,529,879 CMLP Preferred Units for a cash purchase price of $25.10 per unit resulting in gross proceeds to us of approximately $440.0 million (net proceeds of approximately $430.5 million after deducting transaction fees and offering expenses). On August 10, 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 Crestwood Equity Partners LP partners' capital on its consolidated balance sheet as of December 31, 2015. Prior to the Simplification Merger, Crestwood Equity classified the CMLP Preferred Units as a component of Interest of Non-Controlling Partners on its consolidated balance sheet. 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 after June 17, 2017, or (ii) a number of common units determined pursuant to a conversion ratio set forth in our partnership agreement upon the occurrence of certain events, such as a change in control. 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.

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. Working capital borrowings are generally borrowings that are made under CEQP's working capital facility and in all cases are used solely for working capital purposes or to pay distributions to partners. The amount of

149

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. During the year ended December 31, 2013, Legacy Crestwood GP paid cash distributions to its member of $9.3 million. In addition, during the year ended December 31, 2013, CEQP paid cash distributions of approximately $11.8 million related to restricted units that vested as a result of the Crestwood Merger discussed below.

A summary of CEQP's limited partner quarterly cash distributions for the years ended December 31, 2015, 2014 and 2013 is presented below:



Record Date	Payment Date	Per Unit Rate		Cash Distributions (in millions)
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

2014
February 7, 2014	February 14, 2014	$	1.375	$	25.6
May 8, 2014	May 15, 2014	$	1.375	25.7
August 7, 2014	August 14, 2014	$	1.375	25.6
November 7, 2014	November 14, 2014	$	1.375	25.6
				$	102.5

2013
August 7, 2013	August 14, 2013	$	1.30	$	22.3
November 7, 2013	November 14, 2013	$	1.35	25.0
				$	47.3

On February 12, 2016, we paid a distribution of $1.3750 per limited partner unit to unitholders of record on February 5, 2016 with respect to the fourth quarter of 2015.

Preferred Unit Holders. We are required to make quarterly distributions to our Preferred Unit holders. The holders of the Preferred Units are entitled to receive fixed quarterly distributions of $0.2111 per unit. For the seven quarters following the quarter ended September 30, 2015 (the Initial Distribution Period), distributions on the Preferred Units can be made in additional Preferred Units, cash, or a combination thereof, at our election. If we elect to pay the quarterly distribution through the issuance of additional Preferred Units, the number of units to be distributed will be calculated as the fixed quarterly distribution of $0.2111 per unit divided by the cash purchase price of $9.13 per unit. We accrue the fair value of such distribution at the end of the quarterly period and adjust the fair value of the distribution on the date the additional Preferred Units are distributed. Distributions on the Preferred Units following the Initial Distribution Period will be made in cash unless, subject to certain exceptions, (i) there is no distribution being paid on 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 its partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

During the year ended December 31, 2015, we issued 1,372,573 Preferred Units to our preferred unit holders in lieu of paying a quarterly cash distribution of $12.5 million. On February 12, 2016, we issued 1,404,317 Preferred Units to our preferred unit holders for the quarter ended December 31, 2015 in lieu of paying a cash distribution of $12.8 million.

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Crestwood Midstream

Description. Prior to the Crestwood Merger, Legacy Crestwood’s Second Amended and Restated Agreement of Limited Partnership, dated February 19, 2008, as amended (Legacy Crestwood Partnership Agreement), required that, within 45 days after the end of each quarter, they distribute all of their available cash (as defined therein) to unitholders of record on the applicable record date, as determined by its general partner. Legacy Crestwood’s minimum quarterly distribution was $0.30 per unit, to the extent they had sufficient cash flows from operations after the establishment of cash reserve and payment of fees and expenses, including payments to its general partner.

Following the Crestwood Merger and 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 years ended December 31, 2015, 2014 and 2013, 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, $41.8 million and $26.2 million.

On September 30, 2015, Crestwood Midstream made a distribution of approximately $378.3 million to CEQP for purposes of repaying (or, if applicable, satisfying and discharging) substantially all of its outstanding indebtedness. The distribution was funded with borrowings under the Crestwood Midstream credit facility. In addition, during the years ended December 31, 2015, 2014 and 2013, Crestwood Midstream made distributions of $175.6 million, $101.6 million and $50.0 million, which represented net amounts due to Crestwood Midstream related to cash advances to CEQP for its general corporate activities.

As discussed in Note 6, in December 2014, Crestwood Midstream paid approximately $66.4 million to acquire a 50.01% in Tres Palacios from Crestwood Equity. Crestwood Midstream reflected the difference between the cash paid in excess of Crestwood Equity's basis of approximately $30.6 million as a distribution to its general partner on its consolidated statement of partners' capital and its consolidated statement of cash flows for the year ended December 31, 2014.

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 years ended December 31, 2015, 2014 and 2013.

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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
2014
February 7, 2014	February 14, 2014	$	0.41	$	74.1
May 8, 2014	May 15, 2014	$	0.41	74.2
August 7, 2014	August 14, 2014	$	0.41	74.1
November 7, 2014	November 14, 2014	$	0.41	74.1
				$	296.5
2013
January 31, 2013	February 12, 2013	$	0.510	$	21.0
April 30, 2013	May 10, 2013	$	0.510	27.4
August 1, 2013	August 9, 2013	$	0.510	27.4
August 7, 2013(1)	August 14, 2013	$	0.400	34.3
November 7, 2013(1)	November 14, 2013	$	0.405	69.5
				$	179.6


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

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 on its consolidated balance sheet.

Crestwood Niobrara Preferred Interest

Crestwood Niobrara issued a preferred interest to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE) in conjunction with the acquisition of its investment in Jackalope. The preferred interest is reflected as non-controlling interest in Crestwood Equity's and Crestwood Midstream's consolidated financial statements. We serve as the managing member of Crestwood Niobrara and, subject to certain restrictions, we have the ability to redeem GE's preferred interest in either cash or common units at an amount equal to the face amount of the preferred units plus an applicable return.

Pursuant to Crestwood Niobrara's agreement with GE, GE made capital contributions to Crestwood Niobrara in exchange for an equivalent number of preferred units. During the years ended December 31, 2014 and 2013, GE made capital contributions of $53.9 million and $96.1 million to Crestwood Niobrara. As of December 31, 2014, GE has fulfilled its capital contribution commitment to Crestwood Niobrara of $150.0 million and is no longer required to make quarterly contributions to Crestwood Niobrara.

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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, 2015, 2014 and 2013 are as follows (in millions):



	Year Ended December 31,
	2015			2014			2013
Crestwood Niobrara preferred interests	$	23.1		$	16.8		$	4.9
CMLP net income attributable to non-controlling partners	23.1			16.8			4.9
Crestwood Midstream limited partner interests	(683.0		)	(100.8		)	(62.2		)
Crestwood Midstream Class A preferred units	23.1			17.2			—
CEQP net income (loss) attributable to non-controlling partners	$	(636.8	)	$	(66.8	)	$	(57.3	)

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 and distributions paid in conjunction with the Crestwood Merger as discussed below) of $222.9 million, $296.5 million and $179.6 million during the years ended December 31, 2015, 2014 and 2013.

Crestwood Midstream Class A Preferred Unitholders. During the years ended December 31, 2015 and 2014, Crestwood Midstream issued 1,271,935 and 387,991 Preferred Units to its preferred unitholders in lieu of paying a cash distribution of approximately $31.9 million and $9.7 million, respectively.

Crestwood Niobrara Preferred Unitholders. During the years ended December 31, 2014 and 2013, Crestwood Niobrara issued 11,419,241 and 2,161,657 preferred units to GE 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. 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. During the year ended December 31, 2015, Crestwood Niobrara paid cash distributions of $11.3 million to GE.

Other Partners' Capital Transactions

Crestwood Merger

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.

153

As discussed in Note 1, in conjunction with the Crestwood Merger, Legacy Crestwood unitholders received 1.07 units of Inergy Midstream units for each Legacy Crestwood unit they owned and as a result, there were no Legacy Crestwood common or Class D units outstanding immediately following the merger. In addition, Legacy Crestwood unitholders also received a $34.9 million distribution, $10 million of which was funded as a non-cash contribution from Crestwood Holdings and is reflected on Crestwood Equity's consolidated statements of partners’ capital as contribution from Crestwood Holding LLC for the year ended December 31, 2013. Crestwood Equity reflected the distribution of $34.9 million as distributions to non-controlling partners on its consolidated statements of partners’ capital for the year ended December 31, 2013. Crestwood Midstream reflected the $10 million non-cash contribution from Crestwood Holdings as contributions from general partner on its consolidated statement of partners' capital for the year ended December 31, 2013. In addition, Crestwood Midstream reflected the distribution of $34.9 million as distribution to partners on its consolidated statements of partners' capital for the year ended December 31, 2013.

In conjunction with the Crestwood Merger, the restricted units outstanding under the Legacy Inergy long-term incentive plan were modified to accelerate the vesting of certain outstanding awards on December 31, 2013. Crestwood Equity reflected the cash paid of approximately $11.8 million related to these vested units as distributions to partners on its consolidated statement of cash flows for the year ended December 31, 2013.

Following the closing of the Crestwood Merger, Crestwood Holdings exchanged 7,100,000 common units of CMLP for 14,300,000 common units of CEQP pursuant to an option obtained on June 19, 2013 when it acquired CEQP's general partner. This exchange resulted in a $182.3 million decrease to the interest of non-controlling partners and a $182.3 million increase to partners' capital on Crestwood Equity's consolidated statement of partners' capital for the year ended December 31, 2013.

Acquisitions

Crestwood Marcellus Midstream LLC (CMM). In January 2013, Crestwood Midstream acquired Crestwood Holdings 65% membership interest in CMM for approximately $258.0 million, which was funded through $129.0 million of borrowings under the Legacy Crestwood credit facility and the issuance of Class D and common units. The transaction was accounted for as a reorganization of entities under common control. The issuance of the Class D and common units were reflected as a distribution for additional interest in Crestwood Marcellus Midstream LLC in our consolidated statements of cash flows and partners' capital for the year ended December 31, 2013.

Arrow. On November 7, 2013, Crestwood Midstream issued 8,826,125 common units as partial consideration of the Arrow Acquisition. See Note 3 for additional information regarding the Arrow Acquisition.

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 and Crestwood Midstream's common unitholders and to provide an incentive for continuous employment. Long-term incentive compensation consist of grants of restricted and phantom units which vest based upon continued service. Prior to the completion of the Simplification Merger, Crestwood Midstream also granted incentive awards under is Long-term Incentive Plan (Crestwood Midstream LTIP). In conjunction with the closing of the Simplification Merger, the restricted and phantom common units granted under the Crestwood Midstream LTIP were converted into restricted and phantom units of CEQP with substantially the same terms considering the 2.75 to 1 exchange ratio.

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Crestwood LTIP

The following table summarizes information regarding restricted and phantom unit activity during the years ended December 31, 2015 and 2014. As discussed in Note 10, the board of directors of CEQP's general partner approved a 1-for-10 reverse split of our common units effective November 23, 2015. The restricted and phantom units in the table below have been recast to reflect the reverse split.



	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	49,354		$	139.60
Vested - restricted units	(44,993	)	$	139.70
Granted - restricted units	137,746		$	132.30
Forfeited	(10,519	)	$	137.30
Unvested - December 31, 2014	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

(1) We implemented a company-wide initiative to reduce operating costs in 2015 and beyond, which included a reduction in work force. As a result, 7,263

restricted units were forfeited during the year ended December 31, 2015.

As of December 31, 2015 and 2014, we had total unamortized compensation expense of approximately $16.5 million and $8.1 million related to restricted and phantom units, which we expect will be amortized during the next three years (or sooner in certain cases, which generally represents the original vesting period of these instruments), except for grants to non-employee directors of our general partner, which vest over one year. We recognized compensation expense of approximately $11.5 million, $10.1 million and $10.9 million under the Crestwood LTIP during the years ended December 31, 2015, 2014 and 2013, which is included in general and administrative expenses on our consolidated statements of operations. As of February 12, 2016, we had 5,978,939 units available for issuance under the Crestwood LTIP.

Crestwood Restricted Units. Under the Crestwood LTIP, participants who have been granted restricted units may elect to have us withhold common units to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-vested common units. Any such common units withheld are returned to the Crestwood LTIP on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When we withhold these common units, we are required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. During the years ended December 31, 2015 and 2014, we withheld 26,095 and 15,944 common units to satisfy employee tax withholding obligations.

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

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Crestwood Midstream

The following table summarizes information regarding restricted and phantom unit activity during the years ended December 31, 2015 and 2014:



	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	250,557		$	22.13
Vested - restricted units	(208,361	)	$	22.15
Granted - restricted units	871,078		$	23.25
Forfeited	(78,478	)	$	23.33
Unvested - December 31, 2014	834,796		$	23.18
Vested - restricted units	(457,458	)	$	22.91
Vested - phantom units	(21,578	)	$	16.05
Granted - restricted units	535,858		$	15.89
Granted - phantom units	171,648		$	15.76
Modification - restricted units	(823,277	)	$	20.06
Modification - phantom units	(150,070	)	$	18.93
Forfeited⁽¹⁾	(89,919	)	$	16.05
Unvested - December 31, 2015	—		$	—


(1)	We implemented a company-wide initiative to reduce operating costs in 2015 and beyond, which included a reduction in work force. As a result, 39,172

restricted units were forfeited during the year ended December 31, 2015.

As of December 31, 2014, we had total unamortized compensation expense of approximately $9.5 million related to restricted and phantom units issued under the Crestwood Midstream LTIP. Crestwood Midstream recognized compensation expense of approximately $8.1 million, $11.2 million and $11.4 million (including $6.5 million recognized by Legacy Crestwood in 2013 as discussed below) during the years ended December 31, 2015, 2014 and 2013, which is included in general and administrative expenses on our consolidated statements of operations. As of December 31, 2015, we do not have any issued, outstanding units available for issuance under the Crestwood Midstream LTIP.

Crestwood Midstream Restricted Units. Under the Crestwood Midstream LTIP, participants who have been granted restricted units may elect to have common units withheld to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-vested common units. Any such common units withheld were returned to the Crestwood Midstream LTIP on the applicable vesting dates, which corresponded to the times at which income was recognized by the employee. When such common units are withheld, Crestwood Midstream was 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 was determined based on the closing price per common unit as reported on the NYSE on such dates. During the years ended December 31, 2015 and 2014, Crestwood Midstream withheld 139,331 and 71,484 common units to satisfy employee tax withholding obligations.

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

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Crestwood Midstream Employee Unit Purchase Plan

Crestwood Midstream had an employee unit purchase plan under which employees of the general partner purchased Crestwood Midstream's common units through payroll deductions up to a maximum of 10% of the employees' eligible compensation. Under the plan, Crestwood Midstream purchased its common units on the open market for the benefit of participating employees based on their payroll deductions. In addition, Crestwood Midstream could contribute an additional 10% of participating employees' payroll deductions to purchase additional Crestwood Midstream common units for participating employees. Unless increased by the board of directors of Crestwood Midstream's general partner, the maximum number of units that were available for purchase under the plan was 200,000. Effective May 7, 2015, Crestwood Midstream suspended the employee unit purchase plan. In conjunction with the Simplification Merger, all common units purchased through the

employee purchase plan were converted into common units of CEQP.

Legacy Crestwood

Prior to the Crestwood Merger, Legacy Crestwood issued phantom units under its Fourth Amended and Restated 2007 Equity Plan (2007 Equity Plan). The 2007 Equity Plan was terminated in conjunction with the Crestwood Merger. Crestwood Midstream recognized compensation expense under the 2007 Equity Plan of approximately $6.5 million for the year ended December 31, 2013.

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 2015 and $17,500 in 2014 and 2013. 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 $0.5 million during the years ended December 31, 2015, 2014 and 2013.

Note 15 – Commitments and Contingencies

Legal Proceedings

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

In March 2014, the plaintiffs filed their fourth amended motion to name Arrow and numerous other energy companies as additional defendants in the class action lawsuit. The plaintiffs alleged, among other things, that Arrow (i) was a producer of the crude oil being transported on the derailed train, (ii) was negligent in failing to properly classify the crude delivered to the trucks that hauled the crude to the rail loading terminal, and (iii) owed a duty to the petitioners to ensure the safe transportation of the crude being transported. The motion to authorize the class action and motions in opposition were heard by the Court in June 2014. In June 2015, the Superior Court determined that the Class Action Suit proceeding should be allowed to proceed against certain respondents that have not contributed to the global settlement described below. Because Arrow is a contributing party to the global settlement, the Class Action Suit against Arrow has been stayed pending finalization of the global settlement plan in the United States and Canadian bankruptcy proceedings described below.

One of the defendants in the lawsuit, Montreal Main & Atlantic Railway (MM&A), filed bankruptcy actions in the U.S. Bankruptcy Court for the District of Maine and in the Canadian Bankruptcy Court. The bankruptcy trustees in the proceedings approached the respondents in the Class Action Suit (including Arrow) to contribute monetary damages to a global settlement for all claims, including any potential environmental damages, related to the Lac Megantic derailment. During the first quarter of 2015, Crestwood Midstream agreed to contribute to the global settlement in exchange for a release from all claims related to the derailment, including the Class Action Suit. In June 2015, the creditors in the Canadian bankruptcy proceeding voted unanimously in favor of the global settlement. The Canadian bankruptcy court approved the bankruptcy plan (including the global settlement) on July 13, 2015, and the United States bankruptcy court approved a modified version of the bankruptcy plan (including the global settlement) on October 9, 2015. Consistent with the modified plan approved in the US bankruptcy

157

proceeding, the Canadian bankruptcy court also approved a modified bankruptcy plan on October 9, 2015. The US and Canadian bankruptcy proceedings were finalized in December 2015 and the funding of the settlement was complete. Crestwood Midstream's contribution to the global settlement, in addition to associated legal fees, is fully covered by insurance, and since the global settlement is finalized, Arrow should not be exposed to additional damages relating to the derailment.

Additional lawsuits related to the derailment were filed and are pending in United States courts, however, all of lawsuits have been stayed as a result of the automatic stay arising from MM&A's United States bankruptcy proceeding. Arrow has been named as a defendant in 39 lawsuits pending in three different courts; however, we expect these lawsuits to be dismissed with prejudice upon disbursement of funds to the victims. We expect these cases to be dismissed by the end of April 2016.

Based on Crestwood Midstream's contribution to the global settlement and since the global settlement was approved by both bankruptcy courts, we do not anticipate any material loss in this matter after considering insurance.

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

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

On August 12, 2015, the defendants filed a motion to consolidate the Farber and Aron cases, which the court granted on September 4, 2015. Farber subsequently dismissed his claims against all the defendants on September 16, 2015. Aron filed a motion for temporary restraining order and requested an expedited preliminary injunction hearing, which was scheduled for September 23, 2015.

On September 22, 2015, the parties entered into a memorandum of understanding (MOU) with respect to a proposed settlement of the Aron lawsuit. The settlement contemplated by the MOU is subject to a number of conditions, including notice to the class, limited confirmatory discovery and final court approval of the settlement. The defendants expect the court to approve the final settlement during the first half of 2016. The anticipated settlement of the MOU has not and will not have a material impact to our consolidated financial statements.

Property Taxes. Tres Palacios filed a lawsuit in Matagorda County for tax years 2011, 2012 and 2013 alleging that the Matagorda County Appraisal District (MCAD) assessed taxable value above the fair market value and on an unequal and non-uniform basis compared to other properties. In conjunction with its sale of Tres Palacios to Tres Holdings, Crestwood Equity retained liability for certain tax matters, including this litigation. In January 2015, Crestwood Equity received a refund related to the 2011 tax year at the conclusion of the litigation related to that tax year. For the 2012 and 2013 tax years, the MCAD asserted a taxable value that would result in property taxes of approximately $7 million for each of those years, while Tres Palacios asserted a taxable value that would result in property taxes of less than $2 million in each year. Tres Palacios paid approximately $8.6 million to Matagorda County in total for those two tax years. A bench trial was held in October 2015 related to the 2012 and 2013 tax years and the trial court has not issued a decision on those years. These lawsuits remain pending and the outcome is not yet determined.

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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, 2015 and 2014, both CEQP and CMLP had less than $0.1 million and approximately $1.0 million accrued for the outstanding legal matters. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures for which we can estimate will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.

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

Regulatory Compliance

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

Environmental Compliance

During the year ended December 31, 2014, we experienced three releases totaling approximately 28,000 barrels of produced water on our Arrow water gathering system located on the Fort Berthold Indian Reservation in North Dakota. We immediately notified the National Response Center, the Three Affiliated Tribes and numerous other regulatory authorities, and thereafter contained and cleaned up the releases completely and placed the impacted segments of these water lines back into service. In May 2015, we experienced a release of approximately 5,200 barrels of produced water on our Arrow water gathering system, immediately notified numerous regulatory authorities and other third parties, and thereafter contained and cleaned up the release. 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, 2015.

We may potentially be subject to fines and penalties as a result of the water releases. In October 2014, we received data requests from the Environmental Protection Agency (EPA) related to the 2014 water releases and we responded to the requests during the first half of 2015. In April 2015, the EPA issued a Notice of Potential Violation (NOPV) under the Clean Water Act relating to the 2014 water releases. We responded to the NOPV in May 2015, and have commenced settlement discussions with the EPA concerning the NOPV. On March 3, 2015, we received a grand jury subpoena from the United States Attorney’s Office in Bismarck, North Dakota, seeking documents and information relating to the largest of the three 2014 water releases, and we provided the requested information during the second quarter of 2015. 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 ongoing settlement discussions with the regulatory agencies asserting jurisdiction over the 2014 produced water releases. We cannot predict what the outcome of these investigations will be.

Our operations are subject to stringent and complex laws and regulations pertaining to health, safety, and the environment. We are subject to laws and regulations at the federal, state and local levels that relate to air and water quality, hazardous and solid waste management and disposal and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures. At December 31, 2015 and 2014, our accrual of approximately $1.7 million and $1.1 million was primarily related to the Arrow water releases described above, which is based on our undiscounted estimate of amounts we will spend on compliance with environmental and other regulations, 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 $1.7 million to $3.7 million.

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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 evaluates our insurance accruals and adjusts 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, 2015 and 2014, CEQP's self-insurance reserves were $17.2 million and $14.6 million. CEQP estimates that $11.3 million of this balance will be paid subsequent to December 31, 2016. As such, CEQP has classified $11.3 million in other long-term liabilities on our consolidated balance sheets. At December 31, 2015 and 2014, CMLP's self-insurance reserves were $11.4 million and $7.2 million. CMLP estimates that $7.1 million of this balance will be paid subsequent to December 31, 2016. As such, CMLP has classified $7.1 million in other long-term liabilities on our consolidated balance sheets.

Contingent Consideration - Antero

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

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 2016 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,
2016	$	19.1
2017	16.6
2018	15.3
2019	14.1
2020	9.2
Thereafter	23.8
Total minimum lease payments	$	98.1

Our rent expense for operating leases for the years ended December 31, 2015, 2014 and 2013, totaled $37.4 million, $41.8 million and $16.4 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, 2015, the total of these firm purchase commitments was $188.3 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.

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We have entered into certain purchase commitments in connection with the identified growth projects and maintenance obligations primarily related to our gathering and processing segment, the development of a rail terminal project and certain upgrades to the US Salt facility. At December 31, 2015, the total of our storage and transportation and marketing, supply and logistics operations' firm purchase commitments was approximately $12.7 million and our gathering and processing segment's purchase commitments totaled approximately $13.5 million. The majority of the purchases associated with these commitments are expected to occur over the next twelve months.

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, including Sabine Oil and Gas LLC and Mountaineer Keystone LLC.

CEQP and CMLP enter into transactions with their 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.

As discussed in Note 1, in conjunction with the completion of the Simplification Merger, CEQP contributed 100% of its interest

in Crestwood Operations to CMLP. Crestwood Operations has 1,288 full-time employees as of December 31, 2015, 297 of which are general and administrative employees and 991 of which are operational employees. Prior to the Simplification Merger, CMLP did not have any employees other than approximately 100 union employees of US Salt. CMLP shares common management, general and administrative and overhead costs with CEQP and allocated shared costs of $0.8 million to CEQP during the year ended December 31, 2015.

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, 2015, 2014 and 2013 (in millions):



	Year Ended December 31,
	2015		2014		2013
Gathering and processing revenues at CEQP and CMLP	$	3.9	$	3.0	$	74.9
Gathering and processing costs of product/services sold at CEQP and CMLP⁽¹⁾	$	28.9	$	42.2	$	32.5
Operations and maintenance expenses charged at CEQP and CMLP	$	2.8	$	0.2	$	—
General and administrative expenses charged by CEQP to CMLP, net⁽²⁾	$	49.5	$	63.6	$	34.7
General and administrative expenses charged by CEQP to Crestwood Holdings, net⁽³⁾	$	0.4	$	0.5	$	25.3

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

(2) Includes $10.0 million, $6.9 million and $4.4 million of net unit-based compensation charges allocated from CEQP to CMLP for the years ended December 31, 2015, 2014 and 2013.


(3)	Includes $0.1 million unit-based compensation charges allocated from Crestwood Holdings to CMLP during the year ended December 31, 2015.

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



	CEQP				CMLP
	December 31,				December 31,
	2015		2014		2015		2014
Accounts receivable	$	1.7	$	0.6	$	1.7	$	0.3
Accounts payable	$	4.0	$	5.6	$	1.5	$	3.1

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Note 17 – Segments

Financial Information

As discussed in Note 1, on September 30, 2015, the Company contributed 100% of its interest in Crestwood Operations to Crestwood Midstream and as a result, we modified our segments and our financial statements now reflect three operating and reportable segments: (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) marketing, supply and logistics operations (formerly NGL and crude services operations). Consequently, the results of our Arrow operations are now reflected in our gathering and processing operations for all periods presented and our COLT and PRBIC operations are now reflected in our storage and transportation operations for all periods presented. These respective operations were previously included in our NGL and crude services 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 loss on modification/extinguishment of debt) and depreciation, amortization and accretion expense.

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



	Year Ended December 31,
	2015			2014			2013
Net loss	$	(2,303.7	)	$	(10.4	)	$	(50.6	)
Add:
Interest and debt expense, net	140.1			127.1			77.9
Loss on modification/extinguishment of debt	20.0			—			—
Provision (benefit) for income taxes	(1.4		)	1.1			1.0
Depreciation, amortization and accretion	300.1			285.3			167.9
EBITDA	$	(1,844.9	)	$	403.1		$	196.2

The following tables summarize CEQP's reportable segment data for the years ended December 31, 2015, 2014 and 2013 (in millions). Included in earnings (loss) from unconsolidated affiliates below was approximately $86.1 million, $7.6 million and $2.6 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, 2015, 2014 and 2013, respectively.



	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, net	(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	)
Goodwill	$	54.5		$	771.2		$	259.8		$	—		$	1,085.5
Total assets	$	2,325.2		$	2,217.4		$	1,083.7		$	177.4		$	5,803.7
Purchases of property, plant and equipment	$	132.7		$	26.4		$	22.8		$	0.8		$	182.7

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	Year Ended December 31, 2014
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	2,166.8		$	264.6		$	1,499.9		$	—		$	3,931.3
Intersegment revenues	50.0			—			(50.0		)	—			—
Costs of product/services sold	1,859.9			33.3			1,272.1			—			3,165.3
Operations and maintenance expense	102.8			28.8			71.7			—			203.3
General and administrative expense	—			—			—			100.2			100.2
Gain (loss) on long-lived assets	(32.7		)	33.8			(3.0		)	—			(1.9		)
Goodwill impairment	(18.5		)	—			(30.3		)	—			(48.8		)
Loss on contingent consideration	(8.6		)	—			—			—			(8.6		)
Earnings (loss) from unconsolidated affiliates	0.5			(1.2		)	—			—			(0.7		)
Other income, net	—			—			—			0.6			0.6
EBITDA	$	194.8		$	235.1		$	72.8		$	(99.6	)	$	403.1
Goodwill	$	384.2		$	1,394.6		$	713.0		$	—		$	2,491.8
Total assets	$	3,593.6		$	2,423.3		$	2,240.6		$	203.9		$	8,461.4
Purchases of property, plant and equipment	$	327.9		$	37.0		$	50.9		$	8.2		$	424.0



	Year Ended December 31, 2013
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	510.0		$	130.9		$	785.8		$	—		$	1,426.7
Costs of product/services sold	267.5			19.7			715.1			—			1,002.3
Operations and maintenance expense	58.7			14.2			31.7			—			104.6
General and administrative expense	—			—			—			93.5			93.5
Gain (loss) on long-lived assets	5.4			—			(0.1		)	—			5.3
Goodwill impairment	(4.1		)	—			—			—			(4.1		)
Gain on contingent consideration	(31.4		)	—			—			—			(31.4		)
Earnings (loss) from unconsolidated affiliates	0.1			(0.2		)	—			—			(0.1		)
Other income, net	—			—			—			0.2			0.2
EBITDA	$	153.8		$	96.8		$	38.9		$	(93.3	)	$	196.2
Purchases of property, plant and equipment	$	290.7		$	43.4		$	11.9		$	1.0		$	347.0

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



	Year Ended December 31,
	2015			2014		2013
Net income (loss)	$	(1,410.6	)	$	14.7	$	(12.4	)
Add:
Interest and debt expense, net	130.5			111.4		71.7
Loss on modification/extinguishment of debt	18.9			—		—
Provision for income taxes	—			0.9		0.7
Depreciation, amortization and accretion	278.5			255.4		139.4
EBITDA	$	(982.7	)	$	382.4	$	199.4

163

The following tables summarize CMLP's reportable segment data for the years ended December 31, 2015, 2014 and 2013 (in millions). Included in earnings from unconsolidated affiliates below was approximately $86.1 million, $7.6 million and $2.6 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, 2015, 2014 and 2013, respectively.



	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	)
Goodwill	$	54.5		$	771.2		$	259.8		$	—		$	1,085.5
Total assets	$	2,541.6		$	2,216.7		$	1,083.7		$	162.5		$	6,004.5
Purchases of property, plant and equipment	$	132.7		$	26.4		$	22.8		$	0.8		$	182.7



	Year Ended December 31, 2014
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	2,166.8		$	250.8		$	1,499.9		$	—		$	3,917.5
Intersegment revenues	50.0			—			(50.0		)	—			—
Costs of product/services sold	1,859.9			22.8			1,272.1			—			3,154.8
Operations and maintenance expense	102.8			22.1			70.5			—			195.4
General and administrative expense	—			—			—			91.7			91.7
Gain (loss) on long-lived assets, net	(32.7		)	0.6			(3.0		)	—			(35.1		)
Goodwill impairment	(18.5		)	—			(30.3		)	—			(48.8		)
Loss on contingent consideration	(8.6		)	—			—			—			(8.6		)
Earnings (loss) from unconsolidated affiliates, net	0.5			(1.2		)	—			—			(0.7		)
EBITDA	$	194.8		$	205.3		$	74.0		$	(91.7	)	$	382.4
Goodwill	$	127.0		$	1,394.6		$	713.0		$	—		$	2,234.6
Total assets	$	2,941.6		$	2,423.3		$	2,240.6		$	179.7		$	7,785.2
Purchases of property, plant and equipment	$	327.9		$	36.4		$	50.9		$	6.5		$	421.7

164



	Year Ended December 31, 2013
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	510.0		$	116.8		$	785.8		$	—		$	1,412.6
Costs of product/services sold	267.5			12.8			715.1			—			995.4
Operations and maintenance expense	58.7			12.4			32.3			—			103.4
General and administrative expense	—			—			—			84.1			84.1
Gain on long-lived assets	5.4			—			(0.1		)	—			5.3
Goodwill impairment	(4.1		)	—			—			—			(4.1		)
Loss on contingent consideration	(31.4		)	—			—			—			(31.4		)
Earnings (loss) from unconsolidated affiliates, net	0.1			(0.2		)	—			—			(0.1		)
EBITDA	$	153.8		$	91.4		$	38.3		$	(84.1	)	$	199.4
Purchases of property, plant and equipment	$	290.7		$	35.7		$	11.9		$	1.0		$	339.3

Major Customers

No customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2015 and 2013 at CEQP or CMLP. For the year ended December 31, 2014, we had revenues from Tesoro Corporation (Tesoro) of $465.2 million which exceeded 10% of the total consolidated revenues at CEQP and CMLP. Revenues from Tesoro are reflected in each of our reportable segments.

Note 18 – Crestwood Midstream Condensed Consolidating Financial Information

Crestwood Midstream is a holding company and own no operating assets and have no significant operations independent of its subsidiaries (Parent). 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 Niobrara, 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.

At December 31, 2014, we reflected the interest of non-controlling partners in subsidiaries on our condensed consolidating balance sheet as a component of the Parent's and Non-Guarantor Subsidiaries' total partners' capital, with an adjustment to eliminate the Parent's portion. During the year ended December 31, 2015, we began reflecting the interest of non-controlling partners in subsidiaries as a component of the Non-Guarantor Subsidiaries' total partners' capital only. The condensed consolidating balance sheet for the year December 31, 2014 was adjusted to reflect the change in presentation and there was no impact to our consolidated balance sheet.

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, 2015, 2014 and 2013. 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.

165



Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2015
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	0.1	$	—	$	—	$	—		$	0.1
Accounts receivable	—		236.0		0.5		—			236.5
Inventory	—		44.5		—		—			44.5
Other current assets	—		52.5		—		—			52.5
Total current assets	0.1		333.0		0.5		—			333.6

Property, plant and equipment, net	—		3,525.7		—		—			3,525.7
Goodwill and intangible assets, net	40.9		1,846.9		—		—			1,887.8
Investment in consolidated affiliates	5,506.8		—		—		(5,506.8		)	—
Investment in unconsolidated affiliates	—		—		254.3		—			254.3
Other assets	—		3.1		—		—			3.1
Total assets	$	5,547.8	$	5,708.7	$	254.8	$	(5,506.8	)	$	6,004.5

Liabilities and partners' capital
Current liabilities:
Accounts payable	—		141.3		0.1		—			141.4

Other current liabilities	26.4		85.2		—		—			111.6
Total current liabilities	26.4		226.5		0.1		—			253.0

Long-term liabilities:
Long-term debt, less current portion	2,539.8		2.9		—		—			2,542.7
Other long-term liabilities	—		43.3		—		—			43.3
Deferred income taxes	—		0.4		—		—			0.4

Partners' capital	2,981.6		5,435.6		71.2		(5,506.8		)	2,981.6
Interest of non-controlling partners in subsidiaries	—		—		183.5		—			183.5
Total partners' capital	2,981.6		5,435.6		254.7		(5,506.8		)	3,165.1
Total liabilities and partners' capital	$	5,547.8	$	5,708.7	$	254.8	$	(5,506.8	)	$	6,004.5

166



Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2014
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	—	$	7.6	$	—	$	—		$	7.6
Accounts receivable	1.2		377.8		0.3		—			379.3
Inventory	—		46.6		—		—			46.6
Other current assets	—		103.1		—					103.1
Total current assets	1.2		535.1		0.3		—			536.6

Property, plant and equipment, net	7.9		3,738.1		—		—			3,746.0
Goodwill and intangible assets, net	38.0		3,166.2		—		—			3,204.2
Investment in consolidated affiliates	7,148.0		—		—		(7,148.0		)	—
Investment in unconsolidated affiliates	—		—		295.1		—			295.1
Other assets	—		3.3		—		—			3.3
Total assets	$	7,195.1	$	7,442.7	$	295.4	$	(7,148.0	)	$	7,785.2

Liabilities and partners' capital
Current liabilities:
Accounts payable	9.0		225.8		0.2		—			235.0
Other current liabilities	23.0		153.3		—		—			176.3
Total current liabilities	32.0		379.1		0.2		—			411.3

Long-term liabilities:
Long-term debt, less current portion	2,012.8		1.7		—		—			2,014.5
Other long-term liabilities	1.6		36.7		—		—			38.3
Deferred income taxes	—		0.7		—		—			0.7

Partners' capital	5,148.7		7,024.5		123.5		(7,148.0		)	5,148.7
Interest of non-controlling partners in subsidiaries	—		—		171.7		—			171.7
Total partners' capital	5,148.7		7,024.5		295.2		(7,148.0		)	5,320.4
Total liabilities and partners' capital	$	7,195.1	$	7,442.7	$	295.4	$	(7,148.0	)	$	7,785.2

167



Crestwood Midstream Partners LP
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 expense:
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 subsidiary	(1,195.9		)	—			—			1,195.9		—
Income (loss) before income taxes	(1,410.6		)	(1,135.1		)	(60.8		)	1,195.9		(1,410.6		)
Provision for income taxes	—			—			—			—		—
Net income (loss)	(1,410.6		)	(1,135.1		)	(60.8		)	1,195.9		(1,410.6		)
Net income attributable to non-controlling partners in subsidiaries	—			—			(23.1		)	—		(23.1		)
Net income (loss) attributable to Crestwood Midstream Partners LP	(1,410.6		)	(1,135.1		)	(83.9		)	1,195.9		(1,433.7		)
Net income attributable to Class A preferred units	(23.1		)	—			—			—		(23.1		)
Net income (loss) attributable to partners	$	(1,433.7	)	$	(1,135.1	)	$	(83.9	)	$	1,195.9	$	(1,456.8	)

168



Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,917.5		$	—		$	—		$	3,917.5
Costs of product/services sold	—			3,154.8			—			—			3,154.8
Expenses:
Operations and maintenance	—			195.4			—			—			195.4
General and administrative	49.4			42.3			—			—			91.7
Depreciation, amortization and accretion	0.9			254.5			—			—			255.4
	50.3			492.2			—			—			542.5
Other operating expense:
Loss on long-lived assets, net	—			(35.1		)	—			—			(35.1		)
Goodwill impairment	—			(48.8		)	—			—			(48.8		)
Loss on contingent consideration	—			(8.6		)	—			—			(8.6		)
Operating income (loss)	(50.3		)	178.0			—			—			127.7
Loss from unconsolidated affiliates, net	—			—			(0.7		)	—			(0.7		)
Interest and debt expense, net	(111.4		)	—			—			—			(111.4		)
Equity in net income (loss) of subsidiary	176.4			—			—			(176.4		)	—
Income (loss) before income taxes	14.7			178.0			(0.7		)	(176.4		)	15.6
Provision for income taxes	—			0.9						—			0.9
Net income (loss)	14.7			177.1			(0.7		)	(176.4		)	14.7
Net income attributable to non-controlling partners	—			—			(16.8		)	—			(16.8		)
Net income (loss) attributable to Crestwood Midstream Partners LP	14.7			177.1			(17.5		)	(176.4		)	(2.1		)
Net income attributable to Class A preferred units	(17.2		)	—			—			—			(17.2		)
Net income (loss) attributable to partners	$	(2.5	)	$	177.1		$	(17.5	)	$	(176.4	)	$	(19.3	)

169



Crestwood Midstream Partners
Condensed Consolidating Statements of Operations
Year Ended December 31, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	1,412.6		$	—		$	—		$	1,412.6
Costs of product/services sold	—			995.4			—			—			995.4
Expenses:
Operations and maintenance	—			103.4			—			—			103.4
General and administrative	46.5			37.6			—			—			84.1
Depreciation, amortization and accretion	1.0			138.4			—			—			139.4
	47.5			279.4			—			—			326.9
Other operating income (expense):
Gain on long-lived assets, net	—			5.3			—			—			5.3
Goodwill impairment	—			(4.1		)	—			—			(4.1		)
Loss on contingent consideration	—			(31.4		)	—			—			(31.4		)
Operating income (loss)	(47.5		)	107.6			—			—			60.1
Loss from unconsolidated affiliates, net	—			—			(0.1		)	—			(0.1		)
Interest and debt expense, net	(68.7		)	(3.0		)	—			—			(71.7		)
Equity in net income (loss) of subsidiary	103.8			—			—			(103.8		)	—
Income (loss) before income taxes	(12.4		)	104.6			(0.1		)	(103.8		)	(11.7		)
Provision for income taxes	—			0.7			—			—			0.7
Net income (loss)	(12.4		)	103.9			(0.1		)	(103.8		)	(12.4		)
Net income attributable to non-controlling partners	—			—			(4.9		)	—			(4.9		)
Net income (loss) attributable to Crestwood Midstream Partners LP	(12.4		)	103.9			(5.0		)	(103.8		)	(17.3		)
Net income attributable to Class A preferred units	—			—			—			—			—
Net income (loss) attributable to partners	$	(12.4	)	$	103.9		$	(5.0	)	$	(103.8	)	$	(17.3	)

170



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		)
Proceeds from the sale of assets	—			2.7			—			—			2.7
Capital distributions from unconsolidated affiliates	—			—			9.3			—			9.3
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
Principal 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 paid	(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

171



Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(165.6	)	$	602.9		$	—		$	—		$	437.3

Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(19.5		)	—			—			(19.5		)
Purchases of property, plant and equipment	(4.3		)	(417.4		)	—			—			(421.7		)
Investment in unconsolidated affiliates, net	—			—			(144.4		)	—			(144.4		)
Proceeds from the sale of assets	—			2.7			—			—			2.7
Capital contributions to consolidated affiliates	(89.5		)	—			—			89.5			—
Net cash provided by (used in) investing activities	(93.8		)	(434.2		)	(144.4		)	89.5			(582.9		)

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,089.9			—			—			—			2,089.9
Principal payments on long-term debt	(1,949.8		)	(0.2		)	—			—			(1,950.0		)
Payments on capital leases	(1.3		)	(1.9		)	—			—			(3.2		)
Payments for debt-related deferred costs	(0.1		)	—			—			—			(0.1		)
Distributions paid	(470.5		)	—			—			—			(470.5		)
Contributions from parents	—			—			89.5			(89.5		)	—
Net proceeds from issuance of preferred equity of subsidiary	—			—			53.9			—			53.9
Net proceeds from issuance of Class A preferred units	430.5			—			—			—			430.5
Taxes paid for unit-based compensation vesting	—			(1.6		)	—			—			(1.6		)
Change in intercompany balances	161.4			(161.4		)	—			—			—
Other	(0.8		)	—			—			—			(0.8		)
Net cash provided by (used in) financing activities	259.3			(165.1		)	143.4			(89.5		)	148.1

Net change in cash	(0.1		)	3.6			(1.0		)	—			2.5
Cash at beginning of period	0.1			4.0			1.0			—			5.1
Cash at end of period	$	—		$	7.6		$	—		$	—		$	7.6

172



Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(46.1	)	$	333.6		$	—		$	(33.8	)	$	253.7

Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(561.5		)	—			—			(561.5		)
Purchases of property, plant and equipment	(1.0		)	(338.3		)	—			—			(339.3		)
Investment in unconsolidated affiliates, net	—			—			(151.5		)	—			(151.5		)
Capital contributions to consolidated affiliates	(106.4		)	—			—			106.4			—
Proceeds from the sale of assets	—			11.2			—			—			11.2
Net cash provided by (used in) investing activities	(107.4		)	(888.6		)	(151.5		)	106.4			(1,041.1		)

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,072.8			—			—			—			2,072.8
Principal payments on long-term debt	(1,634.3		)	(0.2		)	—			—			(1,634.5		)
Payments on capital leases	(0.4		)	(3.9		)	—			—			(4.3		)
Payments for debt-related deferred costs	(32.0		)	—			—			—			(32.0		)
Distributions paid	(419.7		)	(33.8		)	—			33.8			(419.7		)
Contributions from parents	—			55.5			56.4			(106.4		)	5.5
Net proceeds from the issuance of common units	714.0			—			—			—			714.0
Net proceeds from issuance of preferred equity of subsidiary	—			—			96.1			—			96.1
Taxes paid for unit-based compensation vesting	—			(5.5		)	—			—			(5.5		)
Change in intercompany balances	(546.8		)	546.8			—			—			—
Net cash provided by (used in) financing activities	153.6			558.9			152.5			(72.6		)	792.4

Net change in cash	0.1			3.9			1.0			—			5.0
Cash at beginning of period	—			0.1			—			—			0.1
Cash at end of period	$	0.1		$	4.0		$	1.0		$	—		$	5.1

173

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
2015
Revenues	$	731.5		$	641.5		$	630.7		$	629.1
Operating income (loss)⁽¹⁾	48.5			(248.9		)	(588.3		)	(1,296.1		)
Earnings (loss) from unconsolidated affiliates, net	3.4			5.0			2.8			(72.0		)
Net income (loss)	18.1			(296.0		)	(623.4		)	(1,402.4		)
Net income (loss) attributable to partners	8.3			(40.0		)	(226.9		)	(1,414.5		)
Net income (loss) per limited partner unit:
Basic	$	0.44		$	(2.14	)	$	(11.78	)	$	(20.77	)
Diluted	$	0.44		$	(2.14	)	$	(11.76	)	$	(20.77	)
2014
Revenues	$	971.6		$	926.3		$	1,036.2		$	997.2
Operating income (loss)⁽¹⁾	45.7			29.4			43.0			(0.2		)
Earnings (loss) from unconsolidated affiliates, net	(0.1		)	(1.5		)	0.3			0.6
Net income (loss)	13.2			(4.8		)	11.9			(30.7		)
Net income (loss) attributable to partners	19.6			(4.4		)	2.8			38.4
Net income (loss) per limited partner unit:
Basic	$	1.05		$	(0.24	)	$	0.15		$	2.06
Diluted	$	1.05		$	(0.24	)	$	0.15		$	2.06



Crestwood Midstream	Quarter Ended
	March 31			June 30			September 30			December 31
2015
Revenues	$	731.5		$	641.5		$	630.7		$	629.1
Operating income (loss) ⁽²⁾	56.0			(28.0		)	(578.7		)	(649.7		)
Earnings (loss) from unconsolidated affiliates, net	3.4			5.0			2.8			(72.0		)
Net income (loss)	29.1			(72.8		)	(610.2		)	(756.7		)
Net income (loss) attributable to partners	14.3			(86.0		)	(622.5		)	(762.6		)
2014
Revenues	$	964.9		$	923.9		$	1,033.8		$	994.9
Operating income (loss) ⁽²⁾	54.7			41.6			54.6			(23.2		)
Earnings (loss) from unconsolidated affiliates, net	(0.1		)	(1.5		)	0.3			0.6
Net income (loss)	25.8			11.0			27.1			(49.2		)
Net income (loss) attributable to partners	22.7			6.2			13.5			(61.7		)

(1)

Amount includes goodwill, property, plant and equipment and intangible asset impairments of approximately $281.0 million, $610.8 million, $1,332.3 million and $83.3 million during the three months ended June 30, 2015, September 30, 2015, December 31, 2015 and December 31, 2014, respectively. See Note 2 for a further discussion of our impairments recorded during 2015 and 2014. In addition, for 2014, amount includes a gain of approximately $30.6 million on the sale of our interest in Tres Palacios. See Note 6 for a further discussion of our divestiture of Tres Palacios.


(2)	Amount for the three months ended December 31, 2015 includes impairments of our Jackalope and PRBIC equity investments of approximately $51.4 million and $23.4 million, respectively. See Note 2 for a further discussion of these impairments recorded during 2015.


(3)	Amount includes goodwill, property, plant and equipment and intangible asset impairments of approximately $68.6 million, $610.8 million, $694.3 million and $83.3 million during the three months ended June 30, 2015, September 30, 2015, December 31, 2015 and December 31, 2014, respectively. See Note 2 for a further discussion of our impairments recorded during 2015 and 2014.

174

Table of Contents

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 26, 2016	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 26, 2016		/S/ ROBERT G. PHILLIPS Robert G. Phillips, President, Chief Executive Officer and Director (Principal Executive Officer)

February 26, 2016		/S/ ROBERT T. HALPIN Robert T. Halpin, Senior Vice President and Chief Financial Officer (Principal Financial Officer)

February 26, 2016		/S/ STEVEN M. DOUGHERTY Steven M. Dougherty, Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)

February 26, 2016		/S/ ALVIN BLEDSOE Alvin Bledsoe, Director

February 26, 2016		/S/ MICHAEL G. FRANCE Michael G. France, Director

February 26, 2016		/S/ WARREN H. GFELLER Warren H. Gfeller, Director

February 26, 2016		/S/ DAVID LUMPKINS David Lumpkins, Director

February 26, 2016		/S/ JOHN J. SHERMAN John J. Sherman, Director

February 26, 2016		/S/ JOHN W. SOMERHALDER II John W. Somerhalder II, Director

175

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Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Balance Sheet

(in millions)



	December 31,
	2015		2014
Assets
Current assets:
Cash	$	0.4	$	3.7
Accounts receivable - trade	1.8		—
Accounts receivable - intercompany	—		3.2
Total current assets	2.2		6.9

Property, plant and equipment, net	1.5		2.5
Intangible assets	7.8		1.7
Investment in subsidiaries	2,757.7		5,799.5
Other assets	3.5		—
Total assets	$	2,772.7	$	5,810.6

Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	2.6	$	—
Accrued expenses	2.3		1.9
Current portion of long-term debt	0.2		3.0
Total current liabilities	5.1		4.9

Long-term debt, less current portion	—		380.0
Other long-term liabilities	4.2		12.9

Total partners’ capital	2,763.4		5,412.8
Total liabilities and partners’ capital	$	2,772.7	$	5,810.6

See accompanying notes.

176

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Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statement of Operations

(in millions)



	Year Ended December 31,
	2015			2014			2013
Revenues	$	—		$	—		$	—
Expenses	14.5			8.5			—
Operating loss	(14.5		)	(8.5		)	—
Interest and debt expense, net	(9.6		)	(15.7		)	(6.5		)
Equity in net income (loss) of subsidiaries	(2,279.1		)	14.2			(43.9		)
Loss on modification/extinguishment of debt	(1.1		)	—			—
Other income, net	0.6			—			—
Loss before income taxes	(2,303.7		)	(10.0		)	(50.4		)
Provision for income taxes	—			0.4			0.2
Net loss and net loss attributable to Crestwood Equity Partners LP	(2,303.7		)	(10.4		)	$	(50.6	)
Net income attributable to preferred units	(6.2		)	—			—
Net loss attributable to partners	$	(2,309.9	)	$	(10.4	)	$	(50.6	)

See accompanying notes.

177

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Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statement of Comprehensive Income

(in millions)



	Year Ended December 31,
	2015			2014			2013
Net loss	$	(2,303.7	)	$	(10.4	)	$	(50.6	)
Change in fair value of Suburban Propane Partners, LP units	(2.7		)	(0.5		)	(0.1		)
Comprehensive loss attributable to Crestwood Equity Partners LP	$	(2,306.4	)	$	(10.9	)	$	(50.7	)

See accompanying notes.

178

Table of Contents

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statement of Cash Flows

(in millions)



	Year Ended December 31,
	2015			2014			2013
Cash flows from operating activities	$	(14.7	)	$	(25.3	)	$	(12.3	)

Cash flows from investing activities	593.8			170.8			20.7

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	771.7			734.0			394.1
Principal payments on long-term debt	(1,152.1		)	(746.2		)	(333.3		)
Payments for debt-related deferred costs	—			(1.8		)	—
Distributions paid to partners	(171.5		)	(102.5		)	(68.4		)
Change in intercompany balances	(30.5		)	(25.4		)	0.4
Other	—			—			(1.1		)
Net cash used in financing activities	(582.4		)	(141.9		)	(8.3		)

Net change in cash	(3.3		)	3.6			0.1
Cash at beginning of period	3.7			0.1			—
Cash at end of period	$	0.4		$	3.7		$	0.1

See accompanying notes.

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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, 2015, 2014 and 2013, we received cash distributions from Crestwood Midstream Partners LP of approximately $31.4 million, $72.4 million and $26.2 million.

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Schedule II

Crestwood Equity Partners LP

Valuation and Qualifying Accounts

For the Years Ended December 31, 2015, 2014 and 2013

(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
2015	$	0.1	$	—		$	0.4	$	(0.1	)	$	0.4
2014	0.1		—			—		—			0.1
2013	—		(1.1		)	1.2		—			0.1

181