CEQP - 10K 2014

Large accelerated filer

Accelerated filer

Non-accelerated filer

¨ (Do not check if a smaller reporting company)

Smaller reporting company

10-K 1 ceqp-10k2014.htm 10-K CEQP - 10K 2014

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, 2014



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

COMMISSION FILE NUMBER: 001-34664

Crestwood Equity Partners LP

(Exact name of registrant as specified in its charter)



Delaware		43-1918951
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)



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

(832) 519-2200

(Registrant’s telephone number, including area code)

___________________________________________

SECURITIES REGISTERED PURSUANT TO SECTION 12(b) OF THE ACT:



Title of Each Class		Name of Each Exchange on Which Registered
Common Units representing limited partnership interests		The New York Stock Exchange

SECURITIES REGISTERED PURSUANT TO SECTION 12(g) OF THE ACT: None

Indicate by check mark if registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. Yes x No ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act. Yes ¨ No x

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

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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. 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.

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

The aggregate market value of the 111,166,893 common units of the registrant held by non-affiliates computed by reference to the $7.09 closing price of such common units on February 13, 2015, was $0.8 billion. As of June 30, 2014, the last business day of the registrant's most recently completed second quarter, the aggregate market value of the registrant's common units held by non-affiliates of the registrant was $1.6 billion based on a closing price of $14.87 per common unit as reported on the New York Stock Exchange on such date. As of February 13, 2015, the registrant had 187,349,776 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the following documents are incorporated by reference into the indicated parts of this report: None.

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CRESTWOOD EQUITY PARTNERS LP

INDEX TO ANNUAL REPORT ON FORM 10-K



		Page
	PART I

Item 1.	Business	6

Item 1A.	Risk Factors	25

Item 1B.	Unresolved Staff Comments	45

Item 2.	Properties	45

Item 3.	Legal Proceedings	45

Item 4.	Mine Safety Disclosures	45

	PART II

Item 5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	46

Item 6.	Selected Financial Data	47

Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51

Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	70

Item 8.	Financial Statements and Supplementary Data	71

Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	71

Item 9A.	Controls and Procedures	71

Item 9B.	Other Information	72

	PART III

Item 10.	Directors, Executive Officers and Corporate Governance	73

Item 11.	Executive Compensation	78

Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	89

Item 13.	Certain Relationships and Related Transactions, and Director Independence	91

Item 14.	Principal Accountant Fees and Services	94

	PART IV

Item 15.	Exhibits, Financial Statement Schedules	96

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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,” 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” 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, 2014.

Introduction

Crestwood Equity, a Delaware limited partnership formed in 2004, 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 and crude oil shale plays across the United States. Our common units representing limited partner interests are listed on the NYSE under the symbol “CEQP.”

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. Our consolidated operating assets include:


•	natural gas facilities with approximately 2.5 Bcf/d of gathering capacity, 481 MMcf/d of processing capacity,

1.1 Bcf/d of firm transmission capacity, and 41 Bcf of certificated working gas storage capacity;


•	NGL facilities with approximately 24,000 Bbls/d of fractionation capacity and 2.8 million barrels of storage capacity;


•	crude oil facilities with approximately 125,000 Bbls/d of gathering capacity, approximately 1.1 million barrels of storage capacity, 48,000 Bbls/d of transportation capacity and 160,000 Bbls/d of rail loading capacity; and


•	a fleet of transportation assets supporting our proprietary NGL supply and logistics business, including 8 truck and rail terminals and approximately 543 truck/trailer units and 1,600 rail units that can transport more than 294,000 Bbls/d of NGLs.

Our primary business objective is to increase the cash distributions that we pay to our unitholders. We have worked to position Crestwood Midstream as a growth MLP through which we will expand our midstream platform and to reposition the Company as more of a “pure play” general partner rather than an operating company, and we expect to continue this strategy going forward. We therefore expect to increase cash available for distribution to our unitholders primarily through our investment in Crestwood Midstream and, to a lesser extent, through growth opportunities involving the assets owned by us. We anticipate that the contribution of our remaining operating assets into Crestwood Midstream will enhance our value based on our ownership interests in Crestwood Midstream (including our ownership of its incentive distribution rights or IDRs), and we expect to consummate such drop downs at an appropriate time in the future.

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Ownership Structure

The diagram below reflects a simplified version of our ownership structure as of December 31, 2014:

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Our non-economic general partner interest is held by Crestwood Equity GP LLC, our general partner and which is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings). Crestwood Holdings, which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve), also owns approximately 27% of our limited partner units as of December 31, 2014.

We own the non-economic general partner interest of Crestwood Midstream and, therefore, control and consolidate Crestwood Midstream. We also own 100% of the IDRs and approximately 4% of the common units representing limited partnership interests of Crestwood Midstream as of December 31, 2014.

In May 2013, the former owners of our general partner and Crestwood Holdings 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 us. The strategic business combination was completed in October 2013 when Legacy Crestwood merged with and into Inergy Midstream (the Crestwood Merger) and Inergy Midstream changed its name to Crestwood Midstream Partners LP. See Part IV, Item 15, Exhibits, Financial Statement Schedules, Notes 1 and 3 for additional information on these related transactions.

Our Assets

We, through our wholly-owned subsidiaries, own and operate a proprietary NGL supply and logistics business, which includes our West Coast NGL operations, our Seymour NGL storage facility and our fleet of NGL transportation and related rail-to-truck terminal assets. All of our other consolidated assets are owned by or through Crestwood Midstream.

We have three reporting segments: (i) gathering and processing (G&P), (ii) storage and transportation, and (iii) NGL and crude services.

Gathering and Processing

We provide natural gas gathering, processing, treating and compression services to producers in multiple unconventional shale plays located in West Virginia, Wyoming, Texas, Arkansas, New Mexico, and Louisiana. We own rich gas systems in the Marcellus, Barnett, Granite Wash, Avalon/Bone Spring and Powder River Basin (PRB) Niobrara Shale plays, as well as dry gas gathering systems in the Barnett, Fayetteville and Haynesville/Bossier Shale plays.

The table below summarizes certain information about our G&P systems (including our equity investment) as of December 31, 2014:



Shale Play (State)	Counties / Parishes	Pipeline (Miles)	Gathering Capacity (MMcf/d)	Average Gathering Volume (MMcf/d)	Compression (HP)	Number of In-Service Processing Plants	Processing Capacity (MMcf/d)	Gross Acreage Dedication
Marcellus West Virginia	Harrison, Barbour and Doddridge	77	875	598	138,080	—	—	140,000
Barnett Texas	Hood, Somervell, Johnson, Tarrant, and Denton	496	955	417	153,465	2	425	140,000
Fayetteville Arkansas	Conway, Faulkner, Van Buren, and White	171	510	98	27,645	—	—	143,000
Granite Wash Texas	Roberts	36	36	23	12,240	1	36	22,000
Haynesville / Bossier Louisiana	Sabine	57	100	9	—	—	—	22,000
Avalon / Bone Spring New Mexico	Eddy	71	50	13	955	1	20	107,000
Consolidated Total		908	2,526	1,158	332,385	4	481	574,000
PRB Niobrara⁽¹⁾ Wyoming	Converse	162	90	56	24,080	—	—	311,000
Total		1,070	2,616	1,214	356,465	4	481	885,000


(1)	Our PRB Niobrara assets are owned by Jackalope Gas Gathering Services, L.L.C. (Jackalope), our 50% equity method investment.

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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.

Marcellus

We own and operate rich gas systems in Harrison and Doddridge Counties, West Virginia and a dry gas system in Barbour County, West Virginia. These systems consist of 77 miles of low pressure gathering lines and eight compression and dehydrations stations with 138,080 horsepower. Our current operations are predominantly focused on our rich gas systems. On these systems, we provide midstream services to Antero Resources Appalachian Corporation (Antero), which is the most active upstream developer of the rich gas corridor of the southwestern core of the Marcellus Shale play. We provide our services under long-term, fixed-fee contracts across two operating areas, our eastern area of operation (East AOD) and our western area of operation (Western Area).

In the East AOD, we provide gathering, dehydration and compression services to Antero in an approximately 140,000 gross acre area from which Antero has dedicated all production of rich natural gas to our system pursuant to a 20-year, fixed-fee gathering and compression agreement. As a part of that agreement, we gather and deliver Antero’s production to MarkWest Energy Partners’ Sherwood Gas Processing Plant and various regional pipeline systems. Our system is currently connected to 225 wells and current average daily volumes delivered to our system have increased by over 180% from when we acquired the assets in 2012.

In the Western Area, we provide compression and dehydration services to Antero’s gathering facilities predominantly with our West Union and Victoria compressor stations. We provide services to Antero 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. Although volumes compressed from these stations are not contractually dedicated to us in the Western Area, Antero does provide minimum volume commitments up to 50% of the throughput capacity of each compressor station. We also hold a right of first offer until 2019 to acquire and develop any midstream facilities developed by Antero in the Western Area for ultimate transfer or sale to a third party.

In the southwest portion of the Marcellus Shale, we have completed several expansions on our Antero gathering system that have increased total gathering capacity. Antero continues to develop production in the Marcellus Shale to connect additional wells to our systems. We invested approximately $191 million in our Marcellus systems during the year ended December 31, 2014.

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, 2014, our Cowtown and Corvette plants had a total average throughput of 170 MMcf/d of natural gas with an average NGL recovery of 15,600 Bbl/d.

Our Lake Arlington system, which is located in eastern Tarrant County, Texas, consists of a 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 gas gathering system and a related dehydration, compression and amine treating facility.

We also own the West Johnson County system in the Barnett, which was operational from the date we acquired the plant (August 24, 2012) until we ceased operating the plant on December 31, 2012. We have since diverted rich gas volumes to our other processing facilities and are currently evaluating other potential uses for the West Johnson County plant, which has a processing capacity of 100 MMcf/d of natural gas.

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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.

Other

We also own and operate systems in the Granite Wash, Avalon Shale/Bone Spring, 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 Las Animas system, which is located in Eddy County, New Mexico, consists of three gas gathering systems located in the Morrow/Atoka reservoir and the Avalon Shale/Bone Spring rich gas trend in the Permian Basin. In mid-July 2014, we substantially completed a Phase 2 expansion of our Willow Lake project which included a 20 MMcf/d cryogenic processing facility and expansion of our gathering system, anchored by a 10-year fixed-fee gas gathering and processing agreement with Trinity River Energy, LLC (formerly “Legend Production Holdings, LLC”) (Trinity) in Eddy County, New Mexico at a cost of approximately $19 million. These projects support emerging production from one of the most active drilling areas within the region. 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.

PRB Niobrara

Our G&P segment includes our 50% equity interest in the Jackalope system, which we account for under the equity method of accounting. The Jackalope system is a gas gathering system being developed to support a 311,000 gross acre AOD operated by Chesapeake Energy Corporation (Chesapeake) and RKI Exploration and Production LLC (RKI) in the core of the PRB Niobrara Shale. The Jackalope system, which is also 50% owned and operated by Williams Partners LP (Williams), consists of approximately 162 miles of gathering pipelines and 24,080 horsepower of compression equipment located in Converse County, Wyoming. The existing system, which connects to 77 well pads, is supported by a 20-year gathering and processing agreement with Chesapeake and RKI under which 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. In January 2015, the construction of the 120 MMcf/d Bucking Horse processing plant was completed and placed into service. We expect volumes at the Bucking Horse processing plant to significantly increase throughout the first quarter of 2015. In addition, the gathering system continues to expand with the most recent compression facility placed into service in January 2015. We are actively working with area producers to develop additional gathering and processing facilities beyond our Jackalope acreage in the region.

We invested approximately $105 million in Jackalope during the year ended December 31, 2014. Our Jackalope interest, which we acquired in July 2013, was financed in part through a joint venture formed by our consolidated subsidiary, Crestwood Niobrara LLC (Crestwood Niobrara), with General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE). Crestwood Niobrara manages the commercial operations of Jackalope. See Item 15, Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in Jackalope.

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The table below summarizes certain contract profile information (including our equity investment) as of December 31, 2014:



Shale Play	Type of Services	Type of Contracts⁽¹⁾	Gross Acreage Dedication	Major Customers	Weighted Average Remaining Contract Terms (in years)
Marcellus	Gathering	Fixed-fee⁽²⁾	140,000	Antero	17
	Compression	Fixed-fee	—	Antero	5
Barnett	Gathering	Fixed-fee	140,000	Quicksilver Resources Inc.⁽³⁾, Devon Energy Corporation	8
	Processing	Fixed-fee	—	Quicksilver Resources Inc.⁽³⁾, Devon Energy Corporation	8
	Compression	Fixed-fee	—	Quicksilver Resources Inc.⁽³⁾, Devon Energy Corporation	8
Fayetteville	Gathering	Fixed-fee	143,000	BHP Billiton Petroleum	10
	Treating	Fixed-fee	—	BHP Billiton Petroleum	10
Other⁽⁴⁾	Gathering	Fixed-fee	151,000	Sabine Oil and Gas, Trinity River Energy	10
	Processing	Mixed	—	Sabine Oil and Gas, Trinity River Energy	10
PRB Niobrara⁽⁵⁾	Gathering	Fixed-fee cost-of-service	311,000	Chesapeake	17
	Processing	Fixed-fee cost-of-service	—	Chesapeake	17


(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 425 MMcf/d in 2015 up to an average of 450 MMcf/d in 2016, 2017 and 2018, respectively.


(3)	Eni SpA and Toyko Gas own approximately 27.5% and 25%, respectively, of Quicksilver Resources Inc.'s (Quicksilver) Barnett assets.


(4)	Other shale plays include Granite Wash, Haynesville / Bossier and Avalon / Bone Spring.


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

Storage and Transportation

We own and operate high-performance natural gas storage facilities with an aggregate working gas storage capacity of approximately 79.3 Bcf, including our 50.01% ownership interest in Tres Palacios Gas Storage Company LLC (Tres Palacios), which we account for under the equity method of accounting. Our storage facilities have low maintenance costs, long useful lives and comparatively high cycling capabilities.

Storage Facilities. We have four storage facilities located in New York and Pennsylvania. The interconnectivity of our storage facilities with interstate pipelines offers significant flexibility to our customers, and our facilities are located in close proximity to prolific supply sources. Each of our storage facilities are 100% 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 Central New York Oil And Gas Company, L.L.C. (CNYOG) subsidiary. A 24-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 7.8-mile, 8-inch diameter pipeline lateral connects to Millennium. Thomas Corners is also connected to Dominion Transmission Inc. (Dominion) system through our Steuben facility;


•	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; and


•	Seneca Lake, a FERC-certificated 1.5 Bcf multi-cycle, bedded salt storage facility owned and operated by Arlington Storage. A 19-mile, 16-inch diameter pipeline lateral connects the storage facility to the Millennium and Dominion systems.

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The following provides additional information about our natural gas storage facilities (including our equity investment) as of December 31, 2014:



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.

In December 2014, we sold our 100% membership interest in Tres Palacios, which owns a 38.4 Bcf multi-cycle salt dome gas storage facility located in Texas, to Tres Holdings, a joint venture formed by Crestwood Midstream and Brookfield Infrastructure Group (Brookfield) for cash consideration of approximately $132.8 million, of which approximately $66.4 million was paid by Crestwood Midstream. The natural gas storage facility's 60-mile, dual 24-inch diameter header system (including a 51-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. 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. See Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our divestiture of Tres Palacios and our investment in unconsolidated affiliates.

Transportation Facilities. We own natural gas transportation facilities located in New York and Pennsylvania. These facilities have low maintenance costs and long useful lives, and they are located in or near the Marcellus Shale. Throughput on our transportation assets can also be expanded at relatively low capital costs. In 2014, our transportation facilities delivered approximately 1.8 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 facilities, which are owned and operated by CNYOG, provide more than 457 MMcf/d of firm interstate transportation capacity to shippers. The North-South Facilities generate fee-based revenues under a negotiated rate structure authorized by the FERC;

•

MARC I Pipeline, a 39-mile, 30-inch diameter interstate natural gas pipeline that connects the 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 CNYOG, provides more than 645 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; and

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East Pipeline, a 37.5 mile, 12-inch diameter natural gas intrastate 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 and operated 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).

The table below summarizes our major contract information associated with our facilities (including our equity investment) as of December 31, 2014:



Facility	Type of Services	Type of Contracts⁽¹⁾	Contract Volumes	Major Customers	Weighted Average Remaining Contract Terms (in years)
North-South Facilities	Transportation	Firm	457 MMcf/d	Southwestern Energy, Anadarko Energy Services Company (Anadarko), Chesapeake, Cabot Oil, Mitsui & Co., Ltd. (Mitsui)	4
MARC I Pipeline	Transportation	Firm	645 MMcf/d	Chesapeake Energy, Statoil Natural Gas, Anadarko, Mitsui, Sequent Energy Management (Sequent)	6
East Pipeline	Transportation	Firm	30 MMcf/d	NY State Electric & Gas Corp	6
Stagecoach	Storage	Firm	21.4 Bcf	Consolidated Edison of NY, New Jersey Natural Gas, Repsol Energy North America Corporation (Repsol), Sequent	3
Thomas Corners	Storage	Firm	5.7 Bcf	Repsol, Tenaska Gas Storage, LLC, Emera Inc.	2
Seneca Lake	Storage	Firm	1.5 Bcf	Dominion Transmission Inc., NY State Electric & Gas Corp, DTE Energy Trading	3
Steuben	Storage	Firm	6.2 Bcf	PSEG Energy Resources & Trade LLC, Repsol, Pivot Utility Holdings	3
Tres Palacios⁽²⁾	Storage	Firm	23.5 Bcf	Brookfield, Anadarko, Repsol, Koch Energy Services LLC, MGI	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.

NGL and Crude Services

The operations comprising our NGL and crude segment primarily include our proprietary NGL supply and logistics business, crude oil rail terminals, the Arrow gathering system, our fleet of over-the-road crude oil and produced water transportation assets, NGL storage facilities, and US Salt, LLC (US Salt).

Proprietary NGL Supply and Logistics. Our proprietary NGL supply and logistics business utilizes assets under our ownership or control to effectively provide supply “flow assurance” to producers, refiners and other customers. We are able to offer services that ensure uninterruptible NGL supply flows at attractive economic values by optimizing a portfolio of NGL processing, storage, and transportation assets. These assets consist primarily of:


•	our fleet of rail and rolling stock, 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

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take-away options. We separate NGLs from natural gas, deliver to local natural gas pipelines, and retain NGLs for 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;

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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 Teppo pipeline, allowing pipeline and truck access. The Bath storage facility (owned by Crestwood Midstream) 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.

COLT Hub. The COLT Hub consists of our integrated crude oil loading and storage terminals and interconnecting pipeline facilities located in the heart of the Bakken and Three Forks Shale oil-producing areas in Williams County, North Dakota. It has 1.1 million barrels of crude oil working storage capacity and is capable of loading up to 160,000 Bbls/d utilizing two 8,700-foot rail loops and three release and depart tracks that can accommodate 120-car unit trains. 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 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.

Arrow. The Arrow system gathers crude oil, rich natural 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. The system, which is located approximately 60 miles southeast of the COLT Hub, connects to our COLT Hub through the Hiland and Tesoro crude oil pipeline systems. The Arrow system includes approximately 540 miles of gathering lines (including approximately 170 miles of crude oil gathering pipeline, 200 miles of natural gas gathering pipeline, and 170 miles of produced water gathering lines), a 23-acre central delivery point with multiple pipeline take-away outlets and a fully-automated truck loading facility, and salt water disposal wells. Our operations are anchored by long-term, primarily fee-based gathering contracts with blue-chip producers who have dedicated over 150,000 acres to the Arrow system, and our underlying contracts provide for fixed-fee gathering services with annual escalators for crude oil, natural gas and produced water gathering services.

Crude Oil Transportation Fleet. Our over-the-road crude oil transportation fleet consists of approximately 82 tractors, 107 trailer tanks, 22 double bottom body tanks and 17 service vehicles with 48,000 Bbls/d of crude oil and produced water transportation capacity. We acquired most of these assets through our acquisition of substantially all of the operating assets of two trucking companies, LT Enterprises, Inc. and Red Rock Transportation, Inc. in the first half of 2014. We operate our transportation fleet out of Watford City, North Dakota, and we provide hauling services primarily to the oilfields of western North Dakota and eastern Montana.

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.

PRBIC. Our NGL and crude services segment also includes our approximate 50% interest in Powder River Basin Industrial Complex, LLC (PRBIC), which we account for under the equity method of accounting. PRBIC owns an early stage crude oil rail terminal located in Douglas County, Wyoming that supports crude oil volumes produced within the PRB Niobrara. The rail loading terminal, which we jointly own with Enserco Midstream LLC, is capable of loading up to 20,000 Bbls/d utilizing two rail loops that can accommodate unit trains. The terminal also has 140,000 barrels of crude oil working storage capacity. See Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in PRBIC.

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The table below summarizes our major contract information associated with the Arrow system and the COLT Hub as of December 31, 2014:



Facility	Type of Services	Type of Contracts⁽¹⁾	Gross Acreage Dedication	Volumes⁽²⁾	Major Customers	Weighted Average Remaining Contract Terms (in years)
Arrow	Gathering - crude oil, natural gas and water	Fixed-fee	150,000	—	WPX Energy, Whiting Petroleum Corporation, Halcon Resources Corporation, XTO Energy Inc., QEP Resources, Inc. and Enerplus Corporation	5
COLT	Rail Loading	Fixed-fee	—	149,300 Bbl/d	Tesoro, U.S. Oil, BP, Sunoco Inc., Statoil Inc	3


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


(2)	There is no contracted volume associated with Arrow's fixed-fee contracts due to the nature of those contracts.

Growth Projects

Gathering and Processing

In January 2015, the Bucking Horse processing plant was completed and placed into service. We anticipate expanding the Jackalope gathering system over the next several years and are actively working with area producers to develop additional gathering and processing facilities beyond our Jackalope acreage in the region. The completion of the Bucking Horse processing plant adds a substantial component to our portfolio of fee-based contracts and provides additional opportunities for long-term infrastructure development as production from emerging PRB Niobrara continues to increase.

Storage and Transportation

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

MARC I. We have executed a precedent agreement with a shipper to provide for a new supply interconnect with Williams. In conjunction with this new supply interconnect, we will expand our delivery meter into Transco by over 250 MMcf/d. We will conduct an open season for this project in the first quarter of 2015.

MARC II. In October 2014, we conducted a non-binding open season for the MARC II Pipeline, a 30-mile greenfield natural gas pipeline designed to transport Marcellus dry gas to northeastern demand markets. As proposed, the MARC II Pipeline would transport natural gas volumes approximately 30 miles from the southern terminus of our MARC I Pipeline to the proposed PennEast Pipeline, a new interconnect on Transco's Leidy Line, and Transco’s proposed Atlantic Sunrise Expansion Project in Luzerne County, Pennsylvania. We received non-binding expressions of interest for firm transportation service on the MARC II Pipeline in excess of 700 MMcf/d. Subject to FERC authorization, sufficient binding shipper commitments, and certain other factors beyond our control, we anticipate an in-service date for the MARC II Pipeline in the fourth quarter of 2017.

NGL and Crude Services

Arrow. We are continuing to build out the Arrow gathering system to its total design capacity of 125,000 Bbls/d of crude oil gathering, 100 MMcf/d of gas gathering, and 40,000 Bbls/d of produced water gathering. Given that the Arrow system was designed and constructed to handle significantly greater volumes than those flowing today and that our producer customers are responsible for the costs of connecting their wells to our system, we expect to complete the Arrow system build-out to reach targeted operational throughput capacities with modest organic capital requirements by the end of 2015. We are also constructing a 200,000 barrel crude oil storage tank at the Arrow central delivery point, which we expect to complete and place into service by the third quarter of 2015. The new storage tank, which is expected to cost approximately $16 million, is commercially supported by a take-or-pay storage agreement for 50% of the tank's working storage capacity.

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COLT Hub. In 2014, we expanded our COLT Hub to increase our crude oil throughput and storage capacities. The expansion primarily included the installation of additional crude oil loading arms and pumps at our rail loading rack; the construction of parallel rail tracks on which we will be able to store additional unit trains; the construction of two floating-roof crude oil storage tanks; the construction of additional truck unloading racks; and, modifications that enable us to receive more crude oil from interconnected gathering systems. The expansion increased our unit train loading capacity to 160,000 Bbls/d, our truck unloading capacity to 96,000 Bbls/d, our working storage capacity to 1.1 million barrels, and our input capacity from third-party gathering systems to approximately 105,000 Bbls/d. We have entered into customer contracts that supported a substantial portion of our capital investment.

NGL Storage Project. We are developing an NGL storage facility in Schuyler County, New York. We have requested from the New York State Department of Environmental Conservation (NYSDEC) the permits necessary to store up to 2.1 million barrels of propane and butane in underground caverns created by US Salt’s solution-mining process. Following an issues conference scheduled in mid-February 2015, an Administrative Law Judge will determine whether any significant issues remain open that must be addressed in an adjudicatory hearing. We continue to believe the NYDEC will issue the permit required for us to construct, own and operate the proposed storage facility. We have recorded approximately $38 million of costs in property, plant and equipment and $66 million of goodwill related to this NGL storage facility as of December 31, 2014. We estimate that the remaining capital required to complete the proposed storage project is approximately $20 million.

Customers

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. For the year ended December 31, 2012, Quicksilver and Antero accounted for approximately 47% and 11% of our total consolidated revenues.

Industry Background

The midstream sector of the energy industry provides the link between exploration and production and the delivery of crude oil, natural gas and their components to end-use markets. The midstream sector consists generally of gathering, processing, storage, and transportation activities. We 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 280 million metric tons of salt were produced in the world in 2012. 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 proprietary 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.

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 subsidiaries (CNYOG 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) CNYOG, the owner of the Stagecoach facility, the North-South Facilities and the MARC I Pipeline, and (ii) Arlington Storage, the owner of the Thomas Corners, Seneca Lake and Steuben facilities. CNYOG and Arlington Storage are authorized to charge and collect market-based rates for storage services, and CNYOG 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 CNYOG or Arlington Storage could have an adverse impact on our revenues.

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 NYSDEC has jurisdiction over well drilling, conversion and plugging in New York. The NYDEC 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

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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.

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.

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. We continue to pursue the state regulatory permits required to construct our proposed Finger Lakes NGL storage facility near Watkins Glen, New York but we cannot predict with certainty if and when the permitting process will be concluded.

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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 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.

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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 January 29, 2014, the Internal Revenue Service (IRS) issued a Notice of Beginning of Administrative Proceeding (NBAP) to us stating that the IRS is commencing an examination of our 2011 partnership tax return. A copy of the NBAP is available on our website at www.crestwoodlp.com. This is a routine compliance examination of various items of partnership income, gain, deductions, losses and credits. The examination is in progress, and it is currently not known whether the IRS will propose any adjustments to the 2011 tax return, whether such adjustments would be material, or how such adjustments would affect unitholders.

We are cooperating with the IRS examiners auditing this return. Unitholders should consult their tax advisers if they have any questions.

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;


•	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

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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.

In 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. In October 2014, we received certain data requests from the EPA related to the releases. We responded to the EPA's request for information on January 30, 2015. 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.

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, and, in December 2014, the EPA published a proposed rulemaking that it expects to finalized by October 1, 2015 that would seek to reduce the National Ambient Air Quality Standard for ozone to between 65 and 70 parts per billion for both the 8-hour primary and secondary standards. 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.

Employees

As of January 30, 2015, we had 1,374 full-time employees, 298 of which were general and administrative employees and 1,076 of which were operational. As of January 30, 2015, US Salt had 130 employees, 96 of which are members of a labor union. We believe that our relationship with our employees (including union labor) is satisfactory.

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, 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. 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, 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, and a major factor impacting oil and gas supplies has been the significant growth in unconventional sources such as shale plays. 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. The level and speed of the recovery from the recent recession remains uncertain and could impact the supply and demand for natural gas and our future rate of growth in our business;


•	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 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 high commodity prices would likely place upward pressure on the costs of associated expansion activities. An extended period of low commodity prices could adversely impact storage and transportation values for some period of time until market conditions adjust. 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 we do not complete growth projects or make acquisitions.

Our business strategy depends on our ability to complete growth projects and make acquisitions that increase cash generated from operations on a per unit basis. We may be unable to complete successful, accretive growth projects or acquisitions 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 cannot raise financing for such projects or acquisitions on economically acceptable terms;


•	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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The growth projects and acquisitions we complete may not perform as anticipated.

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

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

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

We generate a substantial portion of our gathering revenue from a limited number of oil and gas producers. Within our G&P segment, the top two producers (Antero in the Marcellus Shale and Quicksilver in the Barnett Shale) accounted for approximately 3% and 2% of our total consolidated revenues in 2014, respectively. Within our NGL and crude services segment, five producers primarily on our Arrow system in the Bakken Shale accounted for approximately 34% of our total consolidated revenues in 2014. Given the current commodity price environment and its anticipated impact on shale production, we expect our gathering earnings to remain leveraged to a limited number of producers in 2015 as we continue to build out our gathering systems, particularly in the Marcellus, Bakken and PRB Niobrara. Because we depend on a limited number of customers, a loss of a significant customer or failure to perform by a significant customer could cause a significant decline in our revenues. In particular, in February 2015, Quicksilver announced its decision not to make an interest payment due under its indenture and to enter into a 30-day grace period under the applicable indenture. This could result in an event of default under the indenture, which could lead Quicksilver to seek voluntary protection under Chapter 11 of the United States Bankruptcy Code.

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

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

Sustained low natural gas, NGL or crude oil prices impact natural gas and oil exploration and production activity levels and can result in a decline in the production of hydrocarbons over time, resulting in reduced throughput on our systems and terminals. 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. For example, market prices for natural gas has declined substantially since 2008 and have remained low for several years. More recently, the increased supply resulting from the rapid development of shale plays throughout North America has contributed significantly to the rapid decline in crude oil prices.

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 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.

Our NGL supply and logistics businesses 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.

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

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

We have limited experience in the crude oil gathering business.

We acquired the Arrow gathering system in November 2013, which serves customers producing crude oil and rich gas from the Bakken Shale formation. The Arrow system is the first crude oil and produced water gathering system that we have been required to build out and operate. Other operators of gathering systems in the Bakken have more experience in the construction, operation and maintenance of crude oil gathering systems than we do. Our lack of experience may hinder our ability to fully implement our business plan in a timely and cost-effective manner, which may adversely affect our results of operations and ability to make distributions.

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 $2.4 billion of long-term debt outstanding as of December 31, 2014. 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:

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


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


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


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

We have a $495 million revolving credit facility that matures in July 2016. Our revolving credit facility will be available to fund working capital and our growth projects, make acquisitions and for general partnership purposes. Crestwood Midstream has a $1 billion revolving credit facility (expandable up to $1.25 billion) that matures in October 2018. Crestwood Midstream’s revolving credit facility will be available to fund working capital and its growth projects, make acquisitions and for general partnership purposes.

Our revolving credit facilities contain various covenants and restrictive provisions that will limit our ability to, among other things:


•	incur additional debt;


•	make distributions on or redeem or repurchase units;


•	make 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 facilities contain covenants requiring us to maintain certain financial ratios. For example, (i) our revolving credit facility requires maintenance of a consolidated leverage ratio (as defined in our credit agreement) of no greater than 5.50 to 1.0 for the quarter ended December 31, 2014, 5.25 to 1.0 for the quarter ended March 31, 2015, 5.00 to 1.0 for the quarter ended June 30, 2015, and 4.75 to 1.0 for the quarter ended September 30, 2015 and all subsequent quarters; (ii) our interest coverage ratio (as defined in our credit agreement) should not be less than 2.50 to 1.00, and (ii) Crestwood Midstream’s credit facility requires maintenance of a consolidated leverage ratio (as defined in its credit agreement) of not more than 5.00 to 1.00 (and, if applicable, 5.50 to 1.0 during certain periods immediately following a material acquisition) and an interest coverage ratio (as defined in its credit agreement) of not less than 2.50 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 and personal property. Borrowings under

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Crestwood Midstream’s revolving credit facility are secured by pledges of the equity interests of, and guarantees by, substantially all of its restricted domestic subsidiaries, and liens on substantially all of its real property (outside of New York) and personal property.

The provisions of our credit agreements 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 facilities could result in events of default, which could enable our lenders, subject to the terms and conditions of credit agreements, 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 (and, with respect to Crestwood Midstream’s revolver, Crestwood Midstream’s 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 facilities.

Our credit agreements contain provisions relating to change of control of our general partners and our partnerships. If these provisions are triggered, our outstanding bank 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 our revolving credit facilities would have the right to foreclose on our assets, which would have a material adverse effect on us. There is no restriction on the ability of our general partner or its parent companies to enter into a transaction which would trigger the change of control provisions, and there are no restrictions on our ability to enter into a transaction which would trigger Crestwood Midstream’s change of control provisions.

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, each of the Crestwood Equity and Crestwood Midstream have used cash flow from operations, borrowings under its respective revolving credit facility and issuances of debt or equity to fund their respective capital programs, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our respective 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 operation, 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 any of these executives, or the loss of key field employees operating in competitive markets like the Bakken Shale and the Marcellus Shale, 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.

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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 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, 2014, the weighted average remaining term of (i) our consolidated portfolio of natural gas storage and transportation contracts is approximately three years, (ii) our consolidated portfolio of natural gas gathering contracts is approximately 11 years, and (iii) our consolidated portfolio of crude oil gathering contracts is approximately five 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.

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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 FERC, are found to be unjust and unreasonable or unduly discriminatory. Existing interstate transportation and storage rates may be challenged by complaint and are subject to prospective change by FERC. Additionally, rate increases proposed by a regulated pipeline or storage provider may be challenged and such increases may ultimately be rejected by FERC. We currently hold authority from 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. 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 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 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

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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 or otherwise relating to environmental protection. Such environmental laws and regulations impose numerous obligations that are applicable to our operations, including the acquisition of permits to conduct regulated activities, the incurrence of capital expenditures to comply with applicable legal requirements, the application of specific health and safety criteria addressing worker protections and the imposition of restrictions on the generation, handling, treatment, storage, disposal and transportation of materials and wastes. Failure to comply with such environmental laws and regulations can result in the assessment of substantial administrative, civil and criminal penalties, the imposition of remedial liabilities and the issuance of injunctions restricting or prohibiting some or all of our activities. Certain environmental laws impose strict, joint and several liability for costs required to clean up and restore sites where materials or wastes have been disposed or otherwise released. In the course of our operations, generated materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for recycling or disposal.

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

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 greenhouse gases 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 greenhouse gases 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 greenhouse gas 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 December 9, 2014, the EPA published a proposed rule that would expand the petroleum and natural gas system sources for which annual GHG emissions reporting is currently 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

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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.

The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased 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. Consequently, legislation and 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, the 2011 Pipeline Safety Act is the most recent federal legislation to amend the NGPSA and HLPSA pipeline safety laws, requiring increased safety measures for gas and hazardous liquids pipelines. Among other things, the 2011 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 us, leak detection system installation, testing to confirm the material strength of certain pipelines and operator verification of records confirming the maximum allowable pressure of certain instrastate 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 PHMSA has also published an advanced notice of proposed rule making to solicit comments on the need for changes to its safety regulations, including whether to revise the integrity management requirements and add new regulations governing the safety of gathering lines. Most recently, in an August 2014 report to Congress from the U.S. Government Accountability Office, the agency acknowledged PHMSA's continued assessment of these pipeline safety risks and recommended that PHMSA move forward with rulemaking to address larger-diameter, higher-pressure gathering lines, including subjecting such pipelines to emergency response planning requirements that currently do not apply. Such legislative and regulatory changes could have a material effect on our operations through more stringent and comprehensive safety regulations and higher penalties for the violation of those regulations.

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;


•	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.

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These risks could result in substantial losses due to breaches of contractual commitments, personal injury and/or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage. For example, we experienced three releases on our Arrow water gathering system during 2014 that resulted in a spill of an estimated 28,000 barrels of produced water 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 its pipelines on land owned by third parties, and our rights frequently revert back to the landowner after we stop using the easement for its specified purpose.

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

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

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

Risks Inherent in an Investment in Us

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

We may not have sufficient cash each quarter to pay quarterly distributions to our common unitholders. 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. Before we pay any distributions on our 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.

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


•	the amount of cash distributions we receive in connection with our ownership of 100% of Crestwood Midstream’s IDRs and 4% of its common units;

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•	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; and


•	the cost of acquisitions.

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; the cost of acquisitions; 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 and make acquisitions.

We expect that we will distribute all of our available cash to our common unitholders and will rely primarily upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. As a result, to the extent we are unable to finance growth externally, our cash distribution policy will significantly impair our ability to grow.

In addition, because we distribute all of our available cash, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we issue additional units in connection with any acquisitions or expansion capital expenditures, the payment of distributions on those additional units may increase the risk that we will be unable to maintain or increase our per unit distribution level. 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 common unitholders.

We may issue additional units without common unitholder approval, which would dilute existing common unitholder 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.

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

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

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

The amount of cash we have available for distribution to common unitholders depends primarily on our cash flow 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 (the majority of which consists of the cash distributions we receive in connection with our ownership of 100% of Crestwood Midstream’s IDRs), 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.

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 common units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units.

As of December 31, 2014, Crestwood Holdings and its affiliates beneficially held an aggregate of 53,809,398 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.

Risks Inherent in Our Structure and Relationship with Crestwood Midstream

Our primary cash-generating assets are our partnership interests, including incentive distribution rights, in Crestwood Midstream, and our cash flow is therefore materially dependent upon the ability of Crestwood Midstream to make distributions in respect to those partnership interests to its partners.

The amount of cash that Crestwood Midstream can distribute to its unitholders each quarter, including us with respect to our IDRs, principally depends upon the amount of cash Crestwood Midstream generates from its operations, which amounts of cash may fluctuate from quarter to quarter based on, among other things:

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•

the rates Crestwood Midstream charges for services and the amount of services their customers purchase from Crestwood Midstream, which will be affected by, among other things, the overall balance between the supply of and demand for natural gas, NGL and crude oil, governmental regulation of Crestwood Midstream’s rates and services, and Crestwood Midstream’s ability to obtain permits for growth projects;


•	force majeure events that damage Crestwood Midstream’s or third-party pipelines, facilities, related equipment and surrounding properties;


•	prevailing economic and market conditions;


•	governmental regulation, including changes in governmental regulation in Crestwood Midstream’s industry;


•	leaks or accidental releases of products or other materials into the environment, whether as a result of human error or otherwise;


•	difficulties in Crestwood Midstream collecting receivables because of its customers’ credit or financial problems;


•	changes in tax laws;


•	the level of competition from other midstream energy companies;


•	the level of Crestwood Midstream’s operating and maintenance and general administrative costs;


•	the level of capital expenditures Crestwood Midstream makes;


•	the ability of Crestwood Midstream to make borrowings under its revolving credit facility; and


•	the cost of acquisitions.

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

We do not have control over many of these factors, including the level of cash reserves established by the board of directors of Crestwood Midstream’s general partner. Accordingly, we cannot guarantee that Crestwood Midstream will have sufficient available cash to pay a specific level of cash distributions to its partners.

If Crestwood Midstream reduced its per unit distribution, we would have less cash available for distribution and would probably be required to reduce our per unit distribution. Furthermore, the amount of cash that Crestwood Midstream has available for distribution depends primarily upon its cash flow, including cash flow from financial reserves and working capital borrowings, and is not solely a function of profitability, which will be affected by non-cash items. As a result, Crestwood Midstream may be able to make cash distributions during periods when it records losses and may not be able to make cash distributions during periods when it records net income.

To the extent we purchase additional securities from Crestwood Midstream, our rate of growth may be reduced.

Our business strategy may include supporting the growth of Crestwood Midstream by purchasing its securities or lending funds to Crestwood Midstream to provide funding for acquisitions or internal growth projects. To the extent we purchase common units, the rate of our distribution growth may be reduced, at least in the short term, as less of our cash distributions will come from our ownership of Crestwood Midstream’s IDRs, which distributions increase at a faster rate than those of our other securities.

We could have an indemnification obligation to Crestwood Midstream, which could materially adversely affect our financial condition.

We have entered into an omnibus agreement with Crestwood Midstream and its general partner that governs certain aspects of our relationship with them. Pursuant to the omnibus agreement, we are generally obligated to indemnify Crestwood Midstream and its affiliates against certain liabilities of the assets of the operations of Crestwood Midstream prior to December 21, 2011. See “Certain Relationships and Related Party Transactions-Omnibus Agreement.” Our indemnification obligations under the omnibus agreement could result in substantial expenses and liabilities to us, which could materially adversely affect our financial condition.

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

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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 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.

Cost reimbursements paid to our general partner may be substantial and may reduce our ability to pay the quarterly distribution.

Before making any distributions on our units, we will reimburse our general partner for all expenses it has incurred on our behalf. In addition, our general partner and its affiliates may provide us with services for which we will be charged reasonable fees as determined by our general partner. The reimbursement of these expenses and the payment of these fees could adversely affect our ability to make distributions our unitholders. Our general partner has sole discretion to determine the amount of these expenses and fees.

We may issue additional common units without unitholder approval, which would dilute our unitholders’ existing ownership interests.

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. The issuance of additional common units or other equity securities of equal rank will have the following effects:


•	the proportionate ownership interest of our existing unitholders in us will decrease;


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


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


•	the market price of the common units or partnership securities may decline.

Crestwood Midstream may issue additional common units, which may increase the risk that it will not have sufficient available cash to maintain or increase its per unit distribution level.

The Crestwood Midstream partnership agreement allows it to issue an unlimited number of additional limited partner interests. The issuance of additional common units or other equity securities by Crestwood Midstream will have the following effects:


•	Our unitholders’ current proportionate ownership interest in Crestwood Midstream will decrease;


•	the amount of cash available for distribution on each common unit or partnership security 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 Crestwood Midstream’s common units may decline.

The payment of distributions on any additional units issued by Crestwood Midstream may increase the risk that Crestwood Midstream may not have sufficient cash available to maintain or increase its per unit distribution level, which in turn may impact the available cash that we have to meet our obligations.

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If we cease to manage and control Crestwood Midstream in the future, we may be deemed to be an investment company under the Investment Company Act of 1940.

If we cease to manage and control Crestwood Midstream and are deemed to be an investment company under the Investment Company Act of 1940 (the Investment Company Act) we would either have to register as an investment company under the Investment Company Act, obtain exemptive relief from the Securities and Exchange Commission or modify our organizational structure or our contract rights to fall outside the definition of an investment company. Registering as an investment company could, among other things, materially limit our ability to engage in transactions with affiliates, including the purchase and sale of certain securities or other property to or from our affiliates, restrict our ability to borrow funds or engage in other transactions involving leverage and require us to add additional directors who are independent of us or our affiliates.

Moreover, treatment of us as an investment company would prevent our qualification as a partnership for federal income tax purposes, in which case we would be treated as a corporation for federal income tax purposes. For further discussion of the importance of our treatment as a partnership for federal income tax purposes and the implications that would result from our treatment as a corporation in any taxable year, please read the risk factor below entitled “The tax treatment of publicly traded partnerships is subject to potential legislative, judicial or administrative changes. If we or Crestwood Midstream were treated as a corporation for federal income tax purposes, or if we or Crestwood Midstream were to become subject to a material amount of state or local taxation, then our cash available for distribution to our unitholders would be substantially reduced.

Although we control Crestwood Midstream through our ownership of its general partner, Crestwood Midstream’s general partner owes fiduciary duties to Crestwood Midstream’s unitholders, which may conflict with our interests.

Conflicts of interest exist and may arise in the future as a result of the relationships between us and our affiliates, on the one hand, and Crestwood Midstream and its limited partners, on the other hand. The directors and officers of Crestwood Midstream’s general partner have fiduciary duties to manage Crestwood Midstream in a manner beneficial to us. At the same time, Crestwood Midstream’s general partner has fiduciary duties to manage Crestwood Midstream in a manner beneficial to Crestwood Midstream and its limited partners. The board of directors of Crestwood Midstream’s general partner will resolve any such conflict and has broad latitude to consider the interests of all parties to the conflict. The resolution of these conflicts may not always be in our best interest.

For example, conflicts of interest with Crestwood Midstream may arise in the following situations:


•	the allocation of shared overhead expenses to Crestwood Midstream and us;


•	the interpretation and enforcement of contractual obligations between us and our affiliates, on the one hand, and Crestwood Midstream, on the other hand;


•	the determination of the amount of cash to be distributed to Crestwood Midstream’s limited partners and the amount of cash to be reserved for the future conduct of Crestwood Midstream’s business; and


•	the determination whether to make borrowings under Crestwood Midstream’s revolving credit facility to pay distributions to Crestwood Midstream’s limited partners.

The fiduciary duties of our general partner’s officers and directors may conflict with those of Crestwood Midstream’s general partner.

Conflicts of interest may arise because of the relationships among Crestwood Midstream, its general partner and us. Our general partner’s directors and officers have fiduciary duties to manage our business in a manner beneficial to us and our unitholders. Some of our general partner’s directors and officers are also directors and officers of Crestwood Midstream’s general partner, and have fiduciary duties to manage the business of Crestwood Midstream in a manner beneficial to Crestwood Midstream and its unitholders. The resolution of these conflicts may not always be in our best interest or that of our unitholders.

Affiliates of our general partner are not prohibited from competing with us.

Our partnership agreement provides that our general partner will be restricted from engaging in any business activities other than acting as our general partner and those activities incidental to its ownership of interests in us. Except as provided in our partnership agreement, affiliates of our general partner are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us.

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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, including Crestwood Midstream and its affiliates and any general partner and limited partnerships acquired in the future, 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, 2014, the directors and executive officers of our general partner owned approximately 12% of our common units.

Our cash distribution policy limits our ability to grow.

Because we distribute all of our available cash, our growth may not be as rapid as businesses that reinvest their available cash to expand ongoing operations. If we issue additional units or incur debt to fund acquisitions and growth capital expenditures, the payment of distributions on those additional units or interest on that debt could increase the risk that we will be unable to maintain or increase our per unit distribution level.

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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 or Crestwood Midstream 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. The value of our investment in Crestwood Midstream depends largely on Crestwood Midstream being treated as a partnership for federal income tax purposes. Despite the fact that we and Crestwood Midstream are each organized as a limited partnership under Delaware law, we and Crestwood Midstream would each 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 and Crestwood Midstream each believe we satisfy the qualifying income requirement.

Failing to meet the qualifying income requirement or a change in current law could cause us or Crestwood Midstream to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. If we or Crestwood Midstream were treated as a corporation for U.S. federal income tax purposes, we each 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 and Crestwood Midstream’s 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 or Crestwood Midstream as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our respective common unitholders, likely causing a substantial reduction in the value of our common units.

Our partnership agreement, as well as that of Crestwood Midstream, 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 or Crestwood Midstream’s unitholders.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us and Crestwood Midstream, or an investment in our or Crestwood Midstream’s 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 2016 recommends that certain publicly traded partnerships earning income from activities related to fossil fuels be taxed as corporations beginning in 2021. From time to time, members of 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 and Crestwood Midstream rely for our treatment as a partnership for U.S. federal income tax purposes.

Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us or Crestwood Midstream 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 or Crestwood Midstream’s common units.

If the IRS contests the federal income tax positions we take, the market for our common units may be adversely impacted and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

Neither we nor Crestwood Midstream has 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

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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.

You will be required to pay taxes on your share of our income 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.

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.

We and Crestwood Midstream will treat each purchaser of our respective 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 Crestwood Midstream’s and our common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we and Crestwood Midstream 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 Crestwood Midstream’s common units and our common units and could have a negative impact on the value of our respective 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 use of this proration method may not be permitted under existing Treasury Regulations. The U.S. Treasury Department has issued proposed Treasury Regulations that provide a safe harbor pursuant to which a publicly-traded partnership may use a similar monthly simplifying convention to allocate tax items among transferor and transferee unitholders. Nonetheless, the proposed regulations do not specifically authorize the use of the proration method we have adopted. 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.

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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.

Seymour Investigation. 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. Although we have not received a compliance order or settlement agreement from the EPA, we anticipate that the EPA will assess a civil penalty against us and the amount could exceed $100,000.

Item 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.

Our 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
2014
December 31, 2014	$	5.84	$	10.73	$	0.1375
September 30, 2014	10.55		15.40		0.1375
June 30, 2014	12.85		15.04		0.1375
March 31, 2014	12.41		14.51		0.1375
2013
December 31, 2013	$	11.83	$	15.30	$	0.1375
September 30, 2013	12.59		16.89		0.135
June 30, 2013	13.55		25.34		0.130
March 31, 2013	18.42		20.91		0.290

The last reported sale price of our common units on the NYSE on February 13, 2015, was $7.09. As of that date, we had 187,349,776 common units issued and outstanding, which were held by 247 unitholders of record.

Cash Distribution Policy

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


•	provide for the proper conduct of our business;


•	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 working capital facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

On February 13, 2015, we paid a distribution of $0.1375 per limited partner unit $0.55 per limited partner unit on an annualized basis) to all unitholders of record on February 6, 2015.

Issuer Purchases of Equity Securities

For the year ended December 31, 2014, 159,435 common units were relinquished to us to cover payroll taxes upon the vesting of restricted units.

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Equity Compensation Plan Information

The following table sets forth in tabular format, a summary of equity compensation plan information as of December 31, 2014:



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	—	$	—	13,812,979
Total	—	$	—	13,812,979

Item 6. Selected Financial Data.

These 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, 2014 and balance sheet data as of December 31, 2014 and 2013 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, 2011 and the balance sheet data as of December 31, 2012, 2011 and 2010 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.

The following table summarizes our results for the years ended December 31, 2014, 2013, 2012 and 2011 and two periods in 2010: January 1, 2010 through September 30, 2010 (the Predecessor Period) and October 1, 2010 through December 31, 2010 (the Successor Period), which relate to the periods before and after Crestwood Holdings acquisition of Quicksilver’s ownership interest in Legacy Crestwood (the Crestwood Transaction).

EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company's operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. EBITDA is defined as income before income taxes, plus net interest and debt expense, and depreciation, amortization and accretion expense. In addition, Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates for our proportionate share of their depreciation and interest and the impact of certain significant items, such as unit-based compensation charges, gains and impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, change in fair value of certain commodity derivative contracts, and other transactions identified in a specific reporting period. EBITDA and Adjusted EBITDA are not measures calculated in accordance with GAAP, as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.

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	Crestwood Equity Partners LP Year Ended December 31, (in millions, except per unit data)
	Successor															Predecessor
	Year Ended December 31,												Period from October 1, 2010 to December 31, 2010			Period from January 1, 2010 to September 30, 2010
	2014			2013 (1)			2012			2011			Period from October 1, 2010 to December 31, 2010			Period from January 1, 2010 to September 30, 2010
Statement of Income Data:
Revenues	$	3,931.3		$	1,426.7		$	239.5		$	205.8		$	31.3		$	82.3
Operating income	117.9			28.2			61.4			71.0			5.8			37.5
Income (loss) before income taxes	(9.3		)	(49.6		)	25.6			43.4			1.1			28.7
Net income (loss)	(10.4		)	(50.6		)	24.4			42.1			1.8			28.6
Net income attributable to Crestwood Equity Partners LP	56.4			6.7			14.9			7.7			0.7			1.8

Performance Measures:
Diluted limited partner income per unit: ⁽²⁾
From net income	$	0.30		$	0.06		$	0.38		$	0.19		$	0.02		$	0.04

Distributions declared per limited partner unit⁽³⁾	$	0.55		$	0.6925		$	1.33		$	2.82		$	0.705		$	2.105

Other Financial Data:
EBITDA (unaudited)	$	403.1		$	196.2		$	134.6		$	124.9		$	16.0		$	54.2
Adjusted EBITDA (unaudited)	495.9			297.7			134.4			110.9			19.5			58.9
Net cash provided by operating activities	283.0			188.3			102.1			86.3			3.1			44.9
Net cash used in investing activities	(483.0		)	(1,042.9		)	(616.6		)	(456.5		)	(16.6		)	(132.7		)
Net cash provided by financing activities	203.6			859.7			513.8			371.0			13.4			87.2

Balance Sheet Data:
Property, plant and equipment, net	$	3,893.8		$	3,905.3		$	1,102.4		$	916.8		$	710.4		$	—
Total assets	8,461.4			8,523.2			2,301.6			1,739.2			1,303.1			—
Total debt, including current portion	2,396.5			2,266.0			685.2			512.5			283.5			—
Other long-term liabilities⁽⁴⁾	47.2			140.4			17.2			15.5			9.9			—
Partners' capital	5,584.5			5,508.6			1,550.7			1,120.0			926.0			—

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	Successor															Predecessor
	Year Ended December 31,												Period from October 1, 2010 to December 31, 2010			Period from January 1, 2010 to September 30, 2010
	2014			2013			2012			2011			Period from October 1, 2010 to December 31, 2010			Period from January 1, 2010 to September 30, 2010
Reconciliation of Net Income to EBITDA and Adjusted EBITDA:
Net income (loss)	$	(10.4	)	$	(50.6	)	$	24.4		$	42.1		$	1.8		$	28.6
Depreciation, amortization and accretion	285.3			167.9			73.2			53.9			10.2			16.7
Interest and debt expense, net	127.1			77.9			35.8			27.6			4.7			8.8
Provision (benefit) for income taxes	1.1			1.0			1.2			1.3			(0.7		)	0.1
EBITDA	$	403.1		$	196.2		$	134.6		$	124.9		$	16.0		$	54.2
Unit-based compensation charges	21.3			17.4			1.9			0.9			3.5			2.0
(Gain) loss on long-lived assets, net⁽⁵⁾	1.9			(5.3		)	—			(1.1		)	—			—
Goodwill impairment⁽⁶⁾	48.8			4.1			—			—			—			—
(Gain) loss on contingent consideration⁽⁷⁾	8.6			31.4			(6.8		)	(17.2		)	—			—
(Earnings) loss from unconsolidated affiliates, net	0.7			0.1			—			—			—			—
Adjusted EBITDA from unconsolidated affiliates, net	6.9			2.5			—			—			—			—
Change in fair value of commodity inventory-related derivative contracts	(10.3		)	10.7			—			—			—			—
Significant transaction and environmental-related costs and other items⁽⁸⁾	14.9			40.6			4.7			3.4			—			2.7
Adjusted EBITDA	$	495.9		$	297.7		$	134.4		$	110.9		$	19.5		$	58.9

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	Successor															Predecessor
	Year Ended December 31,												Period from October 1, 2010 to December 31, 2010			Period from January 1, 2010 to September 30, 2010
	2014			2013			2012			2011			Period from October 1, 2010 to December 31, 2010			Period from January 1, 2010 to September 30, 2010
Reconciliation of Net Cash Provided by Operating Activities to EBITDA and Adjusted EBITDA:
Net cash provided by operating activities	$	283.0		$	188.3		$	102.1		$	86.3		$	3.1		$	44.9
Net changes in operating assets and liabilities	73.8			(19.6		)	(4.1		)	(4.2		)	13.1			5.8
Amortization of debt-related deferred costs, discounts and premiums	(8.5		)	(9.2		)	(5.5		)	(3.5		)	(0.7		)	(0.6		)
Interest and debt expense, net	127.1			77.9			35.8			27.6			4.7			8.8
Market adjustment on interest rate swaps	2.7			1.7			—			—			—			—
Unit-based compensation charges	(21.3		)	(17.4		)	(1.9		)	(0.9		)	(3.5		)	(2.0		)
Gain (loss) on long-lived assets, net⁽⁵⁾	(1.9		)	5.3			—			1.1			—			—
Goodwill impairment⁽⁶⁾	(48.8		)	(4.1		)	—			—			—			—
Gain (loss) on contingent consideration⁽⁷⁾	(8.6		)	(31.4		)	6.8			17.2			—			—
Earnings (loss) from unconsolidated affiliates, net	(0.7		)	(0.1		)	—			—			—			—
Deferred income taxes	5.2			2.8			—			—			0.9			(0.1		)
Provision (benefit) for income taxes	1.1			1.0			1.2			1.3			(0.7		)	0.1
Other non-cash income	—			1.0			0.2			—			(0.9		)	(2.7		)
EBITDA	$	403.1		$	196.2		$	134.6		$	124.9		$	16.0		$	54.2
Unit-based compensation charges	21.3			17.4			1.9			0.9			3.5			2.0
(Gain) loss on long-lived assets, net⁽⁵⁾	1.9			(5.3		)	—			(1.1		)	—			—
Goodwill impairment⁽⁶⁾	48.8			4.1			—			—			—			—
(Gain) loss on contingent consideration⁽⁷⁾	8.6			31.4			(6.8		)	(17.2		)	—			—
(Earnings) loss from unconsolidated affiliates, net	0.7			0.1			—			—			—			—
Adjusted EBITDA from unconsolidated affiliates, net	6.9			2.5			—			—			—			—
Change in fair value of commodity inventory-related derivative contracts	(10.3		)	10.7			—			—			—			—
Significant transaction and environmental-related costs and other items⁽⁸⁾	14.9			40.6			4.7			3.4			—			2.7
Adjusted EBITDA	$	495.9		$	297.7		$	134.4		$	110.9		$	19.5		$	58.9


(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.


(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 2014, we recorded property, plant and equipment and intangible impairments of approximately $13.2 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 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)	Significant transaction and environmental-related costs and other items for the years ended December 31, 2014 and 2013, primarily include costs incurred related to the 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 expectation that we will grow our business through both organic growth projects and acquisitions; (ii) 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; (iii) our belief that we do not have material potential liability in connection with legal proceedings that would have a significant financial impact on our consolidated financial condition, results of operations or cash flows; and (iv) our belief that our assets, and Crestwood Midstream’s 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 crude oil, NGLs and natural gas;


•	interest rates; and


•	the price and availability of debt and equity financing.

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 are a master limited partnership that manages, owns and operates crude oil, natural gas and NGL midstream assets and operations. Headquartered in Houston, Texas, we are a fully-integrated midstream solution provider that specializes in connecting shale-based energy supplies to key demand markets. We manage and conduct a substantial portion of our operations through Crestwood Midstream, a growth-oriented MLP that owns and operates gathering, processing, storage, and transportation assets in the most prolific shale plays across the United States. We own the general partnership interest, IDRs and approximately 4% of the limited partner interests of Crestwood Midstream as of December 31, 2014.

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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 2.5 Bcf/d of gathering capacity, 481 MMcf/d of processing capacity, 1.1 Bcf/d of firm transmission capacity, and 41 Bcf of certificated working gas storage capacity;


•	NGL facilities with approximately 24,000 Bbls/d of fractionation capacity and 2.8 million barrels of storage capacity;


•	crude oil facilities with approximately 125,000 Bbls/d of gathering capacity, approximately 1.1 million barrels of storage working capacity, 48,000 Bbls/d of transportation capacity, and 160,000 Bbls/d of rail loading capacity; and


•	a fleet of transportation assets supporting our proprietary NGL supply and logistics business, including 8 truck and rail terminals and approximately 543 truck/trailer units and 1,600 rail units that can transport more than 294,000 Bbls/d of NGLs.

Our primary business objective is to increase the cash distributions that we pay to our unitholders. We expect to position Crestwood Midstream to increase its cash distributions by providing strong general partner support and using Crestwood Midstream as the primary vehicle through which we grow our midstream business. We intend to grow our business, safely through the development, acquisition and operation of additional midstream assets situated near developed and emerging shale resources and premium demand centers. We plan to increase Crestwood Midstream’s cash available for distribution through organic growth and increased operational efficiencies. We also anticipate growing our business through Crestwood Midstream’s strategic and bolt-on acquisitions, including asset contributions from us, with an emphasis on acquisitions that (i) facilitate our development of an integrated midstream platform that enables us to continue to expand the services we offer to customers in key geographic markets, and/or (ii) provide the scale we need to realize greater economies of scale (from cash flow, cost, credit and other perspectives) that translate into increased cash distributions to our unitholders. We also intend to grow our NGL and crude services business by leveraging our industry knowledge, expertise and operational experience to offer unparalleled takeaway solutions from the wellhead to the end user.

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

Gathering and Processing

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

Our G&P operations primarily include:


•	Marcellus Shale. We own and operate (i) a low-pressure natural gas gathering system with a gathering capacity of approximately 875 MMcf/d of rich gas produced by our customers in Harrison and Doddridge Counties, West Virginia; (ii) eight compression and dehydration stations located on our gathering systems in the East AOD; and (iii) two compressor stations located in the Western Area;


•	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, Somervell and Johnson Counties, Texas, which delivers the rich gas to our two processing plants where NGLs are extracted from the natural gas stream; and

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(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;

•

Other. 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); (ii) three low-pressure natural gas gathering systems with a gathering capacity of approximately 50 MMcf/d of rich gas produced by our customers in Eddy County, New Mexico (Avalon/Bone Springs system); and (iii) 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 Jackalope, which we account for under the equity method of accounting. In January 2015, the construction of the 120 MMcf/d Bucking Horse processing plant was completed and the plant was placed into service. We expect volumes through the Bucking Horse processing plant to significantly increase throughout the first quarter of 2015. In addition, the gathering system continues to expand with the most recent compression facility placed into service in January 2015. We are actively working with area producers to develop additional gathering and processing facilities beyond our Jackalope acreage in the region. The Jackalope system is supported by a 20-year gathering and processing agreement with Chesapeake and RKI under an area of dedication of approximately 311,000 gross acres located in the core of the PRB Niobrara. We funded a significant portion of our Jackalope purchase in July 2013 with the sale to GE of non-voting preferred equity securities in Crestwood Niobrara, our consolidated subsidiary. We consolidate Crestwood Niobrara's results in our financial statements, and we account for Crestwood Niobrara's 50% interest in Jackalope as an equity investment.

The cash flows from our G&P operations are predominantly fee-based with creditworthy counterparties under contracts with original terms ranging from 5-20 years. The results of our G&P operations are significantly influenced by the volumes of natural gas gathered and processed through our systems. We gather, process, treat, compress, transport and sell natural gas pursuant to fixed-fee and, to a lesser extent, percent-of-proceeds contracts. 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. 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 41 Bcf of firm storage capacity and more than 1.0 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.

The cash flows from our storage and transportation operations are predominantly fee-based with creditworthy counterparties 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.

In December 2014, we sold 100% of our membership interest in Tres Palacios to Tres Holdings LLC (Tres Holdings), a newly formed joint venture between Crestwood Midstream and an affiliate of Brookfield for total cash consideration of approximately $132.8 million, of which approximately $66.4 million was paid by Crestwood Midstream. Tres Palacios owns a 38.4 Bcf multi-cycle, salt dome storage facility. Its 60-mile, dual 24-inch diameter header system (including a 51-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. As a result of the sale, effective December 1, 2014, we deconsolidated Tres Palacios' operations. Crestwood Midstream owns a 50.01% interest in Tres Holdings and operates the Tres Palacios assets, and Brookfield owns the remaining 49.99% interest in Tres Holdings. We account for the investment in Tres Holdings under the equity method of accounting. In conjunction with the sale, Brookfield and Tres Palacios entered into a

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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 wheeling services available to Brookfield. We believe the Tres Palacios system is well positioned to capture meaningful natural gas revenue opportunities over the long run as the Texas Gulf Coast market recovers, as well as near term NGL storage and transportation opportunities designed to provide relief to existing constraints. For a further discussion of our investment in Tres Holdings, see Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 6.

NGL and Crude Services

Our NGL and crude services segment consists of our proprietary NGL and crude supply and logistics business, crude oil gathering systems and rail terminals, and US Salt. We have facilities located in and around some of the most prolific crude oil shales and premium demand markets in North America. We utilize these facilities to provide gathering, storage and terminal services to our anchor customers, and we utilize our crude oil and NGL assets on a portfolio basis to provide integrated supply and logistics solutions to producers, refiners and other customers.

Our NGL and crude services operations primarily include:

•

NGL Supply and Logistics Business. Our proprietary NGL supply and logistics business utilizes processing, storage and transportation assets under our ownership or control to effectively provide supply “flow assurance” to producers, refiners and other customers. We are able to offer services that ensure uninterruptible NGL supply flows at attractive economic values by optimizing our fleet of rail and rolling stock, rail-to-truck terminals, West Coast processing, fractionation and storage operations, NGL storage facilities, and leased storage capacity at major hubs;

•

Bakken Shale - Arrow. We own and operate substantial crude oil, natural gas and produced water gathering systems (the Arrow system) located on the Fort Berthold Indian Reservation in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota. The Arrow system consists of more than 540 miles of gathering pipeline, including approximately 170 miles of crude oil gathering lines, 200 miles of natural gas gathering lines and 170 miles of produced water gathering lines. We will have approximately 235,000 barrels of crude oil working storage capacity at the Arrow central delivery point after completion of the 200,000 barrel crude oil tank that is currently under construction;

•

Bakken Shale - 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 recent Arrow acquisition. Located approximately 60 miles away from Arrow’s central delivery point, the COLT Hub interconnects with the Arrow system through the Hiland Partners, LP (Hiland) and Tesoro Corporation (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 1.1 million barrels of crude oil working storage capacity;

•

Bakken Shale - Transportation Fleet. We own and operate an over-the-road 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. Our transportation fleet consists of approximately 82 tractors and 107 trailers with approximately 48,000 Bbls/d of crude oil and produced water transportation capacity. We purchased substantially all of these operating assets from Red Rock Transportation Inc. and LT Enterprises, Inc. during the first half of 2014;


•	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; and

•

PRB Niobrara Shale. We own a 50% ownership interest in PRBIC, which owns an early stage crude oil rail terminal in Douglas County, Wyoming. We account for our interest in PRBIC as an equity investment. The rail loading terminal, which we jointly own with Enserco Midstream LLC, is capable of loading up to 20,000 Bbls/d utilizing two rail loops that can accommodate unit trains. The terminal also has 140,000 barrels of crude oil working storage capacity. The terminal, which when completed will provide unit train takeaway-solutions for crude producers in the PRB Niobrara, is supported by a long-term contract with a major oil producer under which the producer has committed to deliver a minimum volume of crude oil to the rail facility for throughput.

The cash flows from our supply and logistics business (including our NGL processing, fractionation and storage facilities) 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 the Arrow operations are primarily fee-based with creditworthy counterparties under contracts with original terms ranging from

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5-10 years, and can be impacted in the short term by changing commodity prices, seasonality and weather fluctuations. The cash flows from our COLT Hub are predominantly fee-based with creditworthy counterparties under contracts with original terms ranging from 1- 7 years, and are generally economically stable and not significantly affected in the short term by changing commodity prices, seasonality or weather fluctuations. 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 long-term distribution growth will be influenced primarily by our ability to (and to cause Crestwood Midstream to) execute our growth strategy, including both growth projects and strategic acquisitions, and to increase cash available for distribution from the assets we own or control. An integral part of our growth strategy entails capitalizing on commercial synergies from the Crestwood Merger. We continue to expand the services from which we generate revenues from our gathering and processing customer base, and we anticipate generating increased cash flows as our producer customers rely on us for more integrated NGL and crude oil takeaway solutions and flow assurances. We also anticipate pursuing (through Crestwood Midstream) acquisitions that would not have been possible without the combined expertise and relationships resulting from the business combination. The continued integration of our gathering, processing, marketing, storage and transportation experience will be instrumental to our ability to derive such commercial synergies.

Despite the recent decline in commodity prices, we believe that we are well positioned in 2015 to continue the trend of consistent growth and improving financial results with limited operating risk due to our strategically-located assets in economic shale plays and the significant growth capital projects that we completed in 2014. We believe that we will have a conservative level of volume growth in 2015 resulting from the completion of our 2014 growth capital projects and from a substantial producer drilled-but-uncompleted well inventory and core-of-core acreage dedications in shale plays which allow many of our producers to continue to develop their properties even at current prices. Additionally, a substantial portion of our contracts in the Bakken Shale and PRB Niobrara Shale are take-or-pay or cost-of-service in nature, which we believe will help support our anticipated cash flow during 2015. Finally, we have implemented a company-wide initiative to reduce operating costs in 2015 to support more efficient operations in the current market environment.

Organic growth projects, including both expansions and greenfield development projects, can provide cost-effective options for us to grow our infrastructure base. The ongoing expansion of our Bakken assets, including the COLT Hub and the Arrow system, and continued build out of our PRB Niobrara system are examples of our ability to internally grow our operations at very low multiples. In general, purchasers of energy infrastructure have paid relatively high prices (measured in terms of a multiple of EBITDA or another financial metric) to acquire midstream assets and operations in arms-length transactions preceding the recent drop in commodity prices. In a low commodity price environment, merger and acquisition activity can be depressed as fewer sellers are able to capture the premiums necessary to move forward and the number of exceptional acquisition opportunities can be affordable by only the largest midstream companies with the strongest balance sheets. However given the cyclical nature of commodity prices and the specific variables driving merger and acquisition transactions, we continue to expect to selectively pursue acquisitions that add the scale necessary to grow our businesses quickly and successfully. Our Bakken and PRB Niobrara investments are examples of where we believe third-party acquisitions can provide cost-effective means of accelerating our growth. We therefore expect to grow our business in the near term through both organic growth projects and acquisitions.

Our long-term profitability will also depend on our ability to contract and re-contract with customers and to manage increasingly difficult regulatory processes at the federal, state and local levels. The time required to secure the authorizations necessary for development projects and expansions, for both unregulated and regulated projects, and the amounts we pay to secure authorizations and land rights are increasing in most markets in which we participate. Our Watkins Glen NGL storage project is a prime example of the increased political and regulatory challenges we face in certain regions, despite the market need for NGL storage solutions in the Northeast. However, we remain confident that the incremental time and money required to pursue and complete market-driven solutions will deliver meaningful value to our unitholders, as the combination of the ongoing regulatory climate and the location of our assets relative to both high-demand markets and prolific shale basins effectively provides a significant barrier to entry that other market participants may find difficult to overcome.

We remain confident that production levels in the Marcellus, Bakken and PRB Niobrara Shale plays will remain strong, particularly as new gas processing capacity and pipeline takeaway options come online in the next few years. Accordingly, certain producers may continue to divert resources away from dry gas plays (e.g., Fayetteville, Granite Wash and Haynesville), which could negatively impact the volumes flowing through our gathering systems in these plays.

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Based on current market conditions and forecasts, we anticipate robust demand for the supply, marketing and logistics services that our propriety NGL and crude businesses offer to customers. Our ability to control hydrocarbons across the distribution spectrum - from the wellhead to the end user - using our transportation fleet and contracted pipeline and storage capacity not only enables us to offer “flow assurance” on a geographic basis, but our ability to store storage crude oil and NGLs in our facilities enables us to provide flow assurance over periods of time. As the energy sector continues to undergo significant change on both the supply and the demand side, and we increase our ability to control supplies at the wellhead as a result of our G&P operations and relationships, we anticipate that our ability to offer multiple delivery options nationwide will remain in high demand.

We continue to forecast strong demand for storage services for natural gas and NGLs in the Northeast, due mainly to a shortage in supply deliverability options and storage infrastructure near key demand markets and a higher than average annual demand growth. We expect strong demand for natural gas pipelines that move production volumes directly to the market, and softer demand for pipeline capacity that can be displaced by new pipelines and expansion projects brought on line (particularly, new capacity used to move local production directly to local demand centers). We also believe that the location of our facilities in the Northeast positions us well to capitalize on opportunities associated with both (i) the current downward trend of increasingly lower import volumes of NGLs and liquefied natural gas along the East Coast and (ii) anticipated increases in exported volumes of liquefied natural gas as new liquefaction facilities along the East Coast come online.

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.

How We Evaluate Our Operations

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

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

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

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Results of Operations

The following table summarizes our results of operations for each of the three years ended December 31 (in millions). Financial data presented for periods prior to June 19, 2013, solely reflect the operations of Legacy Crestwood GP.



	Year Ended December 31,
	2014			2013			2012
Revenues	$	3,931.3		$	1,426.7		$	239.5
Costs of product/services sold	3,165.3			1,002.3			39.0
Operations and maintenance	203.3			104.6			43.1
General and administrative	100.2			93.5			29.6
Depreciation, amortization and accretion	285.3			167.9			73.2
Gain (loss) on long-lived assets, net	(1.9		)	5.3			—
Goodwill impairment	(48.8		)	(4.1		)	—
Gain (loss) on contingent consideration	(8.6		)	(31.4		)	6.8
Operating income	117.9			28.2			61.4
Loss from unconsolidated affiliates, net	(0.7		)	(0.1		)	—
Interest and debt expense, net	(127.1		)	(77.9		)	(35.8		)
Other income, net	0.6			0.2			—
Provision for income taxes	(1.1		)	(1.0		)	(1.2		)
Net income (loss)	(10.4		)	(50.6		)	24.4
Add:
Interest and debt expense, net	127.1			77.9			35.8
Provision for income taxes	1.1			1.0			1.2
Depreciation, amortization and accretion	285.3			167.9			73.2
EBITDA	$	403.1		$	196.2		$	134.6
Unit-based compensation charges	21.3			17.4			1.9
(Gain) loss on long-lived assets, net	1.9			(5.3		)	—
Goodwill impairment	48.8			4.1			—
(Gain) loss on contingent consideration	8.6			31.4			(6.8		)
Loss from unconsolidated affiliates, net	0.7			0.1			—
Adjusted EBITDA from unconsolidated affiliates, net	6.9			2.5			—
Change in fair value of commodity inventory-related derivative contracts	(10.3		)	10.7			—
Significant transaction and environmental-related costs and other items⁽¹⁾	14.9			40.6			4.7
Adjusted EBITDA	$	495.9		$	297.7		$	134.4

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	Year Ended December 31,
	2014			2013			2012
EBITDA:
Net cash provided by operating activities	$	283.0		$	188.3		$	102.1
Net changes in operating assets and liabilities	73.8			(19.6		)	(4.1		)
Amortization of debt-related deferred costs, discounts and premiums	(8.5		)	(9.2		)	(5.5		)
Interest and debt expense, net	127.1			77.9			35.8
Market adjustment on interest rate swaps	2.7			1.7			—
Unit-based compensation charges	(21.3		)	(17.4		)	(1.9		)
Gain (loss) on long-lived assets, net	(1.9		)	5.3			—
Goodwill impairment	(48.8		)	(4.1		)	—
Gain (loss) on contingent consideration	(8.6		)	(31.4		)	6.8
Loss from unconsolidated affiliates, net	(0.7		)	(0.1		)	—
Deferred income taxes	5.2			2.8			—
Provision for income taxes	1.1			1.0			1.2
Other non-cash income	—			1.0			0.2
EBITDA	$	403.1		$	196.2		$	134.6
Unit-based compensation charges	21.3			17.4			1.9
(Gain) loss on long-lived assets, net	1.9			(5.3		)	—
Goodwill impairment	48.8			4.1			—
(Gain) loss on contingent consideration	8.6			31.4			(6.8		)
Loss from unconsolidated affiliates, net	0.7			0.1			—
Adjusted EBITDA from unconsolidated affiliates, net	6.9			2.5			—
Change in fair value of commodity inventory-related derivative contracts	(10.3		)	10.7			—
Significant transaction and environmental-related costs and other items⁽¹⁾	14.9			40.6			4.7
Adjusted EBITDA	$	495.9		$	297.7		$	134.4

(1) Significant transaction and environmental-related costs and other items for the years ended December 31, 2014 and 2013, primarily include costs incurred related to the Crestwood Merger and Arrow Acquisition.

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



	Year Ended December 31, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services
Revenues	$	332.5		$	192.9	$	3,406.9
Costs of product/services sold	71.3			24.8		3,070.2
Operations and maintenance expense	62.9			23.3		117.1
Gain (loss) on long-lived assets, net	(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			0.2		(1.4		)
EBITDA ⁽¹⁾	$	139.0		$	178.8	$	184.9

	Year Ended December 31, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services
Revenues	$	291.2		$	104.2	$	1,031.3
Costs of product/services sold	56.6			15.7		930.0
Operations and maintenance expense	54.9			12.1		37.6
Gain (loss) on long-lived assets	5.4			—		(0.1		)
Goodwill impairment	(4.1		)	—		—
Gain on contingent consideration	(31.4		)	—		—
Earnings (loss) from unconsolidated affiliates	0.1			—		(0.2		)
EBITDA ⁽¹⁾	$	149.7		$	76.4	$	63.4

	Year Ended December 31, 2012
	Gathering and Processing			Storage and Transportation		NGL and Crude Services
Revenues	$	239.5		$	—	$	—
Costs of product/services sold	39.0			—		—
Operations and maintenance expense	43.1			—		—
Gain on contingent consideration	6.8			—		—
EBITDA ⁽¹⁾	$	164.2		$	—	$	—

(1) General and administrative expenses related to our Corporate operations totaled $100.2 million, $93.5 million and $29.6 million for the years ended December 31, 2014, 2013 and 2012. In addition, our Corporate operations recognized other income, net, of approximately $0.6 million and $0.2 million for the years ended December 31, 2014 and 2013.

Segment Results

Below is a discussion of the factors that impacted EBITDA by segment for the three years ended December 31, 2014, 2013 and 2012.

Gathering and Processing:

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

EBITDA for our G&P segment decreased by approximately $10.7 million during the year ended December 31, 2014 compared to 2013, primarily due to $51.7 million of impairments related to the Granite Wash and Fayetteville reporting units, offset by an increase in our revenues of approximately $41.3 million (or 14%) for the same period, which was primarily driven by higher gathering and compression volumes during the year ended December 31, 2014 compared to 2013. We gathered approximately

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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 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 increase in our G&P segment's revenues was a $14.7 million increase in costs of product/services sold during the year ended December 31, 2014 compared to 2013. The increase 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. We also experienced an increase in our G&P segment's operations and maintenance expense of approximately $8.0 million during the year ended December 31, 2014 compared to 2013 primarily due to the expansion of our assets in the Marcellus Shale.

In addition to the higher costs discussed above, our 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. The loss on contingent consideration was an accrual that reflected the fair value of an earn-out premium associated with the original acquisition of our Marcellus G&P assets from Antero in 2012. The earn-out provision allowed Antero to receive an additional $40 million payment when gathering volumes exceeded a certain threshold as defined in the acquisition agreements, which is due in the first quarter of 2015.

Year Ended December 31, 2013 Compared to Year Ended December 31, 2012

Our G&P segment's EBITDA decreased by approximately $14.5 million during the year ended December 31, 2013 compared to the same period in 2012. Contributing to the decrease was a $31.4 million loss on contingent consideration (described above), a $17.6 million increase in costs of product/services sold, and an $11.8 million increase in operations and maintenance expense, partially offset by a $51.7 million increase in operating revenues in 2013 compared to 2012.

The increase in operating revenues and costs of product/services sold was partially driven by a $15.6 million increase in operating revenues and $14.3 million increase in costs of product/services sold under percentage of proceeds contracts related to our G&P assets located in Granite Wash, the net of which increased our EBITDA by $1.3 million during 2013 compared to 2012.

The remaining increase in our operating revenues and operations and maintenance expense was primarily driven by a $38.3 million increase in operating revenues and an $8.9 million increase in operations and maintenance expense related to our G&P assets in the Marcellus Shale (for which the gathering operations were acquired in March 2012 and compressions operations were acquired in December 2012). Our gathering volumes related to these operations increased 84% during 2013 compared to 2012.

All our G&P systems gathered approximately 365 Bcf of natural gas during 2013, compared to 301 Bcf in 2012. We compressed approximately 107 Bcf of natural gas during 2013, which primarily relates to the acquisition of assets from Enerven Compression, LLC in December 2012. Our gathering and compression volumes were also impacted by the expansion of our gathering and compression assets in the Marcellus Shale in order to capitalize on increased producer activity.

Other. During the years ended December 31, 2014, 2013 and 2012, several significant transactions not related to our core operating activities impacted our G&P segment as follows:

Year Ended December 31, 2014:


•	$13.2 million and $20.0 million of property, plant and equipment and intangible impairments, respectively, related to our Granite Wash operations due primarily to our major customer ceasing substantial drilling in this area. See "Critical Accounting Estimates" below for a further discussion;


•	$14.2 million and $4.3 million goodwill impairments on our Granite Wash and Fayetteville reporting units due primarily to our major customers ceasing substantial drilling in those areas. See "Critical Accounting Estimates" below for a further discusson of our goodwill impairment; and


•	$8.6 million loss on contingent consideration in connection with the acquisition of the Antero assets.

Year Ended December 31, 2013:


•	$4.4 million gain on sale of a cryogenic plant and associated equipment;

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•	$4.1 million impairment of goodwill on our Haynesville/Bossier Shale reporting unit as a result of a decrease in anticipated revenues due primarily to our inability to renew and extend a significant revenue contract that expired in mid-2013; and


•	$31.4 million loss on contingent consideration in connection with the acquisition of the Antero assets.

Year Ended December 31, 2012:


•	$6.8 million gain on contingent consideration as result of the reduction in the fair value of the conditional consideration we agreed to pay Quicksilver related to the Crestwood Transaction

On July 19, 2013, Crestwood Niobrara acquired a 50% interest in a gathering system located in the PRB Niobrara for $107.5 million. For the years ended December 31, 2014 and 2013, we recorded earnings from our unconsolidated affiliate, Jackalope, of approximately $0.5 million and $0.1 million, which primarily related to (i) our proportionate share of Jackalope’s net income and (ii) the amortization of the excess of our investment balance compared to Jackalope’s net assets, which was approximately $3.1 million and $1.4 million for the years ended December 31, 2014 and 2013.

Storage and Transportation:

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 our 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 our storage and transportation segment increased by approximately $102.4 million during the year ended December 31, 2014 compared to 2013. The increase in our 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 below. We also 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. During the year ended December 31, 2014, total firm throughput from our Northeast storage and transportation services averaged approximately 1.8 Bcf/d compared to 1.7 Bcf/d during 2013.

Partially offsetting the increases in our 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.

In December 2014, we sold our 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, we deconsolidated Tres Palacios. Tres Palacios generated approximately $0.4 million of EBITDA to our storage and transportation segment's EBITDA prior to its deconsolidation on December 1, 2014. The sale of our 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 we retained 50.01% of our interest in Tres Palacios through our ownership in Crestwood Midstream, we 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 us. For the year ended December 31, 2014, we recorded earnings from our unconsolidated affiliate, Tres Palacios, of approximately $0.2 million, which primarily related to (i) our proportionate share of Tres Palacios’s net income and (ii) the amortization of the excess of our investment balance compared to Tres Palacios’s net assets which was approximately $0.1 million for the year ended December 31, 2014. See Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 6 for additional information related to the sale of Tres Palacios and Crestwood Midstream's investment in its unconsolidated affiliate.

NGL and Crude Services:

Our NGL and crude services segment results were included in our consolidated results of operations beginning June 19, 2013 (the date that Crestwood Holdings acquired control of our 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.

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Our NGL and crude services segment's EBITDA increased by approximately $121.5 million during the year ended December 31, 2014 compared to 2013, primarily due to higher revenues, partially offset by higher costs of product/services sold and operations and maintenance expense and goodwill impairments of our Watkins Glen and US Salt reporting units.

Our NGL and Crude Services revenues increased by $2,375.6 million during the year ended December 31, 2014 compared to the same period in 2013, primarily due to our 2014 results having a full year of operations from our Arrow assets compared to only two months in 2013. Arrow contributed revenues of approximately $1,884.3 million and $218.8 million for the years ended December 31, 2014 and 2013. The remaining increase in revenues was due primarily to having twelve months of operations from our COLT Hub assets in 2014 compared to six months in 2013. Also contributing to the increase was higher volumes on our COLT Hub as a result of our expansion of the facility and increased utilization of non-firm capacity on the system. During 2014 and 2013, we loaded approximately 110,000 MBbls/d and 82,000 MBbls/d of crude on rail cars entering the facility.

Offsetting the increases in our NGL and crude services segment's revenues was a $2,140.2 million increase in costs of product/services sold and a $79.5 million increase in operations and maintenance expenses, primarily due to our 2014 results have a full year of operations compared to six months in 2013 for Legacy Inergy and two months for Arrow's operations.

In addition to the increases in our NGL and crude services segment's EBITDA discussed above, we had $75.6 million and $25.2 million of EBITDA for the years ended December 31, 2014 and 2013 produced by our NGL terminalling, supply and logistics operations. The increase was due primarily to our 2014 results having a full year of operating revenues compared to six months in 2013. We continue to experience favorable market conditions in this business that allowed our NGL supply and logistics business to capture more opportunities to generate favorable margins from their marketing operations.

We recorded a goodwill impairment of approximately $28.1 million related to our Watkins Glen reporting unit, primarily due to delays in the permitting of the proposed NGL storage facility, including the uncertainty surrounding the timing of placing the project in service. We also recorded impairments of approximately $3.5 million related to our US Salt reporting unit. These impairments resulted from the loss of a significant customer in 2014 which we determined was unlikely to be replaced in the near future given current and future anticipated market conditions. See "Critical Accounting Estimates" below for a further discussion of our goodwill impairment.

On September 2013, Crestwood Crude Logistics LLC (Crude Logistics) and Enserco Midstream, LLC formed PRBIC. Crude Logistics acquired a 50% interest in PRBIC for approximately $22.5 million. For the years ended December 31, 2014 and 2013, we recorded a loss from our unconsolidated affiliate, PRBIC, of approximately $1.4 million and $0.2 million, which primarily related to our proportionate share of PRBIC’s net loss.

Other Results

Our consolidated EBITDA for the year ended December 31, 2014 was $403.1 million, an increase of $206.9 million from 2013 and an increase of $61.6 million for the year ended December 31, 2013 compared to 2012. Our consolidated Adjusted EBITDA for the year ended December 31, 2014 was $495.9 million, an increase of $198.2 million from 2013 and an increase of $163.3 million for the year ended December 31, 2013 compared to 2012.

The increase in our EBITDA and Adjusted EBITDA was primarily driven by our segment results described above. Partially offsetting those results were the general and administrative expenses of our Corporate operations. Our 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. Our general and administrative expenses increased by approximately $63.9 million for the year ended December 31, 2013 compared to 2012 primarily due to these transaction costs and six months of results in 2013 related to Legacy Inergy's operations compared to none in 2012.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense - During the year ended December 31, 2014, our depreciation, amortization and accretion expense increased compared to 2013 and 2012 primarily due to the assets acquired as a result of the Crestwood Merger and other assets acquired during 2014, 2013 and 2012. For a further discussion of our acquisitions, see Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 3.

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Interest and Debt Expense - Interest and debt expense increased for the year ended December 31, 2014 compared to 2013 and 2012, primarily due to (i) higher outstanding balances on our Credit Facilities, net of repayments; (ii) the issuance of an additional $150 million of 7.75% Senior Notes in November 2012; (iii) the assumption of $1.1 billion of long-term debt due to the Crestwood Merger; and (iv) the issuance of $600 million of 6.125% Crestwood Midstream Senior Notes in November 2013.

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



	Year Ended December 31,
	2014		2013		2012
Credit facilities	$	31.5	$	25.4	$	17.6
Senior notes	94.7		49.8		17.8
Capital lease interest	0.1		0.2		0.2
Other debt-related costs	8.5		5.9		0.4
Gross interest and debt expense	134.8		81.3		36.0
Less: capitalized interest	7.7		3.4		0.2
Interest and debt expense, net	$	127.1	$	77.9	$	35.8

Liquidity and Sources of Capital

We are a partnership holding company that derives all of our operating cash flow from our operating subsidiaries. Our principal sources of liquidity include cash generated by operating activities, credit facilities, debt issuances, and sales of our common units. Our operating subsidiaries use cash from their respective operations to fund their operating activities and maintenance capital expenditures. We believe our current liquidity sources and operating cash flows will be sufficient to fund our future operating and capital requirements.

CEQP Credit Facility. As of December 31, 2014 we had $69.3 million of available capacity under the CEQP Credit Facility considering our most restrictive debt covenants under that facility. Our NGL supply and logistics business has historically experienced increased working capital requirements during the third and fourth quarters as we purchase and build inventory for

the winter demand season. We anticipate funding any such increased working capital requirements and service our outstanding indebtedness, fund growth capital expenditures, and make distributions to unitholders through a combination of cash generated by our operating subsidiaries, distributions received from Crestwood Midstream, and borrowings available under the CEQP Credit Facility.

In December 2014, we repaid $130.0 million of borrowings on our CEQP Credit Facility with the proceeds received from the sale of our interest in Tres Palacios. In accordance with the terms of the credit agreement governing our CEQP Credit Facility, the CEQP Credit Facility commitment was reduced to $495 million from $625 million.

Crestwood Midstream utilizes a variety of sources to service its outstanding indebtedness, fund growth capital expenditures, and make distributions to its unitholders. These sources include funds cash generated by its operating subsidiaries, borrowings under the Crestwood Midstream Revolver, funds from the issuance of Preferred Units and funds from the sale of its common units under the equity distribution agreement.


•	Crestwood Midstream Revolver. As of December 31, 2014, Crestwood Midstream had $429.9 million of available capacity under its credit facility considering its most restrictive debt covenants under that facility.

•

Preferred Units. On June 17, 2014, Crestwood Midstream entered into definitive agreements with a group of investors under which it has agreed to sell and the investors have agreed to purchase up to $500 million of Preferred Units at a purchase price of $25.10 per unit prior to September 30, 2015. During the year ended December 31, 2014, Crestwood Midstream sold 17,529,879 Preferred Units to the investors in a series of privately-placed transactions that generated gross proceeds of approximately $440.0 million (or approximately $430.5 million of net proceeds after transaction fees and offering expenses). Crestwood Midstream expects to issue $60.0 million of Preferred Units to the Class A Purchasers before September 30, 2015, and to use the proceeds from such issuances to fund expansion and development projects, to reduce borrowings under its credit facility, and for other general partnership purposes. See Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 12 for a more detailed description of the Preferred Units.

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Equity Distribution Agreement. On July 10, 2014, Crestwood Midstream entered into an equity distribution agreement with several financial institutions under which it may offer and sell from time to time through one or more managers, its common units having an aggregate offering price of up to $300.0 million. Common units sold pursuant to this at the-market (ATM) equity distribution program will be issued under a registration statement that became effective on May 27, 2014. Crestwood Midstream will pay the managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under its ATM program, and net proceeds from equity sold under this program will be used to fund expansion and development projects, to finance acquisitions, to reduce borrowings under the Crestwood Midstream Revolver, and for other general partnership purposes. Crestwood Midstream has not issued any common units under this equity distribution program. See Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 12 for more information on the ATM equity distribution program.

As of December 31, 2014, we were in compliance with all our debt covenants related to the CEQP Credit Facilities, Crestwood Midstream Revolver and our Senior Notes. See Part IV, Item 15, Exhibits and Financial Statement Schedules, Note 9 for a more detailed description of these credit facilities 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 our cash flows by category (in millions):



	Year Ended December 31,
	2014			2013			2012
Net cash provided by operating activities	$	283.0		$	188.3		$	102.1
Net cash used in investing activities	(483.0		)	(1,042.9		)	(616.6		)
Net cash provided by financing activities	203.6			859.7			513.8

Operating Activities

Our operating cash flows increased approximately $94.7 million during the year ended December 31, 2014 compared to 2013 and increased approximately $86.2 million during the year ended December 31, 2013 compared to 2012. The increases during 2014 and 2013 are primarily attributable to the Crestwood Merger and the Arrow Acquisition which occurred in June and November of 2013. These acquisitions were the primary factor in higher operating revenues of approximately $2,504.6 million in 2014 compared to 2013 and $1,187.2 million in 2013 compared to 2012, partially offset by higher costs of products/services sold, operations and maintenance expenses and general and administrative expenses of approximately $2,268.4 million in 2014 compared to 2013 and $1,088.7 million in 2013 compared to 2012. In addition, our interest paid increased approximately $49.5 million during the year ended December 31, 2014 compared to 2013 and approximately $37.0 million during the year ended December 31, 2013 compared to 2012, 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.

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The following table summarizes our capital expenditures for the year ended December 31, 2014 (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	$	330.0
Maintenance capital	27.6
Other⁽¹⁾	66.4
Purchases of property, plant and equipment	424.0
Reimbursements of property, plant and equipment	21.5
Net purchases of property, plant and equipment	$	402.5

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

During 2015, we anticipate growth capital expenditures of approximately $125 million to $135 million, which includes contributions to our equity investments related to their capital projects. In addition, we expect to spend between approximately $25 million to $28 million on maintenance capital expenditures. We anticipate that our growth capital expenditures in 2015 will increase the gathering, processing, compression and overall capacity of our systems, primarily in the PRB Niobrara and Bakken Shales. We expect to finance our growth and maintenance capital expenditures with a combination of cash generated by our operating subsidiaries, distributions received from Crestwood Midstream and borrowings under our credit facilities.

Our cash flows from investing activities were impacted by the following significant items during the three years ended December 31, 2014, 2013 and 2012:

Acquisitions. During the years ended December 31, 2014, 2013 and 2012, we paid approximately $19.5 million, $555.6 million and $564.0 million to acquire our transportation fleet from Red Rock and LT Enterprises in 2014, our Arrow assets in 2013 and Antero, Devon and Enerven asset acquisitions in 2012, respectively. For a further discussion of these acquisitions, see Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 3.

Investments in Unconsolidated Affiliates. During the year ended December 31, 2013, we acquired a 50% interest in Jackalope and a 50% interest in PRBIC for approximately $107.5 million and $22.5 million, respectively. We contributed approximately $105.2 million and $19.6 million to Jackalope during the year ended December 31, 2014 and 2013 to fund its construction project. In addition, we contributed approximately $3.4 million and $1.9 million to PRBIC to fund its construction projects. 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, we sold our 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, we 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, 2014, 2013 and 2012 included the following:

Equity Transactions


•	$34.1 million increase in distributions to partners in 2014 compared to 2013 and an increase of $54.6 million in 2013 compared to 2012;


•	$92.0 million increase in distributions to non-controlling partners in 2014 compared to 2013 and an increase of $114.8 million in 2013 compared to 2012;


•	$430.5 million net proceeds from the issuance of Crestwood Midstream's Class A Preferred Units in 2014;


•	$53.9 million and $96.1 million in proceeds from the issuance of preferred security units to GE in 2014 and 2013;

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


•	$595.5 million of net proceeds from the issuance of Inergy Midstream common units in 2013;


•	$118.5 million and $217.5 million of net proceeds from the issuance of Legacy Crestwood common units in 2013 and 2012; and


•	$249.7 million contribution in 2012 to fund acquisition of interest in CMM.

Debt Transactions


•	$371.4 million decrease in net borrowings of long-term debt from $499.3 million in 2013 to $127.9 million in 2014, primarily due to liquidity obtained through equity issuances and $326.6 million increase in net borrowings in 2013 compared to 2012, primarily as a result of asset acquisitions during 2013.

Other


•	The payment of Sabine System acquisition deferred payment of approximately $8 million in 2012.

Off-Balance Sheet Arrangements

None.

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, 2014 (in millions):



	Less than 1 Year		1-3 Years		3-5 Years		Thereafter		Total
Long-term debt:
Principal	$	3.7	$	368.8	$	917.0	$	1,102.0	$	2,391.5
Interest⁽¹⁾	121.9		222.7		178.4		108.7		631.7
Future minimum payments under operating leases⁽²⁾	16.9		28.4		20.9		17.5		83.7
Future minimum payments under capital leases⁽²⁾	2.2		2.8		0.4		—		5.4
Asset retirement obligations	—		—		—		23.8		23.8
Fixed price commodity purchase commitments⁽³⁾	231.6		11.3		—		—		242.9
Standby letters of credit	71.8		—		—		—		71.8
Growth capital-related purchase commitments and other contractual obligations⁽⁴⁾	33.6		—		—		—		33.6
Total contractual obligations	$	481.7	$	634.0	$	1,116.7	$	1,252.0	$	3,484.4


(1)	$924.0 million of our long-term debt, including interest rate swaps, is variable interest rate debt at prime rate or LIBOR plus an applicable spread. These rates plus their applicable spreads were between 2.91% and 5.00% at December 31, 2014. 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)

Includes identified growth projects primarily related to the Watkins Glen NGL development project, the Arrow growth projects in the Bakken Shale, certain upgrades to the US Salt facility, growth and maintenance contractual purchase obligations in our G&P segment, as well as 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.

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Critical Accounting Estimates

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 assign the goodwill related to these acquisitions to reporting units, which are discrete operating components of the entities that we individually manage. We determined our reporting units based on the discrete financial information that our segment management uses to make decisions about resource allocation and to assess the performance of the individual components of the business. Our reporting units, and the goodwill that was assigned to each of those reporting units, were as follows as of December 31, 2014 (in millions):



Reporting Segment and Unit	Goodwill
G&P
Marcellus	$	8.6
Barnett	257.2
Fayetteville	72.5
Granite Wash⁽¹⁾	—
Storage and Transportation
Northeast Storage and Transportation	726.3
NGL and Crude Services
Arrow	45.9
Bath	29.0
COLT	668.3
NGL and Crude Transportation	177.9
Supply & Logistics	266.2
US Salt	12.6
Watkins Glen	66.2
West Coast	85.9
Storage and Terminals	75.2
Total	$	2,491.8


(1)	We incurred a full impairment related to our Granite Wash reporting unit which is discussed in further detail below.

We evaluate goodwill for impairment annually on December 31, and whenever events or changes 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.

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We estimate the fair value of our reporting units based on a number of factors, including the potential value we would receive if we sold the reporting unit, enterprise value, discount rates and projected cash flows. Estimating projected cash flows requires us to make certain assumptions as it relates to future operating performance. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. If the growth assumptions embodied in the current year impairment testing prove inaccurate, we could incur an impairment charge.

Our quantitative goodwill impairment assessment at December 31, 2014 indicated that four of our reporting units, Granite Wash (G&P), Fayetteville (G&P), US Salt (NGL and Crude Services) and Watkins Glen (NGL and Crude Services) had fair values less than their carrying amounts as of December 31, 2014. We performed a “step two” impairment test for these reporting units which requires us to treat the reporting units as if they had been acquired in a business combination as of December 31, 2014 and assign the fair value of the reporting unit to all of its assets and liabilities. The carrying value of the goodwill is compared to the new implied fair value of goodwill and an impairment is recognized for any amount the carrying value exceeds the implied fair value. Based on that step two impairment test, we noted that our Granite Wash and our Fayetteville goodwill incurred an impairment of $14.2 million and $4.3 million, respectively, which resulted from announcements during the fourth quarter of 2014 by our major customers in the reporting units that they would cease any substantial drilling in the Granite Wash and the Fayetteville Shale in the near future given current and future anticipated market conditions related to natural gas, which negatively impacted our future cash flows, and therefore fair value, of our Granite Wash and Fayetteville reporting units. We also noted that our US Salt goodwill incurred an impairment of $2.2 million as of December 31, 2014, which resulted from the loss of a significant customer in 2014 which we determined was unlikely to be replaced in the near future given current and future anticipated market conditions. Our Watkins Glen goodwill also incurred an impairment of $28.1 million as of December 31, 2014, which resulted from continued delays in permitting of the proposed NGL storage facility. Although we believe it is probable that the storage project will be placed in service, uncertainty surrounding the timing of placing that project in service caused the fair value of our Watkins Glen reporting unit to fall below its carrying value as of December 31, 2014.

We continue to monitor the remaining $72.5 million and $12.6 million of goodwill assigned to our Fayetteville and US Salt reporting units, and we could experience additional impairments of the remaining goodwill in the future if we receive additional negative information about market conditions or the intent of our customers related to those operations. We also continue to monitor the remaining $66.2 million of goodwill assigned to our Watkins Glen reporting unit, and we could experience additional impairments of the remaining goodwill in the future if we receive negative information about the timing or our ability to receive the required permitting related to the proposed NGL storage facility.

During the year ended December 31, 2013, we recorded an impairment of goodwill of approximately $4.1 million on our Haynesville/Bossier Shale system as a result of a decrease in anticipated revenues to be generated from those operations due primarily to our inability to renew and extend a significant revenue contract that expired in mid-2013.

We acquired all of the reporting units in our Storage and Transportation segment and our NGL and Crude segment during 2013, and finalized the purchase price allocations for these acquisitions during 2014, at which time we recorded the assets, liabilities and goodwill of those reporting units at fair value. As a result, any level of decrease in the forecasted cash flows of those businesses from the date of acquisition would likely result in the fair value of the reporting unit to fall below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill could be impaired. In particular, a 8% decrease in the estimated future cash flows or a 0.6% increase in the discount rate used to estimate the fair value of our COLT (NGL and Crude Services) reporting unit could have resulted in an impairment of goodwill. In addition, we continue to monitor the recoverability of the goodwill related to our Barnett Shale (G&P) reporting unit given the recent decrease in commodity prices and the credit considerations of our primary customer in those operations, and note that a 2% decrease in the estimated future cash flows or a 0.2% increase in the discount rate used to estimate the fair value for that reporting unit could have potentially resulted in an impairment of the goodwill related to our Barnett Shale reporting unit.

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

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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 also 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 asset based on the expected future cash flows (to the extent they are reliably 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 annual routine 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.

The value of the assets to be disposed of is estimated at the date a commitment to dispose of the asset is made. Our estimate of any loss associated with an asset sale is dependent on certain assumptions we make with respect to the net realizable value of the particular asset.

We incurred a $20.0 million impairment of our intangible assets and $13.2 million impairment of our property, plant and equipment related to our Granite Wash operations during the year ended December 31, 2014, which resulted from an announcement during the fourth quarter of 2014 by our major customer of those assets that they would cease any substantial drilling in the Granite Wash in the near future given current and future anticipated market conditions related to natural gas, which negatively impacted our future cash flows related to these operations. Our other operations that incurred goodwill impairments during 2014 did not incur any 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, 2014. We did not record any significant impairments of our long-lived assets during 2013 or 2012.

Projected cash flows of our long-lived asset 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.

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 NGL and crude services segment and our gathering and processing 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 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, 2014 and 2013, we had deferred revenue of approximately $12.2 million and $2.1 million, which is reflected as accrued expenses and other liabilities on our consolidated balance sheets.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

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

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

As of December 31, 2014, the carrying value and fair value of our fixed rate debt instruments (including debt fair value adjustments) was approximately $1,466.4 million and $1,422.2 million, respectively. As of December 31, 2013, the carrying value and fair value of our fixed rate debt instruments was approximately $1,467.3 million and $1,522.0 million, respectively. For a further discussion of our fixed rate debt, see Part IV, Item 15, Exhibits and Financial Statement Schedules, Note 9.

We have two credit facilities that are subject to the risk of loss associated with changes in interest rates. At December 31, 2014, we had obligations totaling $924.0 million borrowed under these credit facilities (net of certain interest rate swaps, which convert the interest rate on one of our credit facilities to a fixed rate). 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 our credit facilities were to fluctuate by 1% from the rate as of December 31, 2014, our annual interest expense would have changed by a total of $9.2 million.

Commodity Price, Market and Credit Risk

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

Market Risk

In our businesses other than our NGL and crude logistics operations, 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) NGLs under certain of our percent-of-proceeds contracts (G&P segment); (ii) crude oil purchased from certain of our Arrow producer customers for our marketing operations (NGL and crude oil segment); and (iii) 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 NGL and crude logistics operations, we consider market risk to be the risk that the value of our NGL and crude services segment's portfolio will change, either favorably or unfavorably, in response to changing market conditions. We take an active role in managing and controlling market risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio's position to senior management. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of December 31, 2014 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

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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 and inventory exchange contracts related to price risk management activities as of December 31, 2014 were assets of $79.8 million and liabilities of $25.4 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 $2.8 million change in the market value of these contracts as there were 56.6 million gallons of net unbalanced positions at December 31, 2014. Inventory positions of 56.3 million gallons would substantially offset this theoretical change at December 31, 2014.

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.

In February 2015, Quicksilver, our significant customer in our gathering and processing operations in the Barnett Shale, announced its decision not to make an interest payment due under its indenture and to enter into a 30-day grace period under the applicable indenture. To the extent that the interest payment is not made during the grace period and a debt restructuring plan is not reached between Quicksilver and its creditors, this could result in an event of default which may lead Quicksilver to seek voluntary protection under Chapter 11 of the United States Bankruptcy Code. Although Quicksilver has paid us for all obligations we billed to them as of December 31, 2014 and through the filing date of this Form 10-K, we are closely monitoring Quicksilver's liquidity to ensure continued receipt of prompt payment of invoices submitted to Quicksilver.

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, 2014, we carried out an evaluation under the supervision and with the participation of our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as to the effectiveness, design and operation of our disclosure controls and procedures (as defined in the Securities Exchange Act of 1934, as amended (Exchange Act) Rules 13a-15(e) and 15d-15(e)). We maintain controls and procedures designed to provide reasonable assurance that information required to be disclosed in our reports that we file or submit under the Exchange Act of 1934, as amended, are recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information is accumulated and communicated to our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, as appropriate, to allow timely decisions regarding required disclosure. Our management, including the Chief Executive Officer and Chief Financial Officer of our General Partner, does not expect that our disclosure controls and procedures or our internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Our disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and our Chief Executive Officer and Chief Financial Officer of our General Partner

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concluded that our disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2014.

Changes in Internal Control over Financial Reporting

There have been no changes in our internal control over financial reporting during the fourth quarter of 2014 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting, pursuant to Exchange Act Rules 13a-15(f). Our internal control system was designed to provide reasonable assurance to management and our 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 our management, including our Chief Executive Officer and Chief Financial Officer, we assessed the effectiveness of our internal control over financial reporting as of December 31, 2014. In making this assessment, we 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 our assessment, we concluded that, as of December 31, 2014, our internal control over financial reporting is effective, based upon those criteria.

Our independent registered public accounting firm, Ernst & Young LLP, issued an attestation report dated February 27, 2015, 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.

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 nine 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	60	President, Chief Executive Officer and Director
J. Heath Deneke	41	President, Natural Gas Business Unit
William C. Gautreaux	51	President, Liquids and Crude Business Unit
Michael J. Campbell	45	Senior Vice President, Chief Financial Officer⁽¹⁾
Steven M. Dougherty	42	Senior Vice President, Chief Accounting Officer
Joel C. Lambert	46	Senior Vice President, General Counsel and Corporate Secretary
William H. Moore	35	Senior Vice President, Strategy and Corporate Development
Joel D. Moxley	56	Senior Vice President, Operations Services
Alvin Bledsoe	66	Director
Michael G. France	37	Director
Warren H. Gfeller	62	Director
Arthur B. Krause	73	Director
Randy E. Moeder	54	Director
John J. Sherman	59	Director
John W. Somerhalder II	59	Director
David M. Wood	57	Director

(1) On January 16, 2015, Michael J. Campbell resigned as Chief Financial Officer of our general partner, effective as of March 31, 2015. On January 20, 2015, the board of directors of our general partner appointed Robert T. Halpin as Chief Financial Officer effective on the effective date of Mr. Campbell's resignation.

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

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served as a Director of Pride International, Inc. from October 2007 to May 31, 2011, one of the world’s largest offshore drilling contractors, and was a member of its audit committee. Mr. Phillips is an Advisory Director of Triten Corporation, a leading international engineering firm and alloy products manufacturer. 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, Natural Gas Business Unit of our general partner and CMLP’s general partner in October 2013. He served 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, Liquids and Crude Business Unit of our general partner and CMLP’s general partner in October 2013. He served 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.

Michael J. Campbell has served as the Senior Vice President - Chief Financial Officer our general partner and CMLP’s general partner since September 2012. He joined Legacy Inergy in 2003 and served as the Vice President and Treasurer from May 2005 to September 2012. He previously served as Director of Financial Analysis in the Corporate Development department at Aquila, Inc., and as Manager of Crude and Structured Products Trading Support at Koch Industries. On January 16, 2015, Michael J. Campbell resigned as Chief Financial Officer of our general partner, effective as of March 31, 2015.

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. Most recently, he served as 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.

Joel D. Moxley was appointed Senior Vice President, Operations Services of our general partner and CMLP’s general partner in October 2013. He was appointed Senior Vice President Legacy Crestwood in October 2010 and appointed Chief Operating Officer of Legacy Crestwood in August 2011. From April 2008 until joining Legacy Crestwood, Mr. Moxley was Senior Vice President of Crestwood Midstream Partners, LLC. From November 2005 to March 2008, he was Senior Vice President of Crosstex Energy, L.P. From September 2004 to November 2005, Mr. Moxley was a Senior Vice President for Enterprise Products Partners, L.P. From January 2001 to August 2004 he was Vice President of El Paso Corporation. From 1997 to 2000 he was a Vice President for PG&E Corporation. Mr. Moxley holds a Bachelor of Science in Chemical Engineering from Rice University.

Alvin Bledsoe was appointed a director of our general partner and CMLP’s general partner in October 2013. He served as a director of Legacy Crestwood from July 2007 until October 2013. Since June 2011, Mr. Bledsoe has also served as a director of

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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 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 and CMLP’s general partner in June 2013. He served 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 currently serves 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 and CMLP GP’s board of directors since December 2011. 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.

Arthur B. Krause has been a member of our general partner’s board of directors since May 2003. He served as a member of the board of directors of CMLP GP from December 2011 to October 2013. Mr. Krause retired from Sprint Corporation in 2002, where he served as Executive Vice President and Chief Financial Officer from 1988 to 2002. He was President of United Telephone-Eastern Group from 1986 to 1988. From 1980 to 1986, he was Senior Vice President of United Telephone System. He previously served as a director of Westar Energy and Inergy Holdings GP, LLC. Mr. Krause’s prior leadership experience and his extensive financial and accounting training and practice have made him a valuable member of our board of directors.

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. 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.

Randy Moeder was appointed as a director of our general partner in October 2013. He served as a member of the board of director of CMLP GP from March 2012 to until October 2013. Mr. Moeder currently is the Chief Executive Officer and President of Moeder Oil & Gas, LLC. Mr. Moeder previously served as the Chief Executive Officer and President of Hiland Partners, LP and Hiland Partners, GP. He also held various positions with Continental Resources, Inc. and its affiliates from 1990 to 2004. Mr. Moeder brings a wealth of oil and gas industry experience to our board. His experience with the midstream sector as well as publicly traded master limited partnership give him valuable insight into the successful execution of our long-term growth objectives and makes him a valuable member of our board.

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 has 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, since March 2006 and as Chairman of the Board of AGL Resources since November 2007.

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From 2000 to May 2005, Mr. Somerhalder served as the Executive Vice President of El Paso Corporation, a natural gas and related energy products provider and one of North America’s largest independent natural gas producers, where he continued service under a professional services agreement from May 2005 to March 2006. From 2001 to 2005, he served as the President of El Paso Pipeline Group. From 1996 to 1999, Mr. Somerhalder served as the President of Tennessee Gas Pipeline Company, an El Paso subsidiary company. From April 1996 to December 1996, Mr. Somerhalder served as the President of El Paso Energy Resources Company. From 1992 to 1996, he served as the Senior Vice President, Operations and Engineering, of El Paso Natural Gas Company. From 1990 to 1992, Mr. Somerhalder served as the Vice President, Engineering of El Paso Natural Gas Company. From 1977 to 1990, Mr. Somerhalder held various other positions at El Paso Corporation and its subsidiaries until being named an officer in 1990. Mr. Somerhalder was selected to serve as a director of our general partner due to his years of experience in the oil and gas industry and his extensive business and management expertise, including as President, Chief Executive Officer and a director of a publicly-traded energy company.

David M. Wood was appointed as a director of our general partner and CMLP’s general partner in August 2013. He served as the Chief Executive Officer, President and a director of Murphy Oil Corporation from January 1, 2009 to June 2012. Mr. Wood served as the President of Murphy Exploration & Production Company for Murphy Oil Corporation since January 1, 2007 and served as its Executive Vice President of Worldwide Exploration & Production Operations since January 1, 2007. Prior to joining Murphy Oil Corp., Mr. Wood held various senior positions with Ashland Exploration and Production. He served as the President of Murphy Exploration & Production Company-International from March 2003 to December 2006 and also served as Senior Vice President of Frontier Exploration & Production from April 1999 to February 2003. Mr. Wood served as Vice President of Frontier Exploration & Production for Murphy Oil Corporation from 1997 to March 1999, General Manager of Frontier Exploration from 1995 to 1997 and Manager of Frontier Exploration from 1994 to 1995. He served as a member of the board of directors of the American Petroleum Institute and was a member of the National Petroleum Council. Mr. Wood holds a Bachelor's degree in Geology from Nottingham University in England. Mr. Wood was selected to serve as a director of our general partner because he has over 30 years of experience within the oil and gas industry.

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, Arthur B. Krause, Randy Moeder 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, Arthur Krause and Randy Moeder. 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 members of the compensation committee are David Wood and Warren Gfeller. Our compensation committee charter may be found on our website at www.crestwoodlp.com.

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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 Randy Moeder and John Somerhalder. 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 sole member and chairman of the finance committee is Arthur Krause.

Board Leadership Structure

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

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 H. 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.

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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, 2014, all section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% unitholders, were met.

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, except for prior awards of incentive units in Crestwood Holdings Partners LLC described in more detail below. 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 2014 were comprised of:


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


•	Michael J. Campbell, our Chief Financial Officer (Principal Financial Officer);


•	J. Heath Deneke, our President, Natural Gas Business Unit;


•	William C. Gautreaux, our President, Liquids and Crude Business Unit; and


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

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 increase 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 growth 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 and the growth of cash earnings on behalf of our unitholders;


•	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

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

By accomplishing these objectives, we hope 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, Aon Hewitt, 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 sponsored by Aon Hewitt, and Mercer. The survey data is used to confirm that pay practices among companies in the comparator group are aligned with the market as a whole.

Chief Executive Officer’s Role in the Compensation Setting Process

Our Chief Executive Officer 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 Chief Executive Officer 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 Chief Executive Officer’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 ultimately approves all aspects of executive compensation based on the recommendations of 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's independent compensation consultant advises on 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, the board of directors meets in executive session without management present to review the CEO's performance. In this session, the board of directors reviews:


•	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 uses 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 Independent Compensation Consultant

In 2013, Pearl Meyer & Partners (PM&P) was retained by the Compensation Committee to assist the Compensation Committee in determining the compensation for our NEOs for 2014. To assist the Compensation Committee in discussions and decisions about compensation for our NEOs, including our CEO, the Compensation Committee's independent compensation consultant provided a competitive market study that includes proxy data from the approved comparator group and published compensation data. Our comparator group was developed by management, with input from the Compensation Committee and the Compensation Committee's independent compensation consultant, and was approved by the Compensation Committee.

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In 2014, Meridian Compensation Partners was retained by the Compensation Committee to review the competitive market study and assist the Compensation Committee in compensation matters. Aon Hewitt was retained by management to conduct the competitive market study to provide to the Compensation Committee.

Market Analysis

In 2013, PM&P collected market data from two primary data sources:


•	Peer group 10-K data for the following 12 midstream master limited partnerships (MLPs).



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


•	Survey data for midstream oil and gas, broader energy, and general industry companies with revenues of around $2 billion (roughly the same as combined gross revenues for Legacy Crestwood and Legacy Inergy pre-merger).

The PM&P competitive market study was used as the basis for establishing our executive officers’ initial post-merger base salary, target bonus and target long-term annual equity awards, which were documented in employment agreements we entered into with each of our executive officers in January 2014 (the Executive Employment Agreements). Based upon PM&P’s competitive market study, base salary and annual and long-term incentive amounts for our named executive officers were targeted at the midpoint between the 50th and 75th percentiles of the market data. These amounts remained in effect through 2014.

For our 2015 compensation review, Aon Hewitt conducted and Meridian reviewed a competitive market study of the executive compensation of the combined partnership. The methodology and peer groups used were similar to those used in 2014.

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.

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). Our compensation philosophy and the competitive market study includes proxy data from the approved comparator group and published compensation data for companies with which we compete for executive talent.

The Executive Employment Agreements established the following base salary levels for 2014:



Named Executive Officer		2014 Base Salary
Robert G. Phillips		$655,000
Michael J. Campbell		$400,000
J. Heath Deneke		$435,000
William C. Gautreaux		$435,000
William H. Moore		$350,000

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The base salaries of our NEOs are reviewed on an annual basis. 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.

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”.

Annual Incentive Awards

Incentive awards are designed to reward the performance of key employees, including the NEOs, 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 executives who can significantly impact performance and promote achievement of our short-term business objectives.

For 2014, annual incentive target payouts were established for each of our named executive officers pursuant to their Employment Agreements. The annual incentive targets set forth in the Employment Agreements were determined based upon the peer group analysis and survey data analyzed by PM&P as described above and were targeted at the midpoint between the 50th and 75th percentiles of the market data. For additional information regarding the analysis performed by PM&P during 2014, see “Compensation Discussion & Analysis -Market Analysis.” The Employment Agreements established the following annual cash incentive targets for such NEOs:



Named Executive Officer		2014 Target Bonus (% of Base Salary)
Robert G. Phillips		$655,000 (100%)
Michael J. Campbell		$400,000 (100%)
J. Heath Deneke		$391,500 (90%)
William C. Gautreaux		$391,500 (90%)
William H. Moore		$350,000 (100%)

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.”

Actual bonuses for 2014 were determined based 80% on our achievement of certain key performance indicators (KPIs) and 20% based upon a board of director’s discretionary component. The KPIs for Fiscal 2014 were Adjusted EBITDA by segment, operational and administrative costs and safety. 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 125%, results below the minimum threshold result in 0% achievement for that KPI. Notwithstanding the foregoing, Mr. Campbell’s bonus for 2014 was separately established to be paid out at 75% of target in connection with entry into his separation agreement as described below under “Compensation Discussion & Analysis-Severance and Change of Control Benefits”.

Based on the foregoing the actual annual cash incentive awards for our NEOs in Fiscal 2014 were as follows:



Named Executive Officer		2014 Bonus Amount
Robert G. Phillips		$655,000
Michael J. Campbell		$300,000
J. Heath Deneke		$430,650
William C. Gautreaux		$293,625
William H. Moore		$350,000

Long-Term Incentive Plan Awards

Long-term incentive awards for the NEOs are granted under the Crestwood Equity Partners LP Long Term Incentive Plan (formerly the Inergy Long Term Incentive Plan) and the Crestwood Midstream Partners LP Long Term Incentive Plan (formerly the Inergy Midstream, L.P. 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 are designed to align the economic interests of key employees and directors with those of our common unitholders and the common unitholders of us

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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 is based upon the common units representing limited partnership interests in us and in Crestwood Midstream Partners LP. For Fiscal 2014, our awards consisted solely of grants of restricted common units which vest based upon continued service. Restricted units are designed to attract and retain executive talent and to align their economic interests with those of common unitholders. For fiscal 2015, certain of our named executive officers will receive grants of phantom units rather than restricted common units.

Annual Long-Term Incentive Awards during Fiscal 2014

For 2014, equity incentive targets were established for each of our named executive officers Employment Agreements. The annual long-term incentive target amounts set forth in their Employment Agreements were determined based upon the peer group analysis and survey data analyzed by PM&P as described above and were targeted at the midpoint between the 50th and 75th percentiles of the market data. For additional information regarding the analysis performed by PM&P during 2014, see “Compensation Discussion & Analysis -Market Analysis.” The Executive Employment Agreements establish the following equity incentive targets for such NEOs:



Named Executive Officer		Target Equity Compensation Grant (% of Base Salary) ⁽¹⁾
Robert G. Phillips		250%
Michael J. Campbell		150%
J. Heath Deneke		175%
William C. Gautrueax		175%
William H. Moore		140%


(1)	Includes both awards with respect to Crestwood Equity Partners LP and Crestwood Midstream Partners LP.

Based on the foregoing targets, on January 17, 2014, our Compensation Committees approved the annual grant of restricted units under the Crestwood Equity Partners LP Long Term Incentive Plan and Crestwood Midstream Partners LP Long Term Incentive Plan to the NEOs as follows:



Employee	CEQP Units	CMLP Units
Robert G. Phillips⁽¹⁾	20,038	11,698
Michael J. Campbell	22,026	12,859
J. Heath Deneke⁽¹⁾	9,315	5,438
William C. Gautreaux	27,946	16,315
William H. Moore	17,988	10,502

(1) The level of equity compensation awarded to Mr. Phillips and Mr. Deneke was reduced one-third in 2014 from the target grants set forth above to reflect their prior awards of incentive units in Crestwood Holdings Partners LLC.

The awards vest in one-third annual increments beginning on the first anniversary of the grant date.

“Bridge” Long Term Incentive Awards in 2014

In connection with the Inergy/Crestwood Transaction, all outstanding restricted units held by our NEOs during Fiscal 2013 (other than Mr. Gautreaux whose awards vested on June 19, 2014) vested on or before December 31, 2013. As a result of this vesting event, the Compensation Committee recognized a significant retention issue over the next two years due to the lack of unvested long term equity held by our NEOs. Accordingly, on January 17, 2014, the Compensation Committees approved a one-time “bridge” grant of restricted units under the Crestwood Equity Partners LP Long Term Incentive Plan and Crestwood Midstream Partners LP Long Term Incentive Plan to the NEOs as follows:



Employee	CEQP Units	CMLP Units
Robert G. Phillips	40,076	23,396
Michael J. Campbell	44,053	25,718
J. Heath Deneke	18,631	10,877
William C. Gautreaux	55,892	32,630
William H. Moore	35,977	21,003

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The “bridge” awards vest over a two year period beginning one year from the grant date (2/3 in 2015 and 1/3 in 2016).

Discretionary Long Term Incentive Awards in 2014

In February 2014, in connection with its review of the performance of our Chief Executive Officer the board of directors approved a one-time, discretionary award of $3.1 million in equity to be allocated equally between CEQP and CMLP restricted units based on the closing price of CEQP and CMLP common units on the grant date. The awards will vest ratably over a three-year period beginning one year from the grant date. The equity award was granted in recognition of our Chief Executive Officer’s significant role and leadership in consummating the Inergy/Crestwood Transaction and post-transaction integration efforts. The size of the award was determined in the board of directors’ sole discretion in light of the significance of the transaction.

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

As described above, in January 2014 we entered into a new employment agreement with each named executive officer who remained employed by us at such time. The Executive Employment Agreements replaced any existing employment agreement and supersede the named executive officer’s participation in the Officer Severance Plan. For a more detailed description of the severance provided for pursuant to the Executive Employment Agreements, see “Narrative Disclosure to Summary Compensation and Grants of Plan Based Awards Tables”.

On January 16, 2015, Michael J. Campbell resigned as our Chief Financial Officer, with such resignation to be effective on March 31, 2015.

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, subject to his continued service through March 31, 2015: (i) up to $1,600,000 of severance payments to be allocated 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.

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.

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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, 2014.

David Wood

Warren Gfeller

Members of the Compensation Committee

Summary Compensation Table for Fiscal 2014

The following table sets forth the cash and non-cash compensation earned by our NEOs for the fiscal years ended December 31, 2014, the Transition Period (October 1, 2013 - December 31, 2013), September 30, 2013, and September 30, 2012.



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	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
Michael J. Campbell⁽²⁾ Senior Vice President- Chief Financial Officer	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
	2012	175,000	200,000	434,000	—	6,750	815,750
William C. Gautreaux President, Liquids and Crude	2014	435,000	293,625	2,256,796	—	15,363	3,000,784
	Transition⁽¹⁾	106,442	—	—	—	733	107,175
	2013	250,000	391,500	280,800	—	6,538	928,838
	2012	235,577	300,000	651,000	—	6,356	1,192,933
William H. Moore Senior Vice President, Strategy and Corporate Development	2014	350,000	350,000	1,452,659	—	15,654	2,168,313
J. Heath Deneke, President, Natural Gas	2014	435,000	430,650	752,265	—	15,780	1,633,695
J. Heath Deneke, President, Natural Gas	Transition⁽¹⁾	116,442	391,500	—	—	1,339	509,281


(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)

On January 16, 2015, Michael J. Campbell resigned as Chief Financial Officer of our general partner and CMLP’s general partner, effective as of March 31, 2015. On January 20, 2015, the board of directors of general partner and CMLP’s general partner appointed Robert T. Halpin as Chief Financial Officer effective on the effective date of Mr. Campbell’s resignation. 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.

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(4) “All Other Compensation” for Fiscal Year 2014 consisted of the following:



Name	Unit Purchase Plan Employer Match ($)	401(k) Matching Contributions ($)	Group Term Life Insurance ($)	Total ($)
Robert G. Phillips	—	15,600	1,188	16,788
Michael J. Campbell	—	13,192	90	13,282
William C. Gautreaux	2,175	13,050	138	15,363
William H. Moore	—	15,600	54	15,654
J. Heath Deneke	—	15,600	180	15,780


(5)	Mr. Phillips received a $655,000 bonus payment in January 2014 pursuant to a Legacy Crestwood incentive plan. The amount reflected in the table above represents the pro-rata portion of the bonus in Fiscal 2013.

Grants of Plan-Based Awards Table for Fiscal 2014

The following table provides information concerning each grant of an award made to our NEOs during Fiscal 2014.



		Estimated Future Payouts Under Non-Equity Incentive Plan Awards
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)⁽⁴⁾	All Other Unit Awards(#)	Grant Date Fair Value of Unit and Option Awards ($)
Robert G. Phillips	1/17/2014⁽¹⁾	—	655,000	655,000	20,038 (CEQP) 11,698 (CMLP)	265,303 274,804
	1/17/2014⁽²⁾	—	—	—	40,076 (CEQP) 23,396 (CMLP)	530,606 548,168
	2/26/2014⁽³⁾	—	—	—	114,054 (CEQP) 67,804 (CMLP)	1,549,994 1,549,999
Michael J. Campbell	1/17/2014⁽¹⁾	—	400,000	400,000	22,026 (CEQP) 12,859 (CMLP)	291,624 301,286
Michael J. Campbell	1/17/2014⁽²⁾	—	—	—	44,053 (CEQP) 25,718 (CMLP)	583,262 602,573
William C. Gautreaux	1/17/2014⁽¹⁾	—	391,500	391,500	27,946 (CEQP) 16,315 (CMLP)	370,005 382,260
William C. Gautreaux	1/17/2014⁽²⁾	—	—	—	55,892 (CEQP) 32,630 (CMLP)	740,010 764,521
William H. Moore	1/17/2014⁽¹⁾	—	350,000	350,000	17,988 (CEQP) 10,502 (CMLP)	238,161 246,062
William H. Moore	1/17/2014⁽²⁾	—	—	—	35,977 (CEQP) 21,003 (CMLP)	476,335 492,100
J. Heath Deneke	1/17/2014⁽¹⁾	—	391,500	391,500	9,315 (CEQP) 5,438 (CMLP)	123,331 127,412
J. Heath Deneke	1/17/2014⁽²⁾	—	—	—	18,631 (CEQP) 10,877 (CMLP)	246,674 254,848


(1)	Annual Restricted Unit Award - The restricted units vest ratably (33.33%) over a three year period beginning on the first anniversary of the grant date.


(2)	Bridge Restricted Unit Award - The restricted units vest in two installments as follows: 66.66% on the first anniversary of the grant date and the remaining 33.33% on the second anniversary of the grant date.


(3)	The restricted units vest ratably (33.33%) over a three year period beginning on the first anniversary of the grant date.

(4)

The amounts in these columns reflect the “Target” and “Maximum” bonus award amounts for our NEOs with respect to cash bonuses awarded pursuant to such named executive officer’s employment agreement in effect during Fiscal 2014. The “Maximum” amount may be increased by the discretion of the Compensation Committee as described above in the “Compensation Discussion and Analysis -Incentive Awards.”

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

Employment Agreements Entered into During Fiscal 2014

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

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

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 2014 Fiscal Year-End

The following table summarizes the outstanding equity awards as of the end of Fiscal 2014 for the each of our NEOs. The table includes restricted units of Crestwood Equity Partners LP (NYSE: CEQP) granted under the Crestwood Equity Partners LP Long Term Incentive Plan and restricted units of Crestwood Midstream Partners L.P. (NYSE: CMLP) granted under the Crestwood Midstream 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 (#)

Market Value of Units That Have Not Vested ($)⁽¹⁾

Robert G. Phillips

—

174,168 (CEQP)⁽²⁾

102,898 (CMLP)⁽³⁾

1,410,761 (CEQP)

1,561,992 (CMLP)

Michael J. Campbell

—

66,079 (CEQP)⁽²⁾

38,577 (CMLP)⁽³⁾

535,240 (CEQP)

585,599 (CMLP)

William C. Gautreaux

—

83,838 (CEQP)⁽²⁾

48,945 (CMLP)⁽³⁾

679,088 (CEQP)

742,985 (CMLP)

William H. Moore

—

53,965 (CEQP)⁽²⁾

31,505 (CMLP)⁽³⁾

437,117 (CEQP)

478,246 (CMLP)

J. Heath Deneke

—

27,946 (CEQP)⁽²⁾

16,315 (CMLP)⁽³⁾

226,363 (CEQP)

247,662 (CMLP)

(1) Market value for CEQP units based on the NYSE closing price of $8.10 on December 31, 2014 and market value for CMLP units based on the NYSE closing price of $15.18 on December 31, 2014.

(2)

Mr. Phillips’ restricted units vest as follows: 33,396 on January 17, 2015, 38,018 on February 26, 2015, 20,038 on January 17, 2016, 38,018 on February 26, 2016, 6,680 on January 17, 2017 and 38,018 on February 26, 2017. Mr. Campbell’s restricted units vest as follows: 36,711 on January 17, 2015 and 29,368 on March 31, 2015. Mr. Gautreaux’s restricted units vest as follows: 46,576 on January 17, 2015, 27,946 on January 17, 2016 and 9,316 on January 17, 2017. Mr. Moore’s restricted units vest as follows: 29,980 on January 17, 2015, 17,989 on January 17, 2016 and 5,996 on January 17, 2017. Mr. Deneke’s restricted units vest as follows: 15,525 on January 17, 2015, 9,316 on January 17, 2016 and 3,105 on January 17, 2017.

(3)

Mr. Phillips’ restricted units vest as follows: 19,496 on January 17, 2015, 22,601 on February 26, 2015, 11,698 on January 17, 2016, 22,601 on February 26, 2016, 3,900 on January 17, 2017 and 22,602 on February 26, 2017. Mr. Campbell’s restricted units vest as follows: 21,431 on January 17, 2015 and 17,146 on March 31, 2015. Mr. Gautreaux’s restricted units vest as follows: 27,191 on January 17, 2015, 16,315 on January 17, 2016 and 5,439 on January 17, 2017. Mr. Moore’s restricted units vest as follows: 17,502 on January 17, 2015, 10,502 on January 17, 2016 and 3,501 on January 17, 2017. Mr. Deneke’s restricted units vest as follows: 9,063 on January 17, 2015, 5,439 on January 17, 2016 and 1,813 on January 17, 2017.

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Units Vested During Fiscal 2014

The following table provides information regarding restricted unit vesting during Fiscal 2014 for each of the NEOs. Value realized on upon vesting was calculated by using the closing price of Crestwood Equity Partners LP and Crestwood Midstream Partners LP on the date that the award vested, as applicable



	UNIT AWARDS
Name	Number of Units Acquired On Vesting (#)	Value Realized on Vesting ($)
Robert G. Phillips	—	—
Michael J. Campbell	—	—
William C. Gautreaux	110,000 (CEQP) 30,00 (CMLP)	1,606,400 (CEQP) 664,800 (CMLP)
William H. Moore	—	—
J. Heath Deneke	—	—

Pension Benefits during Fiscal 2014

We do not offer any pension benefits.

Non-qualified Deferred Compensation during Fiscal 2014

We have no non-qualified deferred compensation plans.

Potential Payments upon a Change in Control or Termination during Fiscal 2014

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 units in Crestwood Equity Partners LP and Crestwood Midstream Partners LP 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, 2014.



Name	Cash Severance ($)⁽¹⁾	Accelerated Vesting of Restricted Units ($)⁽²⁾	Benefit Continuation ($)⁽³⁾	Total ($)
Robert G. Phillips	3,930,000	2,972,752	21,243	6,923,995
Michael Campbell ⁽⁴⁾	1,500,000	1,120,839	24,998	2,645,837
William C. Gautreaux	1,555,125	1,422,073	24,645	3,001,843
William H. Moore	1,400,000	915,362	24,645	2,340,007
J. Heath Deneke	1,692,150	474,024	25,101	2,191,275

(1)

As described above, amounts reflect cash severance payments payable upon a qualifying termination without “employer cause” or the named executive officer resigns due to “employee cause” the named executive officer will be entitled to receive pursuant to his Employment Agreements, subject to the executive’s execution of a release of claims. The severance payments are equal to two (or, in the case of Mr. Phillips, three) times the sum of the named executive officer’s base salary and average annual bonus for the prior two years.


(2)	The amounts reflected in the table above include the value of restricted units in Crestwood Equity Partners LP and Crestwood Midstream Partners LP which would be subject to accelerated vesting upon a change of control of Crestwood Equity Partners LP or Crestwood Midstream Partners LP,

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respectively, 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 $8.10 for CEQP units on December 31, 2014 and the NYSE closing price of $15.18 on for CMLP units December 31, 2014.


(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.

(4)

On January 16, 2015, Michael J. Campbell resigned as Chief Financial Officer of our general partner and CMLP’s general partner, with such resignation to be effective as of March 31, 2015. 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, subject to his continued service through March 31, 2015: (i) $1,600,000 of severance payments to be paid in installments over 18 months after his date or resignation, (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.

Director Compensation Table for Fiscal 2014

The following table sets forth the cash and non-cash compensation for Fiscal 2014 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	80,000	80,398	160,398
Michael France	60,000	80,398	140,398
Warren Gfeller	80,000	80,398	160,398
Arthur Krause	90,000	80,398	170,398
Randy Moeder	100,000	80,398	180,398
John Sherman	60,000	80,398	140,398
John Somerhalder II	80,000	80,398	160,398
David Wood	70,000	80,398	150,398

(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, 2014, our non-employee directors held the following restricted unit awards: Mr. Bledsoe, Mr. France, Mr. Sherman, Mr. Somerhalder II and Mr. Wood each held 7,099 restricted units; Mr. Krause and Mr. Gfeller each held 9,719 restricted units and Mr. Moeder held 10,972 restricted units.

Compensation of Directors during Fiscal 2014

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 directors serves on both our board of directors and the board of directors of CMLP GP, the director receives 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 serve as the members of the compensation committee, and neither of them was an officer or employee of our company or any of its subsidiaries during Fiscal 2014.

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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, 2014, regarding the beneficial ownership of our limited partner 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.

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⁾	Limited Partner Units Beneficially Owned	Percentage of Limited Partner Units Beneficially Owned
Crestwood Holdings Partners LLC⁽²⁾⁽⁴⁾	53,809,398	28.7	%
Crestwood Gas Services Holdings LLC⁽³⁾⁽⁴⁾	53,809,398	28.7	%
Neuberger Berman Group LLC⁽⁵⁾	30,355,803	16.2	%
Advisory Research, Inc.⁽⁶⁾	10,266,025	5.5	%
Robert G. Phillips	281,369	*
J. Heath Deneke	77,271	*
William C. Gautreaux	2,538,666	1.4	%
Michael J. Campbell	132,013	*
Steven M. Dougherty	60,789	*
Joel C. Lambert	71,733	*
William H. Moore	80,103	*
Joel D. Moxley	40,013	*
John J. Sherman	18,707,643	10.0%
Alvin Bledsoe	16,975	*
Michael G. France	16,975	*
Warren H. Gfeller	137,494	*
Arthur B. Krause	132,884	*
Randy Moeder	25,607	*
John W. Somerhalder II	16,975	*
David M. Wood	36,975	*
Directors and executive officers as a group (16 persons)	22,373,485	11.9	%

* 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) Crestwood Holdings is the ultimate parent company of Crestwood Gas Services Holdings LLC and may, therefore, be deemed to beneficially own the units held by Crestwood Holdings.

(3) Crestwood Gas Services Holdings LLC, an indirect wholly owned subsidiary of Crestwood Holdings, owns a 100% interest in our General Partner and a 28.9% limited partner interest in us.

(4) Crestwood Holdings has shared voting power and shared investment power with Crestwood Gas Services Holdings LLC, Crestwood Holdings LLC, Crestwood Holdings II 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 49,421,509 common units and 4,387,889 subordinated units of Crestwood Equity Partners LP. Crestwood Gas Services Holdings LP indirectly owns the sole general partner of CEQP.

(5) According to a Schedule 13G filed by Neuberger Berman Group LLC, with the SEC on February 12, 2015, Neuberger Berman Group LLC has shared voting power over 29,176,573 common units and dispositive power over 30,355,803 common units. The address of Neuberger Berman Group LLC is 605 Third Avenue, New York, New York 10158. Neuberger Berman Group LLC disclaims beneficial ownership of these units.

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(6) According to a Schedule 13GF filed by Piper Jaffray Companies, with the SEC on February 17, 2015. Advisory Research, Inc., a wholly-owned subsidiary of Piper Jaffray Companies, is the beneficial owner of 10,266,025 common units. The address of Advisory Research, Inc., is 180 N. Stetson, Chicago, IL 60601. Piper Jaffray Companies may be deemed to be the beneficial owner of these 10,266,025 common units through control of Advisory Research, Inc. Piper Jaffray Companies disclaims beneficial ownership of these units.

See Item 5 of this report for certain information regarding securities authorized for issuance under 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

Omnibus Agreement

We have entered into an omnibus 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; and


•	certain indemnification obligations.

Our indemnification obligations to CMLP include certain liabilities relating to:

•

for three years after CMLP’s December 2011 initial public offering (IPO) , certain environmental liabilities attributable to the ownership and operation of CMLP’s assets prior to the CMLP IPO, including (i) any violation or correction of a violation of environmental laws associated with CMLP’s assets, where a correction of violation would include assessment, investigation, monitoring, remediation, or other similar action and (ii) any event, omission or condition associated with the ownership or operation of CMLP’s assets (including the presence or release of hazardous materials), including (a) the cost and expense of any assessment, investigation, monitoring, remediation or other similar action, (b) the cost and expense of the preparation and implementation of any closure activity or remedial or corrective action required under environmental laws, and (c) the cost and expense of any environmental or toxic tort litigation;


•	environmental liabilities attributable with CMLP’s prior ownership and operation of Tres Palacios Gas Storage LLC;


•	the ownership and operation of CMLP’s assets prior to its IPO;

provided, that (i) the aggregate amount payable to CMLP pursuant to the first bullet point above will not exceed $15 million and (ii) amounts are only payable to CMLP pursuant to the first and second bullet points above after liabilities relating to the first and second bullet points have exceeded $100,000 and then only for such amounts in excess of $100,000;


•	until the first day after the applicable statute of limitations, any of CMLP’s federal, state and local income tax liabilities attributable to the ownership and operation of CMLP’s assets prior to the CMLP IPO;


•	for three years after the closing of the CMLP IPO, the failure to have all necessary consents and governmental permits where such failure renders CMLP unable to use and operate its assets in substantially the same manner in which they were used and operated immediately prior to the CMLP IPO; and


•	for three years after the closing of the CMLP IPO, CMLP’s failure to have valid and indefeasible easement rights, rights-of-way, leasehold and/or fee ownership interest in and to the lands on which CMLP’s assets are located and such failure prevents CMLP from using or operating its assets in substantially the same manner as they were used or operated immediately prior to the CMLP IPO.

We will not be required to indemnify CMLP for any claims, losses or expenses or income taxes referred to above to the extent such were either (i) reserved for in CMLP’s financial statements as of the closing of the CMLP IPO or (ii) CMLP recovers any such amounts under available insurance coverage, from contractual rights or other recoveries against any third party.

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CMLP’s indemnification obligations to us, our general partner and to our affiliates (other than CMLP and its subsidiaries) include certain liabilities relating to:

•

certain environmental liabilities attributable to the ownership and operation of CMLP’s assets, but only to the extent the violations, events, omissions or conditions giving rise to such covered environmental liabilities occur after the closing of the CMLP IPO; provided , that (i) our aggregate liability for such covered environmental liabilities will not exceed $15 million and (ii) amounts are only payable by us pursuant to this bullet point after liabilities relating to such covered environmental losses have exceeded $100,000 and then only for such amounts in excess of $100,000; and


•	losses suffered or incurred by us by reason of or arising out of events and conditions associated with the operation of CMLP’s assets that occur on or after the CMLP IPO (other than covered environmental losses, which are covered by the preceding bullet).

With respect to the provision by us of certain administrative services and such management and operating services as may be necessary to manage and operate CMLP’s business, the omnibus agreement addresses certain aspects of our relationship with CMLP, including:


•	the provision by us to CMLP of certain specified administrative services necessary to run CMLP’s business, including the provision of such employees as may be necessary to operate and manage CMLP’s business, and CMLP’s agreement to reimburse us for all reasonable costs and expenses incurred in connection with such services;


•	CMLP’s agreement to reimburse us for all expenses we incurred as a result of CMLP becoming a publicly traded partnership; and


•	CMLP’s agreement to reimburse us for all expenses that we incurred or payments we make on CMLP’s behalf with respect to insurance coverage for our business.

Except for the indemnification provisions, the omnibus agreement may be terminated by us with 180 days’ prior written notice if (i) Crestwood Midstream GP LLC is removed as CMLP’s general partner under circumstances where “cause” does not exist and the common units held by us and our affiliates were not voted in favor of such removal; (ii) a change of control of CMLP occurs; or (iii) a change of control of us occurs. Except for the indemnification provisions, CMLP may terminate the omnibus agreement with 180 days’ prior written notice if a change of control of CMLP occurs, a change of control of us occurs or Inergy Holdings GP, LLC, the indirect owner of our general partner, acquires MGP GP, LLC, the entity that controls CMLP’s general partner, pursuant to a certain membership interest purchase agreement.

During the year ended December 31, 2014, CMLP paid approximately $56.7 million to us pursuant to the omnibus agreement.

Tax Sharing Agreement

We have entered into a tax sharing agreement with CMLP pursuant to which CMLP will reimburse 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 with respect to taxable periods including or beginning on the closing date of the CMLP IPO. The amount of any such reimbursement will be limited to the tax that CMLP (and its subsidiaries) would have paid had CMLP not been included in a combined group with us. We may use our tax attributes to cause our combined or consolidated group, of which CMLP may be a member for this purpose, to owe no tax. However, CMLP would nevertheless reimburse us for the tax CMLP would have owed had the attributes not been available or used for our benefit, even though we had no cash expense for that period.

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.

Other Transactions with Related Persons

Our subsidiary, Crestwood Services LLC leases 100% of the operationally available storage capacity at CMLP’s Bath storage facility, under a five-year contract entered into in March 2011. As of December 31, 2014, the annual storage fee was approximately $13.6 million. The terms and conditions of the storage contract are consistent with the terms and conditions of the storage leases that Crestwood Services has entered into with third parties.

In addition, Crestwood Services leases 100% of the operationally available storage capacity at CMLP’s proposed Watkins Glen NGL storage facility under a five-year contract expiring March 31, 2016, subject to Crestwood Services' renewal rights. All

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revenue generated by Crestwood Services from subleasing storage capacity to third parties at the storage facility will be paid to CMLP during the term of the contract. The other terms and conditions of the storage contract are consistent with the terms and conditions of the storage contracts that Crestwood Services enters into with third-party customers.

On December 4, 2014, we sold Tres Palacios Gas Storage LLC to Tres Palacios Holdings LLC (TPH LLC), a newly formed joint venture between CMLP and an affiliate of Brookfield Infrastructure Group (Brookfield Infrastructure) for total cash consideration of approximately $132.8 million, of which $66.4 million was paid by CMLP. CMLP owns 50.01% of Tres Palacios Holdings LLC (TPH LLC) and is the operator of Tres Palacios and its assets. The terms of the transaction were unanimously approved by the board of directors of our general partner and CMLP’s general partner based on the unanimous approval and recommendation of their respective conflicts committees, which each consisted entirely of independent directors. As part of the transaction, we entered into an operating agreement with Tres Palacios pursuant to which we are responsible for the operating and maintenance of the Tres Palacios facilities as well as certain administrative and other general services identified in the agreement.

Review, Approval or Ratification of Transactions with Related Persons

Our related person transactions policy applies to any transaction since the beginning of our fiscal year (or currently proposed transaction) in which we or any of our subsidiaries was or is to be a participant, the amount involved exceeds $120,000 and any director, director nominee, executive officer, 5% or greater unitholder (or their immediate family members) had, has or will have a direct or indirect material interest. A transaction that would be covered by this policy would include, but not be limited to, any financial transaction, arrangement or relationship (including any indebtedness or guarantee of indebtedness) or any series of similar transactions, arrangements or relationships.

Under our related person transactions policy, related person transactions may be entered into or continue only if the transaction is deemed to be “fair and reasonable” to us, in accordance with the terms of our partnership agreement. Under our partnership agreement, transactions that represent a “conflict of interest” may be approved in one of three ways and, if approved in any of those ways, will be considered “fair and reasonable” to us and the holders of our common units. The three ways enumerated in our related person transactions Policy for reaching this conclusion include:


(i)	approval by the Conflicts Committee of the Board (the Conflicts Committee) under Section 7.9 of our partnership agreement (Special Approval);

(ii)

approval by our Chief Executive Officer applying the criteria specified in Section 7.9 of our partnership agreement if the transaction is in the normal course of the partnership’s business and is (a) on terms no less favorable to the partnership than those generally being provided to or available from unrelated third parties or (b) fair to the partnership, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to the Partnership); and


(iii)	approval by an independent committee of the Board (either the Audit Committee or a Special Committee) applying the criteria in Section 7.9 of our partnership agreement.

Once a transaction is approved in any of these ways, it is “fair and reasonable” and accordingly deemed (i) approved by all of our partners and (ii) not to be a breach of any fiduciary duties of general partner.

Our general partner determines in its discretion which method of approval is required depending on the circumstances.

Under our partnership agreement, when determining whether a related person transaction is “fair and reasonable,” if our general partner elects to adopt a resolution or a course of action that has not received Special Approval, then our general partner may consider:


•	the relative interests of any party to such conflict, agreement, transaction or situation and the benefits and burdens relating to such interest;


•	any customary or accepted industry practices and any customary or historical dealings with a particular person;


•	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.

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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-empanelling 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.

Item 14. Principal Accountant Fees and Services.

Effective as of July 23, 2013, the Audit Committee of the Board (the Board) of Directors of Crestwood Equity GP LLC dismissed Deloitte & Touche LLP (Deloitte) as the independent registered public accounting firm of Legacy Crestwood GP and 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, 2013. The dismissal was effective as of the date of the completion by Deloitte of the audit of Legacy Crestwood GP. Legacy Crestwood GP is the accounting predecessor to the partnership and its financial statements now constitute the primary financial statements of the partnership.

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The audit report on the financial statements of Legacy Crestwood GP for the fiscal years ended December 31, 2012 and December 31, 2011 issued by Deloitte did not contain any adverse opinion or disclaimer of opinion, nor was the report qualified or modified as to uncertainty, audit scope or accounting principles. Furthermore, during Legacy Crestwood GP’s two most recent fiscal years ended December 31, 2012 and December 31, 2011 and the subsequent interim period through July 23, 2013, (1) there were no disagreements between Legacy Crestwood GP and Deloitte on any matter of accounting principles or practices, financial statement disclosure or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Deloitte, would have caused Deloitte to make reference thereto in its report on Legacy Crestwood GP’s financial statements for such periods, and (2) there were no “reportable events” as that term is described in Item 304(a)(1)(v) of Regulation S-K.

In addition, during Legacy Crestwood GP’s fiscal years ended December 31, 2012 and 2011 and the subsequent interim period ending July 23, 2013, Legacy Crestwood GP did not consult E&Y in regards to Legacy Crestwood GP’s financial statements, which were audited by Deloitte as its independent accountant, with respect to (1) the application of accounting principles to a specified transaction, either completed or proposed and (2) the type of audit opinion that was rendered on Legacy Crestwood GP’s financial statements or might be rendered on Legacy Crestwood GP’s financial statements. During such fiscal years and subsequent interim period ending July 23, 2013, Legacy Crestwood GP did not consult with E&Y in regards to Legacy Crestwood GP’s financial statements with respect to any matter that was the subject of a “disagreement” or a “reportable event” as those terms are described in Item 304(a)(1) of Regulation S-K.

The following table presents fees billed for professional audit services rendered for the audit of our and CMLP's annual financial statements and for other services for the years ended December 31, 2014 and 2013 (in millions):



	Ernst & Young LLP				Deloitte & Touche LLP
	2014		2013		2013
Audit fees⁽¹⁾	$	2.7	$	4.2	$	1.5


(1)	Includes fees for the integrated audit of annual financial statements and internal control over financial reporting, reviews of related quarterly financial statements and reviews of and issuances of comfort letters related to other documents filed with the SEC.

The audit committee of our general partner reviewed and approved all audit and non-audit services provided to us during 2014. For information regarding the audit committee’s pre-approval policies and procedures related to the engagement by us of an independent accountant, see our audit committee charter on our website at www.crestwoodlp.com.

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PART IV

Item 15. Exhibits, Financial Statement Schedules.


(a)	Exhibits, Financial Statements and Financial Statement Schedules:


1.	Financial Statements:

See Index Page for Financial Statements


2.	Financial Statement Schedules:

Schedule I: Parent Only Condensed Financial Statements

Schedule II: Valuation and Qualifying Accounts

Other financial statement schedules have been omitted because they are either not required, are immaterial or are not applicable or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.


3.	Exhibits:



Exhibit Number		Description
2.1		Agreement and Plan of Merger, dated August 7, 2010, among Inergy, L.P., Inergy GP, LLC, Inergy Holdings, L.P., NRGP Limited Partner, LLC and NRGP MS, LLC (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed on August 9, 2010)

2.2		First Amended and Restated Agreement and Plan of Merger, dated September 3, 2010, among Inergy, L.P., Inergy GP, LLC, Inergy Holdings, L.P., NRGP Limited Partner, LLC and NRGP MS, LLC (incorporated herein by reference to Exhibit 2.1 to Inergy, L.P.’s Form 8-K filed on September 7, 2010)

2.3		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)

2.4		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)

2.5		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)

2.6		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)

2.7		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)

2.8		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)

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)

3.1A		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)

3.1B		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 the Partnership’s Form 8-K filed on October 10, 2013)

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Exhibit Number		Description
3.2		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)

3.3		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)

3.3A		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 the Partnership’s Form 10-Q filed on November 8, 2013)

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

3.4A		Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of 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 the Partnership’s Form 10-Q filed on November 8, 2013)

4.1		Specimen Unit Certificate for Common Units (incorporated herein by reference to Exhibit 4.3 to Inergy L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)

4.2		Indenture dated February 2, 2009, by and among Inergy, L.P., Inergy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on February 3, 2009)

4.3		First Supplemental Indenture and Amendment-Subsidiary Guarantee dated November 5, 2010, to the Indenture, dated February 2, 2009 (incorporated herein by reference to Exhibit 10.4 to Inergy, L.P.’s Form 8-K filed on November 5, 2010)

4.4		Indenture dated September 27, 2010, by and among Inergy, L.P., Inergy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on September 28, 2010)

4.5		First Supplemental Indenture and Amendment-Subsidiary Guarantee dated November 5, 2010, to the Indenture dated September 27, 2010 (incorporated herein by reference to Exhibit 10.5 to Inergy, L.P.’s Form 8-K filed on November 5, 2010)

4.6		Indenture dated as of February 2, 2011, by and among Inergy, L.P., Inergy Finance Corp., the Subsidiary Guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.3 to Inergy, L.P.’s Form 8-K filed on February 3, 2011)

4.7		Second Supplemental Indenture dated July 17, 2012, to the Indenture dated September 27, 2010 (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on July 19, 2012)

4.8		Second Supplemental Indenture dated July 17, 2012, to the Indenture dated February 2, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy, L.P.’s Form 8-K filed on July 19, 2012)

4.9		Third Supplemental Indenture dated August 1, 2012, to the Indenture dated September 27, 2010 (incorporated herein by reference to Exhibit 4.1 to Inergy, L.P.’s Form 8-K filed on August 3, 2012)

4.10		Third Supplemental Indenture dated August 1, 2012, to the Indenture dated February 2, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy, L.P.’s Form 8-K filed on August 3, 2012)

4.11		Second Supplemental Indenture dated August 1, 2012, to the Indenture dated February 2, 2009 (incorporated herein by reference to Exhibit 4.3 to Inergy, L.P.’s Form 8-K filed on August 3, 2012)

4.12		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 Michael Campbell and Crestwood Operations LLC dated as of January 21, 2014 (incorporated by reference Exhibit 10.2 to Crestwood Equity Partners LP’s Form 8-K filed on January 27, 2014)

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Exhibit Number		Description

*10.3		Employment Agreement between William Gautreaux and Crestwood Operations LLC dated as of January 21, 2014 (incorporated by reference to Exhibit 10.3 to Crestwood Equity Partners LP’s Form 8-K filed on January 27, 2014)

*10.4		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 10-K filed on February 28, 2014)

**10.5		Employment Agreement between William H. Moore and Crestwood Operations LLC

*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 Partner 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		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)

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

10.10		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)

10.11		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)

10.12		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)

10.13		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)

10.14		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)

10.15		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)

10.16		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)

10.17		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 Form 8-K filed on December 24, 2013)

10.18		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 Form 8-K filed on September 12, 2014)

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Exhibit Number		Description
10.19		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)

10.20		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)

10.21		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)

10.22		Support Agreement dated August 1, 2012, by and among Inergy , L.P., Suburban Propane Partners, L.P. and Suburban Energy Finance Corp. (incorporated by reference to Exhibit 10.1 to Inergy L.P.’s Form 8-K filed on August 3, 2012)

10.23		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)

10.24		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)

10.25		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)

**10.26		Member Interest Purchase Agreement dated as of December 3, 2014 between Tres Palacios Holdings LLC and Crestwood Equity Partners LP

**12.1		Computation of ratio of earnings to fixed charges

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

**23.2		Consent of Deloitte & Touche LLP

**31.1		Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

**31.2		Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended

**32.1		Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

**32.2		Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

**101.INS		XBRL Instance Document

**101.SCH		XBRL Taxonomy Extension Schema Document

**101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document

**101.LAB		XBRL Taxonomy Extension Label Linkbase Document

**101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document

**101.DEF		XBRL Taxonomy Extension Definition Linkbase Document

Table of Contents



*	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

Consolidated Financial Statements

December 31, 2014 and 2013 and each of the

Three Years in the Period Ended

December 31, 2014

Contents



Reports of Independent Registered Public Accounting Firm	102

Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial Reporting	104

Audited Consolidated Financial Statements:

Consolidated Balance Sheets	105

Consolidated Statements of Operations	106

Consolidated Statements of Comprehensive Income	107

Consolidated Statements of Partners’ Capital	108

Consolidated Statements of Cash Flows	109

Notes to Consolidated Financial Statements	111

101

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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, 2014 and 2013, and the related consolidated statements of operations, comprehensive income, partners’ capital and cash flows for each of the years then ended. 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.

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. An audit 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, as well as 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 Equity Partners LP at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for the years then ended, 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, 2014, 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 27, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2015

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Unitholders of Crestwood Equity Partners LP

We have audited the accompanying consolidated statement of operations, comprehensive income, cash flows, and partners’ capital of Crestwood Equity Partners LP (formerly known as Inergy, L.P. (formerly known as Crestwood Gas Services GP LLC)) and subsidiaries (the “Company”) for the year ended December 31, 2012. Our audit also included the financial statement schedule (Schedule I) for the year ended December 31, 2012 listed in the Index at Item 15(a)(2). These financial statements and the financial statement schedule are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements and the financial statement schedule 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 the financial statements are free of material misstatement. The Company was not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. Our audit 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, as well as evaluating the overall financial statement presentation. We believe that our audit provides a reasonable basis for our opinion.

In our opinion, such consolidated financial statements, present fairly, in all material respects, the results of operations and cash flows of Crestwood Equity Partners LP and subsidiaries for the year ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America. Also, in our opinion, such financial statement schedule, when considered in relation to the basic consolidated financial statements taken as a whole, presents fairly, in all material respects, the information set forth therein.

Our audit was conducted for the purpose of forming an opinion on the basic consolidated financial statements taken as a whole. With respect to the unaudited pro forma information presented in Note 3 for the acquisitions of Inergy Midstream, L.P. and Arrow Midstream Holdings, LLC, such information has not been subjected to the auditing procedures applied in our audit of the basic consolidated financial statements and, accordingly, we express no opinion on it.

/s/ DELOITTE & TOUCHE LLP

Houston, Texas

July 23, 2013

(August 5, 2013 as to Note 10)

(February 28, 2014 as to Note 17)

(March 4, 2014 as to Schedule I in Item 15(a)(2))

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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, 2014, 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, 2014, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), the 2014 consolidated financial statements of Crestwood Equity Partners LP and our report dated February 27, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2015

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

	December 31,
	2014		2013
Assets
Current assets:
Cash	$	8.8	$	5.2
Accounts receivable, less allowance for doubtful accounts of $0.1 million at December 31, 2014 and December 31, 2013	379.6		412.6
Inventory (Note 4)	46.6		73.6
Assets from price risk management activities	79.8		14.5
Prepaid expenses and other current assets	23.3		16.1
Total current assets	538.1		522.0

Property, plant and equipment (Note 4)	4,273.9		4,108.7
Less: accumulated depreciation and depletion	380.1		203.4
Property, plant and equipment, net	3,893.8		3,905.3

Intangible assets (Note 4)	1,441.9		1,466.4
Less: accumulated amortization	210.6		106.0
Intangible assets, net	1,231.3		1,360.4

Goodwill	2,491.8		2,552.2
Investment in unconsolidated affiliates (Note 6)	295.1		151.4
Other assets	11.3		31.9
Total assets	$	8,461.4	$	8,523.2

Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	241.2	$	379.0
Accrued expenses and other liabilities (Note 4)	154.6		177.1
Liabilities from price risk management activities	25.4		34.9
Current portion of long-term debt (Note 9)	3.7		5.1
Total current liabilities	424.9		596.1

Long-term debt, less current portion (Note 9)	2,392.8		2,260.9
Other long-term liabilities	47.2		140.4
Deferred income taxes	12.0		17.2
Commitments and contingencies (Note 15)

Partners’ capital (Note 12):
Crestwood Equity Partners LP partners' capital (186,403,667 and 185,274,279 common units issued and outstanding at December 31, 2014 and December 31, 2013)	776.2		831.6
Interest of non-controlling partners in subsidiaries	4,808.3		4,677.0
Total partners’ capital	5,584.5		5,508.6
Total liabilities and partners’ capital	$	8,461.4	$	8,523.2

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,
	2014			2013			2012
Revenues:
Gathering and processing	$	328.5		$	216.3		$	125.8
Storage and transportation	192.9			104.2			—
NGL and crude services	3,406.9			1,031.3			—
Related party (Note 16)	3.0			74.9			113.7
	3,931.3			1,426.7			239.5
Costs of product/services sold:
Gathering and processing	29.1			24.1			23.8
Storage and transportation	24.8			15.7			—
NGL and crude services	3,069.2			930.0			—
Related party (Note 16)	42.2			32.5			15.2
	3,165.3			1,002.3			39.0
Expenses:
Operations and maintenance	203.3			104.6			43.1
General and administrative (Note 16)	100.2			93.5			29.6
Depreciation, amortization and accretion	285.3			167.9			73.2
	588.8			366.0			145.9
Other operating income (expense):
Gain (loss) on long-lived assets, net	(1.9		)	5.3			—
Goodwill impairment	(48.8		)	(4.1		)	—
Gain (loss) on contingent consideration (Note 15)	(8.6		)	(31.4		)	6.8
Operating income	117.9			28.2			61.4

Earnings (loss) from unconsolidated affiliates, net	(0.7		)	(0.1		)	—
Interest and debt expense, net	(127.1		)	(77.9		)	(35.8		)
Other income, net	0.6			0.2			—
Income (loss) before income taxes	(9.3		)	(49.6		)	25.6
Provision for income taxes	1.1			1.0			1.2
Net income (loss)	(10.4		)	(50.6		)	24.4
Net (income) loss attributable to non-controlling partners	66.8			57.3			(9.5		)
Net income attributable to Crestwood Equity Partners LP	$	56.4		$	6.7		$	14.9

Subordinated unitholders' interest in net income	$	1.3		$	0.3		$	1.7
Common unitholders' interest in net income	$	55.1		$	6.4		$	13.2

Net income per limited partner unit:
Basic	$	0.30		$	0.06		$	0.38
Diluted	$	0.30		$	0.06		$	0.38

Weighted-average limited partners’ units outstanding (in thousands):
Basic	182,009			109,145			35,103
Dilutive units	4,388			4,388			4,388
Diluted	186,397			113,533			39,491

See accompanying notes.

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

	Year Ended December 31,
	2014			2013			2012
Net income (loss)	$	(10.4	)	$	(50.6	)	$	24.4
Change in fair value of Suburban Propane Partners, L.P. units (Note 12)	(0.5		)	(0.1		)	—
Comprehensive income (loss)	$	(10.9	)	$	(50.7	)	$	24.4

See accompanying notes.

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

	Crestwood Equity Partners			Non-Controlling Partners			Total Partners’ Capital
Balance at December 31, 2011	$	22.0		$	1,098.0		$	1,120.0
Net proceeds from the issuance of Legacy Crestwood common units	—			217.5			217.5
Issuance of Legacy Crestwood Class C units to Crestwood Gas Services	2.0			(2.0		)	—
Contributions from partner	6.6			284.2			290.8
Unit-based compensation charges	—			1.9			1.9
Taxes paid for unit-based compensation vesting	—			(0.4		)	(0.4		)
Distributions to partners	(13.8		)	(89.7		)	(103.5		)
Net income	14.9			9.5			24.4
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
Unit-based compensation charges	1.7			15.7			17.4
Taxes paid for unit-based compensation vesting	(2.8		)	(5.5		)	(8.3		)
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		)
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 Crestwood Midstream Partners LP 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		)
Unit-based compensation charges	3.9			17.4			21.3
Taxes paid for unit-based compensation vesting	(2.3		)	(1.6		)	(3.9		)
Distributions to partners	(102.5		)	(296.5		)	(399.0		)
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

See accompanying notes.

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

	Year Ended December 31,
	2014			2013			2012
Operating activities
Net income (loss)	$	(10.4	)	$	(50.6	)	$	24.4
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion	285.3			167.9			73.2
Amortization of debt-related deferred costs, discounts and premiums	8.5			9.2			5.5
Market adjustment on interest rate swaps	(2.7		)	(1.7		)	—
Unit-based compensation charges	21.3			17.4			1.9
(Gain) loss on long-lived assets, net	1.9			(5.3		)	—
Goodwill impairment	48.8			4.1			—
(Gain) loss on contingent consideration	8.6			31.4			(6.8		)
Loss from unconsolidated affiliates, net	0.7			0.1			—
Deferred income taxes	(5.2		)	(2.8		)	—
Other	—			(1.0		)	(0.2		)
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	60.4			(39.9		)	(3.5		)
Inventory	26.9			(23.6		)	—
Prepaid expenses and other current assets	(11.4		)	11.2			0.8
Accounts payable, accrued expenses and other liabilities	(96.4		)	44.2			6.8
Reimbursements of property, plant and equipment	21.5			—			—
Net liabilities from price risk management activities	(74.8		)	27.7			—
Net cash provided by operating activities	283.0			188.3			102.1

Investing activities
Acquisitions, net of cash acquired (Note 3)	(19.5		)	(555.6		)	(564.0		)
Purchases of property, plant and equipment	(424.0		)	(347.0		)	(52.6		)
Investment in unconsolidated affiliates	(108.6		)	(151.5		)	—
Proceeds from sale of Tres Palacios	66.4			—			—
Proceeds from sale of assets	2.7			11.2			—
Net cash used in investing activities	(483.0		)	(1,042.9		)	(616.6		)

See accompanying notes.

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CRESTWOOD EQUITY PARTNERS LP (FORMERLY INERGY, L.P.) CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (in millions)

	Year Ended December 31,
	2014			2013			2012
Financing activities
Proceeds from the issuance of long-term debt	$	2,823.9		$	2,466.9		$	706.7
Principal payments on long-term debt	(2,696.0		)	(1,967.6		)	(534.0		)
Payments on capital leases	(3.2		)	(4.3		)	(3.0		)
Payments for debt-related deferred costs	(1.9		)	(33.1		)	(11.4		)
Payments for deferred acquisition costs	—			—			(7.8		)
Contributions from partners	—			—			249.7
Distributions to partners	(102.5		)	(68.4		)	(13.8		)
Distributions paid to non-controlling partners	(296.5		)	(204.5		)	(89.7		)
Distribution for additional interest in Crestwood Marcellus Midstream LLC	—			(129.0		)	—
Net proceeds from issuance of Crestwood Midstream Partners LP common units	—			714.0			217.5
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	430.5			—			—
Taxes paid for unit-based compensation vesting	(3.9		)	(10.5		)	(0.4		)
Other	(0.7		)	0.1			—
Net cash provided by financing activities	203.6			859.7			513.8

Net change in cash	3.6			5.1			(0.7		)
Cash at beginning of period	5.2			0.1			0.8
Cash at end of period	$	8.8		$	5.2		$	0.1

Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	114.4		$	64.9		$	27.9
Cash paid during the period for income taxes	$	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	$	(40.6	)	$	(38.0	)	$	(1.7	)

Acquisitions, net of cash acquired:
Current assets	$	0.5		$	409.6		$	—
Property, plant and equipment	13.5			2,487.2			178.0
Intangible assets	9.4			660.9			384.0
Goodwill	3.6			2,195.4			4.1
Other assets	—			32.1			—
Current liabilities	(2.7		)	(420.6		)	(0.7		)
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		)	(1.4		)
Total acquisitions, net of cash acquired	$	19.5		$	555.6		$	564.0

See accompanying notes.

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CRESTWOOD EQUITY PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Organization and Description of Business

Organization

Crestwood Equity Partners LP (the Company or CEQP), is a publicly-traded (NYSE: CEQP) Delaware limited partnership formed in March 2001, that provides midstream solutions to customers in the crude oil, NGLs and natural gas sectors of the energy industry. We are engaged primarily in the gathering, processing, storage and transportation of natural gas and NGLs, the marketing of NGLs, and the gathering, storage and transportation of crude oil.

Our general partner, Crestwood Equity GP LLC, owns our non-economic general partnership interest. Our general partner is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve). As of December 31, 2014, First Reserve owns approximately 27% of our common units, 4,387,889 of our subordinated units, and approximately 11% of the Crestwood Midstream Partners LP (Crestwood Midstream) common units.

We indirectly own Crestwood Midstream GP LLC, the non-economic general partner of Crestwood Midstream and, consequently, manage and control Crestwood Midstream. As of December 31, 2014, we also own approximately 4% of Crestwood Midstream’s limited partnership interests and 100% of its incentive distribution rights (IDRs), which entitle us to receive 50% of all distributions paid by Crestwood Midstream in excess of its initial quarterly distribution of $0.37 per common unit.

On October 7, 2013, we changed our name from Inergy, L.P. to Crestwood Equity Partners LP. Unless otherwise indicated, references in this report to “we,” “us,” “our,” “ours,” “our company,” the “partnership,” the “Company,” “Crestwood,” and similar terms refer to either Crestwood Equity Partners LP itself or Crestwood Equity Partners LP and its consolidated subsidiaries, as the context requires. 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 refers to Crestwood Midstream Partners LP and its consolidated subsidiaries following the Crestwood Merger. See Note 3 for additional information on the Crestwood Merger.

Business Combination

On May 5, 2013, we and certain of our affiliates entered into a series of definitive agreements with Crestwood Holdings and certain of its affiliates under which, among other things, (i) we agreed to distribute to our common unitholders all of the NRGM common units owned by us; (ii) Crestwood Holdings agreed to acquire the owner of our general partner; (iii) Crestwood Holdings agreed to contribute ownership of Legacy CMLP's general partner and IDRs to us in exchange for common and subordinated units; and (iv) Legacy Crestwood agreed to merge with and into a subsidiary of Inergy Midstream in a merger in which Legacy CMLP unitholders received 1.07 NRGM common units for each Legacy CMLP common unit they owned and, Legacy CMLP unitholders (other than Crestwood Holdings), received a one-time $34.9 million cash payment at the closing of the Crestwood Merger, or $1.03 per unit, $24.9 million of which was paid by NRGM and $10 million of which was paid by Crestwood Holdings.

On June 5, 2013, Legacy Crestwood's general partner distributed to a wholly-owned subsidiary of Crestwood Holdings approximately 137,105 common units and approximately 21,588 Class D units of Legacy CMLP, representing all of the Legacy CMLP common and Class D units held by Legacy Crestwood's general partner.

On June 18, 2013, we distributed to our unitholders approximately 56.4 million NRGM common units, representing all of the NRGM common units held by us.

On June 19, 2013, Crestwood Holdings acquired the owner of our general partner and contributed to us ownership of Crestwood Gas Services GP, LLC (Legacy Crestwood GP), which owned 100% of the general partnership interests and IDRs of Legacy Crestwood. Crestwood Holdings and its ultimate parent company, First Reserve, acquired control of us as a result of these transactions.

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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 our common units pursuant to an option granted to Crestwood Holdings when it acquired our general partner.

Description of Business

We provide gathering, processing, storage and transportation solutions to customers in the crude oil, NGL and natural gas sectors of the energy industry. Our financial statements reflect three operating and reporting segments, including:

•

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

•

Storage and Transportation: our storage and transportation operations provide regulated natural gas storage and transportation services to producers, utilities and other customers. This segment primarily includes our natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake), and our natural gas transmission facilities (the North-South Facilities, the MARC I Pipeline, and the East Pipeline) in New York and Pennsylvania.

•

NGL and Crude Services: our NGL and crude services operations provide NGL and crude oil gathering, storage, marketing and transportation services to producers, refiners, marketers, and other customers. This segment primarily includes our NGL marketing, supply and logistics business (including our West Coast processing and fractionation operations, Seymour NGL storage facility, and our fleet of terminals and over-the-road and rail transportation assets) and our integrated Bakken crude oil footprint in North Dakota, which consists of (i) the COLT Hub, a crude oil rail loading and storage terminal, (ii) the Arrow crude oil, natural gas and water gathering systems, and (iii) our fleet of over-the-road crude and produced water transportation assets. This segment also includes our Bath storage facility and US Salt, a solution-mining and salt production company in New York.

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

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

Basis of Presentation

Our 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 combinations. The accounting for the reverse acquisition resulted in the legal acquiree (Legacy Crestwood GP) being the acquirer for accounting purposes. Although Legacy Crestwood GP was the acquiring entity for accounting purposes, we were the acquiring entity for legal purposes.

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.

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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, we sold our 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, we deconsolidated Tres Palacios and began accounting for the investment in Tres Holdings under the equity method of accounting through our 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 NGL and crude services operations and our storage and transportation operations are stated at the lower of cost or market and are computed predominantly using the average cost method.

Property, Plant and Equipment

Property, plant and equipment is recorded at is original cost of construction or, upon acquisition, at the fair value of the assets acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead and interest. We capitalize major units of property replacements or improvement and expense minor items. Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:



	Years
Gathering systems and pipelines	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.

When we retire property, plant and equipment, we charge accumulated depreciation for the original costs of the assets in addition to the cost to remove, sell or dispose of the assets, less their salvage value.

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 based on discounted cash flow projections, which is a Level 3 fair value measurement.

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Based on this evaluation, during the year ended December 31, 2014, we recorded a $13.2 million impairment in gain (loss) on long-lived assets in our consolidated statements of operations related to the property, plant and equipment of our gathering and processing assets located in the Granite Wash, which resulted from an announcement during the fourth quarter of 2014 by our major customer of those assets that they would cease any substantial drilling in the Granite Wash in the near future given current and future anticipated market conditions related to natural gas, which negatively impacted our future cash flows related to these operations. We had approximately $20.2 million of property, plant and equipment related to our gathering and processing operations located in the Granite Wash as of December 31, 2014, which represents the fair value of those assets based on its projected cash flows over the useful lives of the assets of 17 years and a discount rate of 9.0%, which are Level 3 fair value measurements. We did not record any impairments of our long-lived assets during the years ended December 31, 2013 and 2012 based on this evaluation.

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 reliably 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. For the year ended December 31, 2014, we recorded a $21.3 million impairment of our intangible assets in gain (loss) on long-lived assets in our consolidated statements of operations. This impairment was based on the intangible assets’ fair value, estimated primarily by utilizing discounted cash flow projections, which is a Level 3 fair value measurement. This impairment was primarily related to a full impairment of our intangible assets associated with our gathering and processing operations located in the Granite Wash. This impairment resulted from an announcement in the fourth quarter of 2014 by our major customer of those assets that they would cease any substantial drilling in the Granite Wash in the near future given current and future anticipated market conditions related to natural gas in the Granite Wash.

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

Our goodwill represents consideration paid in excess of the fair value of the identifiable assets acquired in a business combination. We evaluate goodwill for impairment annually on December 31, and whenever events indicate 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 a reporting unit to its carrying value (including goodwill). If the fair value exceeds the carrying amount, goodwill of the reporting unit is not considered impaired. For a further discussion of the goodwill recorded during the year ended December 31, 2014, see Note 3.

We estimate the fair value of our reporting units based on a number of factors, including the potential value we would receive if we sold the reporting unit, discount rates and projected cash flows, which are Level 3 fair value measurements. Estimating projected cash flows requires us to make certain assumptions as it relates to future operating performance. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. If the growth assumptions utilized in the current year impairment analysis prove inaccurate, we could incur an impairment charge.

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For the year ended December 31, 2014, we recorded an impairment of goodwill of approximately $48.8 million related to four of our 14 reporting units including Granite Wash (G&P), Fayetteville (G&P), US Salt (NGL and Crude Services), and Watkins Glen (NGL and Crude Services). The $14.2 million and $4.3 million impairments of our Granite Wash and Fayetteville goodwill, respectively, resulted from a decrease in anticipated revenues to be generated from those operations due to our primary customers in those operations announcing the cessation of any significant drilling in the near future given current and future anticipated market conditions in those areas. The $2.2 million impairment of our US Salt goodwill resulted from a decrease in anticipated revenues to be generated from those operations due primarily to the loss of a significant customer in 2014. The $28.1 million impairment of our Watkins Glen goodwill resulted from delays and related uncertainty in the permitting of our proposed NGL storage facility. We had approximately $72.5 million, $12.6 million and $66.2 million of goodwill remaining on our consolidated balance sheet as of December 31, 2014 related to our Fayetteville, US Salt and Watkins Glen reporting units, respectively, which represents the fair value of the goodwill related to those reporting units at December 31, 2014, which is a Level 3 fair value measurement.

For the year ended December 31, 2013, we recorded an impairment of goodwill of approximately $4.1 million on our Haynesville/Bossier Shale system as a result of a decrease in anticipated revenues to be generated from those operations due primarily to our inability to renew and extend a significant revenue contract that expired in mid-2013.

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. 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. Our fair value estimates are generally based on assumptions market participants would use, including marketing data obtained through the sales process.

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, 2014 and 2013, 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. 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.

For fixed-fee contracts, we recognize revenues based on the volume of crude oil, natural gas or produced water gathered, processed and treated or compressed, as applicable. For percent-of-proceeds contracts, we recognize revenues based on the value of products sold to third parties.

Sales of crude oil, NGLs and salt are recognized at the time product is shipped or delivered to the customer depending on the sales terms. NGL processing and fractionation fees are recognized upon delivery of the product. Revenues from the COLT Hub are recognized when the contractual services are provided, such as loading of customer rail cars. Revenues from storage

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and transportation contracts are recognized during the period in which the storage and transportation services are provided, such as providing storage and transportation services during the period a firm service contract is in place. 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, 2014 and 2013, we had deferred revenue of approximately $12.2 million and $2.1 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

We are a master 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 for accounting purposes or any derivatives designated as cash flow hedges for the years ended December 31, 2014, 2013 or 2012.

Unit-Based Compensation

Long-term incentive awards are granted under the Crestwood Equity and Crestwood Midstream incentive plans. Unit-based compensation awards consist of restricted units that are valued at the closing market price of CEQP's or CMLP'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.

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. See Note 13 for a further discussion of our long-term incentive plans.

New Accounting Pronouncements Issued But Not Yet Adopted

As of December 31, 2014, the following accounting standards had not yet been adopted by us.

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

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

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primarily to anticipated operating synergies between the assets acquired and our existing assets. These assets are included in our NGL and crude services segment.

LT Enterprises. On May 9, 2014, 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 NGL and crude services segment.

The acquisitions of Red Rock and LT Enterprises were not material to our NGL and crude services segment's results of operations for the 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 (CEQP) 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 CEQP was calculated based on the consolidated enterprise fair value of CEQP 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.

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



Current assets	$	224.5
Property, plant and equipment	2,088.1
Intangible assets	337.5
Other assets	12.7
Total identifiable assets acquired	2,662.8

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

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

Reductions of approximately $15.3 million from our preliminary estimates as of December 31, 2013 relate primarily to goodwill and were based on additional valuation information obtained on the components that comprise 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, $1,408.5 million is reflected in our NGL and crude services segment and $726.3 million is reflected in our storage and transportation segment. Goodwill recognized relates primarily to synergies and new expansion opportunities expected to result from the combination of

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Legacy Crestwood and Legacy Inergy. During 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, we recognized $916.7 million of operating revenues and $23.9 million of operating income related to this reverse acquisition. Transaction costs related to the Crestwood Merger were $3.4 million and $30.1 million for the years ended December 31, 2014 and 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.

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 NGL and crude services segment. Goodwill recognized relates 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.

2012 Acquisitions

Antero Acquisition

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On March 26, 2012, Crestwood Marcellus Midstream LLC (CMM) acquired from Antero gathering assets located in Harrison and Doddridge Counties, West Virginia (the Antero Acquisition) for approximately $376.8 million. The acquired assets consisted of a 33-mile low-pressure gathering system that delivers Antero’s Marcellus Shale production to various regional pipeline systems and MarkWest Energy Partners’ Sherwood Gas Processing Plant.

In connection with the Antero Acquisition, Legacy Crestwood 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. During 2012 and 2013, Antero did not meet the annual production level to earn additional payments. Based on our estimates of Antero’s 2014 production, we believed their production levels would exceed the annual production threshold in the earn-out provision and accordingly, we recognized a liability of $40.0 million and $31.4 million as of December 31, 2014 and 2013 that represented the fair value of the potential payments under the earn-out provision. We estimated the liability at December 31, 2013 based on the probability-weighted discounted cash flows using a 5.9% discount rate and our estimate of Antero’s production in 2014 (a Level 3 fair value measurement). In the first quarter of 2015, we expect to pay Antero $40.0 million under the earn-out provision.

Upon the closing of the Antero Acquisition, CMM entered into a 20-year fixed-fee, Gas Gathering and Compression Agreement (GGA) with Antero. The GGA provided for an area of dedication of approximately 127,000 gross acres, or 104,000 net acres, largely located in the rich gas corridor of the southwestern core of the Marcellus Shale play. Under the GGA, Antero committed to deliver minimum annual throughput volumes to us for a seven year period from January 1, 2012 to January 1, 2019, ranging from an average of 300 MMcf/d in 2012 to an average of 450 MMcf/d in 2018. During the period ended December 31, 2012, Antero delivered less than the minimum annual throughput volumes and at December 31, 2012, we recorded a receivable and deferred revenue of approximately $2.6 million due to Antero’s potential ability to recover this amount if Antero’s 2013 throughput volumes exceeded the minimum annual throughput volumes included in the GGA for 2013. In 2013, Antero paid us approximately $2.4 million to satisfy their minimum volume commitment. For the year ended December 31, 2013, Antero's throughput volumes exceeded the 2013 minimum thresholds and was sufficient to recover their 2012 minimum volume shortfall that was previously paid. As a result of Antero's recovery of their 2012 shortfall, we reclassified approximately $2.4 million from deferred revenue to other accounts payable at December 31, 2013 to reflect the amount we owed to Antero, which was paid in 2014. We reflect deferred revenue and other accounts payable as accrued expenses and other liabilities on our consolidated balance sheets.

Devon Acquisition

On August 24, 2012, we acquired certain gathering and processing assets in the NGL rich gas region of the Barnett Shale (the Devon Acquisition) from Devon Energy Corporation (Devon). We paid approximately $87.3 million for these assets. During the year ended December 31, 2013, we finalized the purchase price allocation of the assets acquired and liabilities assumed, and as a result, we reduced our depreciation, amortization and accretion expense by approximately $2.2 million.

The final purchase price allocation is as follows (in millions):



Cash	$	87.9
Total purchase price	$	87.9

Purchase price allocation:
Property, plant and equipment	$	88.6
Total assets	88.6

Asset retirement obligation	0.5
Environmental liability	0.2
Total liabilities	0.7

Total	$	87.9

Operating revenues, operating income and transaction costs related to the Devon Acquisition were immaterial to our results of operations for the year ended December 31, 2012. We believe that it is impracticable to present financial information for the

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acquired assets prior to the acquisition date due to the lack of availability of historical financial information related to the acquired assets, and because the 20-year fixed-fee gathering, processing and compression agreement with Devon has significantly different terms than the historical intercompany relationships between the acquired assets and Devon.

EMAC Acquisition

On December 28, 2012, CMM acquired all of the membership interest of E. Marcellus Asset Company, LLC (EMAC) from Enerven Compression, LLC (Enerven) for approximately $95.0 million. We financed this acquisition through CMM's credit facility. At the time of acquisition, EMAC’s assets consisted of four compression and dehydration stations located on our gathering systems in Harrison County, West Virginia. These assets provide compression and dehydration services to Antero under a compression services agreement through 2018. Antero has the option to renew the agreement for an additional five years upon expiration of the original agreement.

During the year ended December 31, 2013, we finalized the purchase price allocation of the assets acquired and liabilities assumed, and as a result, we reduced our depreciation, amortization and accretion expense by approximately $0.7 million. In addition, we recognized goodwill of approximately $8.6 million, primarily related to anticipated operating synergies between the assets acquired and our existing assets.

The final purchase price allocation is as follows (in millions):



Cash	$	95.0
Total purchase price	$	95.0

Purchase price allocation:
Property, plant and equipment	$	53.4
Intangible assets	33.9
Goodwill	8.6
Total assets	95.9

Asset retirement obligation	0.8
Environmental liability	0.1
Total liabilities	0.9

Total	$	95.0

Our intangible assets recorded as a result of the EMAC acquisition relate to the compression services agreements with Antero. These intangibles will be amortized over the life of the contracts. The financial results of EMAC prior to the date of acquisition were not material to our results of operations, therefore, pro forma information has not been provided.

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 Legacy Inergy reverse acquisition and the Arrow Acquisition had been included in our consolidated results for the year ended December 31, 2012 and for the entire year ended December 31, 2013 (in millions, except per unit information). All other acquisitions were immaterial in consolidation.

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	Year Ended December 31,
	2013		2012 (1)
Revenues	$	3,449.3	$	2,267.2
Net income	$	3.9	$	49.8

Net income per limited partner unit⁽²⁾:
Basic	$	0.04	$	0.31
Diluted	$	0.04	$	0.29

(1)

The year ended December 31, 2012 has also been adjusted to reflect the contribution of Inergy, L.P.'s retail operations to Suburban Propane Partners on August 1, 2012 and the subsequent distribution on September 14, 2012 of 99% of the Suburban Propane Partners LP units acquired in the contribution as if that contribution and subsequent distribution had been removed from the consolidated results of operations at the beginning of each period presented.

(2) Basic and diluted net income per limited partner unit for the year ended December 31, 2012 were computed 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.

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.

Note 4 – Certain Balance Sheet Information

Inventory

Inventory consisted of the following at December 31, 2014 and 2013 (in millions):



	December 31,
	2014		2013
NGLs	$	37.5	$	66.9
Parts, supplies and other	9.1		6.7
Total inventory	$	46.6	$	73.6

Property, Plant and Equipment

Property, plant and equipment consisted of the following at December 31, 2014 and 2013 (in millions):



	December 31,
	2014		2013
Gathering systems and pipelines	$	1,410.9	$	1,473.4
Facilities and equipment	1,648.3		1,186.5
Buildings, land, rights-of-way, storage contracts and easements	841.5		814.7
Vehicles	45.2		35.8
Construction in process	156.5		365.8
Base gas	37.5		102.0
Salt deposits	120.5		120.5
Office furniture and fixtures	13.5		10.0
	4,273.9		4,108.7
Less: accumulated depreciation and depletion	380.1		203.4
Total property, plant and equipment, net	$	3,893.8	$	3,905.3

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Depreciation. Depreciation expense totaled $184.2 million, $109.9 million and $49.1 million for the years ended December 31, 2014, 2013 and 2012. Depletion expense totaled $0.7 million and $0.4 million for the years ended December 31, 2014 and 2013. Legacy Crestwood GP did not have depletion expense.

Capitalized Interest. During the year ended December 31, 2014, 2013 and 2012 we capitalized interest of $7.7 million, $3.4 million and $0.2 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 $5.3 million and $5.0 million included in property, plant and equipment, net at December 31, 2014 and 2013.

Sale of Long-Lived Assets. In July 2013, Legacy Crestwood sold a cryogenic plant and associated equipment for approximately $11.0 million (net of fees) and recognized a gain of approximately $4.4 million for the year ended December 31, 2013.

Intangible Assets

Intangible assets consisted of the following at December 31, 2014 and 2013 (in millions):



	December 31,
	2014		2013
Customer accounts	$	583.7	$	576.9
Covenants not to compete	9.6		7.0
Gas gathering, compression and processing contracts	730.2		750.2
Acquired storage contracts	29.0		43.5
Trademarks	32.2		33.5
Deferred financing costs	57.2		55.3
	1,441.9		1,466.4
Less: accumulated amortization	210.6		106.0
Total intangible assets, net	$	1,231.3	$	1,360.4

The following table summarizes the total of accumulated amortization of intangible assets by the type of intangible asset at December 31, 2014 and 2013:



	December 31,
	2014		2013
Customer accounts	$	72.5	$	18.7
Covenants not to compete	3.2		1.0
Gas gathering, compression and processing contracts	98.0		67.3
Acquired storage contracts	12.7		8.6
Trademarks	6.7		2.3
Deferred financing costs	17.5		8.1
Total accumulated amortization	$	210.6	$	106.0

Amortization and interest expense for the years ended December 31, 2014, 2013 and 2012, was approximately $109.8 million, $66.7 million and $28.9 million.

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



Year Ending December 31,
2015	$	115.1
2016	101.2
2017	87.5
2018	73.9
2019	65.5

Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at December 31, 2014 and 2013 (in millions):



	December 31,
	2014		2013
Accrued expenses	$	52.5	$	40.3
Accrued property taxes	2.2		9.4
Accrued product purchases payable	0.7		1.6
Tax payable	1.6		14.8
Interest payable	23.5		16.7
Accrued additions to property, plant and equipment	20.0		58.2
Commitments and contingent liabilities (Note 15)	40.0		31.4
Capital leases	1.9		2.6
Deferred revenue	12.2		2.1
Total accrued expenses and other liabilities	$	154.6	$	177.1

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.

The following table presents the changes in the net asset retirement obligations for the years ended December 31, 2014 and 2013 (in millions):



	December 31,
	2014		2013
Net asset retirement obligation at January 1	$	15.1	$	14.0
Liabilities incurred	4.6		—
Acquisitions	1.2		—
Accretion expense	1.1		0.8
Changes in estimate	1.8		0.3
Net asset retirement obligation at December 31	$	23.8	$	15.1

We did not have any material assets that were legally restricted for use in settling asset retirement obligations as of December 31, 2014 and 2013.

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Note 6 - Investments in Unconsolidated Affiliates

Jackalope Gas Gathering Services, L.L.C.

Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, owns a 50% ownership interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope). 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.

In July 2013, Crestwood Niobrara acquired its interest in Jackalope from RKI Exploration and Production, LLC (RKI), an affiliate of Crestwood Holdings, for approximately $107.5 million. During the years ended December 31, 2014 and 2013, Crestwood Niobrara contributed $105.2 million and $19.6 million to Jackalope to fund the construction of its gathering and processing system.

Our investment in Jackalope was $232.9 million and $127.2 million at December 31, 2014 and 2013. We have reflected the earnings from our investment in Jackalope in our consolidated statements of operations, which includes our share of Jackalope’s net earnings based on our ownership interest and other adjustments recorded by us as discussed below. Our share of Jackalope’s net earnings was approximately $3.6 million and $1.5 million for the years ended December 31, 2014 and 2013. As of December 31, 2014, our investment balance in Jackalope exceeded our equity in the underlying net assets of Jackalope by approximately $53.7 million. We amortize and generally assess the recoverability of this amount over 20 years, which represents the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake) and RKI . The amortization is reflected as a reduction of our earnings from unconsolidated affiliates, and we recorded amortization expense of approximately $3.1 million and $1.4 million for the years ended December 31, 2014 and 2013.

Jackalope is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the years ended December 31, 2014 and 2013, Jackalope did not make any distributions to its members.

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, we sold our 100% interest in Tres Palacios to Tres Holdings, a newly formed joint venture between Crestwood Midstream's consolidated subsidiary and an affiliate of Brookfield Infrastructure Group (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, we 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. Crestwood Midstream accounts for its investment in Tres Holdings under the equity method of accounting, and the investment is included in our storage and transportation segment.

The sale of our 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 we retained 50.01% of our interest in Tres Palacios through our ownership in Crestwood Midstream, we 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 us. The sale of our 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 our historical basis in Tres Palacios .

Tres Palacios is a 38.4 Bcf multi-cycle, salt dome storage facility. Its 60-mile, dual 24-inch diameter header system (including a 51-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.

Crestwood Midstream’s investment in Tres Holdings was $36.0 million at December 31, 2014. We have reflected the earnings from our investment in Tres Holdings in our consolidated statements of operations, which includes our share of Tres Holdings'

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net earnings based on our ownership interest and other adjustments recorded by us as discussed below. Our share of Tres Holdings' net earnings was approximately $0.1 million for the year ended December 31, 2014. As of December 31, 2014, our equity in the underlying net assets exceeded our investment balance in Tres Holdings by approximately $30.6 million. We amortize and generally assess the recoverability of this amount over the life of the property, plant and equipment of Tres Palacios. The amortization is reflected as an increase in our earnings from unconsolidated affiliates, and we recorded amortization of approximately $0.1 million for the year ended December 31, 2014.

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. Tres Holdings' distribution requirement to its members commences with the quarter ended March 31, 2015.

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. Crestwood Midstream did not receive any reimbursements under this agreement during the year ended December 31, 2014. In addition to our operating agreement, Crestwood Equity 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 Crestwood Equity.

Powder River Basin Industrial Complex, LLC

Crestwood Crude Logistics LLC (Crude Logistics), our consolidated subsidiary, owns a 50% ownership interest in Powder River Basin Industrial Complex, LLC (PRBIC) which we account for under the equity method of accounting. Our PRBIC investment is included in our NGL and crude services segment.

In September 2013, Crude Logistics and Enserco Midstream, LLC formed PRBIC to construct, own and operate and early stage crude oil terminal located in Douglas County, Wyoming. The terminal was placed in manifest service in August 2013. Crude Logistics paid approximately $22.5 million to acquire its interest in PRBIC. During the years ended December 31, 2014 and 2013, Crude Logistics contributed approximately $3.4 million and $1.9 million to PRBIC to fund its construction projects.

Our investment in PRBIC was $26.2 million and $24.2 million at December 31, 2014 and 2013. During the years ended December 31, 2014 and 2013, our share of PRBIC’s loss was approximately $1.4 million and $0.2 million. As of December 31, 2014 and 2013, our investment balance in PRBIC approximated our equity in the underlying net assets of PRBIC.

PRBIC is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage. During the years ended December 31, 2014 and 2013, PRBIC did not make any distributions to its members. In February 2015, we received a cash distribution of approximately $0.3 million from 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 as well as fluctuations in interest rates. We utilize derivative instruments to manage our exposure to fluctuations in commodity prices, which is discussed below. We also periodically utilize derivative instruments to manage our exposure to fluctuations in interest rates, which is discussed in Note 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

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the years ended December 31, 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 $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. There were no risk management activities at December 31, 2012.

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, 2014 and 2013(in millions):



	December 31, 2014		December 31, 2013
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, crude and heating oil (barrels)	6.8	8.4	5.6	6.8
Natural gas (MMBTU’s)	0.2	0.1	—	—

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

All contracts subject to price risk had a maturity of 35 months or less; however, 95% 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, 2014 and 2013, was $5.2 million and $16.6 million for which we had posted $1.8 million and $2.6 million of collateral in the normal course of business. In addition, at December 31, 2014 and 2013, we posted $5.0 million and $3.6 million of NYMEX margin deposits in the normal course of business. At December 31, 2014 and 2013, we also received collateral of $33.6 million and $5.9 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 and physical exchanges.


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

Cash, Accounts Receivable and Accounts Payable

As of December 31, 2014 and 2013, the carrying amounts of cash, accounts receivable and accounts payable represent fair value based on their short-term nature of theses instruments.

Credit Facilities

The fair value of the amounts outstanding under our credit facilities approximates their carrying amounts as of December 31, 2014 and 2013, 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, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
CEQP Senior Notes	$	11.4	$	11.6	$	11.4	$	11.6
Crestwood Midstream 2019 Senior Notes	$	351.0	$	360.5	$	351.2	$	379.3
Crestwood Midstream 2020 Senior Notes	$	504.0	$	481.6	$	504.7	$	513.8
Crestwood Midstream 2022 Senior Notes	$	600.0	$	568.5	$	600.0	$	617.3

Financial Assets and Liabilities

As of December 31, 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, 2014 and 2013 (in millions):



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

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

	December 31, 2013
	Fair Value of Derivatives
	Level 1		Level 2		Level 3		Total		Netting Agreements⁽¹⁾			Total
Assets
Assets from price risk management	$	0.3	$	27.7	$	—	$	28.0	$	(13.5	)	$	14.5
Suburban Propane Partners, L.P. units	6.7		—		—		6.7		—			6.7
Total assets at fair value	$	7.0	$	27.7	$	—	$	34.7	$	(13.5	)	$	21.2

Liabilities
Liabilities from price risk management	$	0.1	$	39.5	$	—	$	39.6	$	(4.7	)	$	34.9
Interest rate swaps	—		4.3		—		4.3		—			4.3
Total liabilities at fair value	$	0.1	$	43.8	$	—	$	43.9	$	(4.7	)	$	39.2

(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.

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Note 9 – Long-Term Debt

Long-term debt consisted of the following at December 31, 2014 and 2013, (in millions):



	December 31, 2014		December 31, 2013
CEQP Credit Facility	$	369.0	$	381.0
CEQP Senior Notes	11.4		11.4
Crestwood Midstream Revolver	555.0		414.9
Crestwood Midstream 2019 Senior Notes	350.0		350.0
Premium on Crestwood Midstream 2019 Senior Notes	1.0		1.2
Crestwood Midstream 2020 Senior Notes	500.0		500.0
Fair value adjustment of Crestwood Midstream 2020 Senior Notes	4.0		4.7
Crestwood Midstream 2022 Senior Notes	600.0		600.0
Other	6.1		2.8
Total debt	2,396.5		2,266.0
Less: current portion	3.7		5.1
Total long-term debt	$	2,392.8	$	2,260.9

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

CEQP Credit Facility

Description of Credit Facility. We utilize a secured credit facility (the CEQP Credit Facility) with an aggregate revolving loan capacity of $495 million due July 2016, to fund working capital requirements, capital expenditures and acquisitions and for general partnership purposes. All borrowings under the CEQP Credit Facility are generally secured by substantially all of our assets and the equity interests in all of our wholly owned subsidiaries, and loans thereunder bear interest, at our option, subject to certain limitations, at a rate equal to the following:


•	the Alternate Base Rate, which is defined as the higher of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) Adjusted LIBOR plus 1%; plus a margin varying from 0.75% to 2.00%; or


•	Adjusted LIBOR, which is defined as the LIBOR plus a margin varying from 1.75% to 3.00%.

We are required to use 50% of the net cash proceeds (that are not applied to purchase replacement assets) from asset dispositions (other than the sale of inventory and motor vehicles in the ordinary course of business, sales of assets among us and our domestic subsidiaries and the sale or disposition of obsolete or worn equipment) to reduce borrowings under the CEQP Credit Facility during any fiscal year in which unapplied net cash proceeds are in excess of $50 million.

In September 2014, we amended the CEQP Credit Facility, among other things, to (i) increase the general partnership commitment from $550 million to $625 million; (ii) decrease the expansion option from $100 million to $25 million; and (iii) modify the maximum total leverage ratio financial covenant levels as discussed further below. The fees paid to our bank syndicate for this amendment were approximately $1.7 million and we amortize such fees over the remaining term of the facility. In conjunction with the sale of our interest in Tres Palacios in December 2014, the CEQP Credit Facility commitment was reduced to $495 million from $625 million, and as a result of the reduction in capacity, we expensed approximately $0.5 million of debt issue costs.

At December 31, 2014 and 2013, the balance outstanding under the CEQP Credit Facility was $369.0 million and $381.0 million and outstanding standby letters of credit were $56.7 million and $52.7 million. We had $69.3 million of available capacity under the revolving credit facility at December 31, 2014 considering our most restrictive debt covenants under the facility. The interest rates on the CEQP Credit Facility are based on prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 2.91% and 5.00% at December 31, 2014 and 2.67% and 4.75% at December 31, 2013.

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The weighted-average interest rate as of December 31, 2014 and 2013 was 3.02% and 2.68%.

Restrictive Covenants. The CEQP Credit Facility contains various covenants and restrictive provisions that limit its 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) enter into certain types of transactions with affiliates; (vi) merge, consolidate or amalgamate with another company; and (vii) transfer or otherwise dispose of assets.

The CEQP Credit Facility contains the following financial covenants:

•

the ratio of our total funded debt (as defined in the credit agreement) to consolidated EBITDA (as defined in the credit agreement) was amended in September 2014 to increase the ratio from 4.75 to 1.0 to no greater than (i) 5.50 to 1.0 for the quarter ended December 31, 2014; (ii) 5.25 to 1.0 for the quarter ended March 31, 2015; (iii) 5.00 to 1.0 for the quarter ended June 30, 2015; and (iv) 4.75 to 1.0 for the quarter ended September 30, 2015 and all subsequent quarters.


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

At December 31, 2014, the total funded debt to consolidated EBITDA was approximately 3.87 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 8.32 to 1.0.

If we fail to perform our obligations under these and other covenants, the CEQP Credit Facility could be terminated and any outstanding borrowings, together with accrued interest, under the credit agreement could be declared immediately due and payable. The credit agreement also has cross default provisions that apply to any other material indebtedness of ours, excluding the debt of Crestwood Midstream.

Events of default under the credit agreement governing the CEQP Credit Facility include, among other things: default in payment of principal when due; default in payment of interest, fees or other amounts within three days of their due date; and violation of specified affirmative and negative covenants.

At December 31, 2014, we were in compliance with the debt covenants in the CEQP Credit Facility.

Interest Rate Swaps. We have entered into six interest rate swaps that mature in 2015 and 2016 to reduce our exposure to variable interest payments due under the CEQP Credit Facility. These swap agreements require us to pay the counterparty an amount based on fixed rates from 0.84% to 2.52% due quarterly on an aggregate notional amount of $225 million. In exchange, the counterparty is required to make quarterly floating interest rate payments on the same date to us based on the three-month LIBOR applied to the same aggregate notional amount of $225 million. During the year ended December 31, 2014, we recorded a gain of approximately $2.6 million associated with these interest rate swaps, which is reflected as a reduction of our interest and debt expense, net on our consolidated statements of operations. These interest rate swaps are not designated as hedges for accounting purposes.

CEQP Senior Notes

At December 31, 2014, we had $11.4 million in outstanding senior notes, the majority of which mature on October 1, 2018 and have a coupon rate of 7%. The outstanding senior notes do not contain any financial covenants.

Crestwood Midstream Revolver

Description of Facility. Crestwood Midstream has a five-year $1.0 billion senior secured revolving credit facility due in October 2018 (the Crestwood Midstream Revolver), which is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The Crestwood Midstream Revolver includes a sub-limit up to $25 million for same-day swing line advances and a sub-limit up to $250 million for letters of credit. Subject to limited exception, the Crestwood Midstream Revolver is secured by substantially all of the equity interests and assets of Crestwood Midstream’s restricted domestic subsidiaries, and is joint and severally guaranteed by substantially all of its restricted domestic subsidiaries, except for Crestwood Niobrara LLC, Crestwood Crude Logistics LLC and CMLP Tres Manager LLC.

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In June 2014, Crestwood Midstream amended its revolver to clarify, among other things, (i) the methodology for calculating the value of its investment in certain joint ventures constituting unrestricted subsidiaries; and (ii) that redemptions, repurchases and retirements of equity interests are permitted to the extent made solely through the issuance of additional equity units. Crestwood Midstream did not pay any fees to its bank syndicate for this amendment.

At December 31, 2014 and 2013, the balance outstanding on the Crestwood Midstream Revolver was $555.0 million and $414.9 million and outstanding standby letters of credit were $15.1 million and $30.7 million. Crestwood Midstream had $429.9 million of available capacity under its revolving credit facility at December 31, 2014 considering its most restrictive debt covenants under the facility. The interest rates on the Crestwood Midstream Revolver are based on the prime rate and LIBOR plus the applicable spreads, resulting in interest rates which were between 2.66% and 4.75% at December 31, 2014 and 2.67% and 4.75% at December 31, 2013. The weighted-average interest rate as of December 31, 2014 and 2013 was 2.86% and 2.75%.

Borrowings under the Crestwood Midstream Revolver (other than swing line loans) bear interest at its option at either:


•	the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) JP Morgan's prime rate; or (iii) Adjusted LIBOR plus 1%; plus a margin varying from 0.75% to 1.75% depending on Crestwood Midstream's most recent total leverage ratio; or


•	Adjusted LIBOR, which is defined as LIBOR plus a margin varying from 1.75% to 2.75% depending on Crestwood Midstream's most recent total leverage ratio.

Swingline loans bear interest at the Alternate Base Rate plus a margin varying from 0.75% to 1.75%. The unused portion of the Crestwood Midstream Revolver is subject to a commitment fee ranging from 0.30% to 0.50% per annum according to Crestwood Midstream's most recent total leverage ratio. Interest on Alternative Base Rate loans is payable quarterly or, if Adjusted LIBOR applies, it may be paid at more frequent intervals.

Restrictive Covenants. The Crestwood Midstream Revolver contains various covenants and restrictive provisions that limit Crestwood Midstream's 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) enter into certain types of transactions with affiliates; (vi) merger, consolidate or amalgamate with another company; and (vii) transfer or otherwise dispose of assets.

The Crestwood Midstream Revolver requires maintenance of a consolidated leverage ratio (as defined in its credit agreement) of not more than 5.00 to 1.0 (and, if applicable, 5.50 to 1.0 during certain periods immediately following a material acquisition by us) and an interest coverage ratio (as defined in its credit agreement) of not less than 2.50 to 1.0. At December 31, 2014, the net debt to consolidated EBITDA was approximately 4.50 to 1.0 and consolidated EBITDA to consolidated interest expense was approximately 3.99 to 1.0.

In December 2014, Crestwood Midstream notified the administrative agent of its election to commence an Acquisition Period (as defined in our credit agreement) effective as of December 3, 2014. Crestwood Midstream made this election following its acquisition of a 50.01% indirect interest in Tres Palacios. Crestwood Midstream's consolidation leverage ratio (as defined in its credit agreement) increases to 5.50 to 1.0 during the 270-day Acquisition Period as a result of this election.

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 Crestwood Midstream Revolver could be declared immediately due and payable. The Crestwood Midstream Revolver also has cross default provisions that apply to any other material indebtedness of Crestwood Midstream.

Crestwood Midstream Senior Notes

2019 Senior Notes. In April 2011, Legacy Crestwood and Crestwood Midstream Finance Corporation (Legacy Crestwood Finance and together with Legacy Crestwood, the Legacy Crestwood Issuers) issued $200 million of 7.75% Senior Notes due 2019 (the Initial 2019 Senior Notes) in a private offering . On November 14, 2012, the Legacy Crestwood Issuers issued and sold an additional $150 million of these notes (the Additional 2019 Senior Notes, and together with the Initial 2019 Senior

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Notes, the 2019 Senior Notes). The 2019 Senior Notes will mature on April 1, 2019, and interest is payable semi-annually in arrears on April 1 and October 1 of each year.

Following the close of the Crestwood Merger on October 7, 2013, (i) Crestwood Midstream and Crestwood Midstream Finance Corp. (Finance Corp) assumed the obligations of Legacy Crestwood and Legacy Crestwood Finance under their 2019 Senior Notes; (ii) certain Legacy Crestwood subsidiary guarantors of the 2019 Senior Notes guaranteed the obligations of Crestwood Midstream and Finance Corp. under the 2020 Senior Notes described below; (iii) Crestwood Midstream’s subsidiary guarantors of the 2020 Senior Notes guaranteed the obligations of the Legacy Crestwood Issuers under the 2019 Senior Notes; and (iv) Legacy Crestwood Finance merged with and into NRGM Finance Corp., with NRGM Finance Corp. continuing as the surviving entity and immediately thereafter changing its name to Crestwood Midstream Finance Corp.

2020 Senior Notes. At December 31, 2014, the balance outstanding on Crestwood Midstream's 6.0% Senior Notes due 2020 (the 2020 Senior Notes) was $500 million. We recorded an adjustment in conjunction with Legacy Crestwood GP's reverse acquisition of us to adjust the debt to fair value. At the December 31, 2014 and 2013, the unamortized balance of the adjustment was $4.0 million and $4.7 million. The adjustment is being amortized over the remaining life of the 2020 Senior Notes. The senior notes will mature on December 15, 2020, and interest is payable semi-annually in arrears on June 15 and December 15 of each year.

2022 Senior Notes. In November 2013, Crestwood Midstream and Finance Corp, 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. Crestwood Midstream used the net proceeds from the offering to fund a portion of the consideration paid in the Arrow Acquisition and related fees and expenses, and to repay borrowings under the Crestwood Midstream Revolver.

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, which were issued in the private offering in November 2013. 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. At December 31, 2014, the balance outstanding on the 2022 Senior Notes was $600 million.

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). 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; and create unrestricted subsidiaries. These restrictions are subject to a number of exceptions and qualifications, and many of these restrictions will terminate when the senior notes are rated investment grade by either Moody's Investors Service, Inc. or Standard & Poor's Rating Services and no default or event of default (each as defined in the respective indentures) under the indentures has occurred and is continuing. In addition, under the indenture governing the Crestwood Midstream 2019 Senior Notes, Crestwood Midstream may not pay any dividend on its common units unless, among other things, at the time of and after giving effect to such dividend payment, no default under the indenture has occurred and is continuing or would occur as a consequence of such dividend payment.

At December 31, 2014, Crestwood Midstream was in compliance with the debt covenants and restrictions in each of its credit agreements and discussed above.

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Notes Payable and Other Obligations

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 2022 and imputed interest ranging from 5.02% to 8.00%. Non-interest bearing obligations consisted of $7.4 million in total payments due under agreements, less unamortized discount based on imputed interest of $1.3 million at December 31, 2014.

Maturities

The aggregate maturities of principal amounts on our outstanding long-term debt and other notes payable as of December 31, 2014 for the next five years and in total thereafter are as follows (in millions):



2015	$	3.7
2016	367.9
2017	0.9
2018	566.1
2019	350.9
Thereafter	1,102.0
Total debt	$	2,391.5

Residual Value Guarantee

In August 2012, we entered into a support agreement with Suburban Propane Partners, L.P. (SPH) pursuant to which we are 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, we 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. We have 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.

Note 10 - Earnings Per Limited Partner Unit

Our net income (loss) attributable to Crestwood Equity Partners is allocated to the subordinated and limited partner unitholders based on their ownership percentage. We calculate basic net income per limited partner unit by utilizing the two class method. Diluted net income per limited partner unit is computed by dividing net income attributable to the limited partners by the weighted-average number of units outstanding and the effect of dilutive units outstanding. 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. There were no units excluded from our dilutive earnings per share as we did not have any anti-dilutive units for the years ended December 31, 2014, 2013 and 2012.

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Note 11 - Income Taxes

The provision for income taxes for the years ended December 31, 2014, 2013, and 2012 consisted of the following (in millions):



	Year Ended December 31,
	2014			2013			2012
Current:
Federal	$	5.0		$	2.5		$	—
State	1.3			1.3			1.2
Total current	6.3			3.8			1.2
Deferred:
Federal	(5.3		)	(2.5		)	—
State	0.1			(0.3		)	—
Total deferred	(5.2		)	(2.8		)	—
Provision for income taxes	$	1.1		$	1.0		$	1.2

The effective rate differs from the statutory rate for the years ended December 31, 2014 and 2013, primarily due to the Partnership not being treated as a corporation for federal income tax purposes as discussed in Note 2.

Deferred income taxes related to our wholly owned subsidiary, IPCH Acquisition Corp., 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. Components of the deferred income taxes at December 31, 2014 and 2013 are as follows (in millions).



	December 31,
	2014			2013
Deferred tax liability:
Basis difference in stock of acquired company	$	(12.0	)	$	(17.2	)
Total deferred tax liability	$	(12.0	)	$	(17.2	)

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, 2014, 2013 and 2012 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.

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Note 12 – Partners’ Capital

Unit Issuances

We periodically sell common units in public offerings to generate funds to reduce our indebtedness under our credit facilities 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
Legacy Crestwood	January 13, 2012	3,500,000		$	30.73	$	29.50	$	103.1
Legacy Crestwood	July 25, 2012	4,600,000	⁽²⁾	26.00		24.97		114.4
Legacy Crestwood	March 22, 2013	5,175,000	⁽³⁾	23.90		23.00		118.5
Inergy Midstream	September 13, 2013	11,773,191	⁽⁴⁾	22.50		21.69		255.2
Crestwood Midstream	October 23, 2013	16,100,000	⁽⁵⁾	N/A		21.19		340.3


(1)	Price is net of underwriting discounts.


(2)	Includes 600,000 units that were issued in August 2012.


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


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


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

During 2011 and 2013, Legacy Crestwood issued Class C and Class D units, respectively, representing limited partner units. Legacy Crestwood had the option to pay distributions to its Class C and 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 Legacy Inergy 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. For the year ended December 31, 2012, Legacy Crestwood issued 633,084 additional Class C units in lieu of paying quarterly cash distributions.

Contributions

During 2012, Legacy Crestwood's general partner made additional capital contributions of approximately $5.9 million in exchange for the issuance of an additional 215,722 general partner units.

Distributions

We make quarterly distributions to our partners within approximately 45 days after the end of each quarter in an aggregate amount equal to our 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 our business;


•	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 after the end of the quarter. Working capital borrowings are generally borrowings that are made under our working capital facility and in all cases are used solely for working capital purposes or to pay distributions to partners. The amount of cash we have available for distribution depends primarily upon our cash flow (which consists of the cash distributions we receive in connection with our ownership of 100% of Crestwood Midstream's IDRs and 4% of Crestwood Midstream's common units) and the cash flow generated by certain of our consolidated subsidiaries not owned by Crestwood Midstream.

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Distributions to Partners

During the years ended December 31, 2013 and 2012, Legacy Crestwood GP paid cash distributions to its member of $9.3 million and $13.8 million. In addition, during the year ended December 31, 2013, we paid cash distributions of approximately $11.8 million related to units that vested as a result of the Crestwood Merger discussed below.

A summary of our limited partner quarterly cash distributions for the years ended December 31, 2014 and 2013 (subsequent to the June 19, 2013 reverse acquisition) is presented below:



Record Date	Payment Date	Per Unit Rate		Cash Distributions (in millions)
2014
February 7, 2014	February 14, 2014	$	0.1375	$	25.6
May 8, 2014	May 15, 2014	$	0.1375	25.7
August 7, 2014	August 14, 2014	$	0.1375	25.6
November 7, 2014	November 14, 2014	$	0.1375	25.6
				$	102.5
2013
August 7, 2013	August 14, 2013	$	0.1300	$	22.3
November 7, 2013	November 14, 2013	$	0.1350	25.0
				$	47.3

On February 13, 2015, we paid a distribution of $0.1375 per limited partner unit to unitholders of record on February 6, 2015 with respect to the fourth quarter of 2014.

Non-Controlling Partners Equity

Crestwood Midstream Class A Preferred Units

On June 17, 2014, Crestwood Midstream entered into definitive agreements with a group of investors, including Magnetar Financial, affiliates of GSO Capital Partners LP and GE Energy Financial Services (the Class A Purchasers). Under these agreements, Crestwood Midstream has agreed to sell to the Class A Purchasers and the Class A Purchasers have agreed to purchase from Crestwood Midstream up to $500 million of Preferred Units at a fixed price of $25.10 per unit on or before September 30, 2015. During the year ended December 31, 2014, the Class A Purchasers purchased 17,529,879 Preferred Units for a cash purchase price of $25.10 per unit resulting in gross proceeds of approximately $440.0 million (net proceeds of approximately $430.5 million after deducting transaction fees and offering expenses). The Preferred Units are reflected as non-controlling interests in our consolidated financial statements.

Subject to certain conditions, holders of the Preferred Units will have the right to convert Preferred Units into (i) common units on a one-for-one basis after June 17, 2017, or (ii) a number of common units determined pursuant to a conversion ratio set forth in the Crestwood Midstream partnership agreement upon the occurrence of certain events, such as a change in control. Also, subject to certain conditions after the full $500 million purchase commitment has been satisfied, Crestwood Midstream may convert the Preferred Units into common units at a conversion ratio set forth in the partnership agreement, which is based in part on the aggregate principal amount of the Preferred Units outstanding and the weighted average trading price of its common units.

The Preferred Units have voting rights that are identical to the voting rights of the Crestwood Midstream common units and will vote with the common units as a single class, with each Preferred Unit 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 unitholders are entitled to vote that adversely affects the rights, powers, privileges or preferences of the Preferred Units in relation to Crestwood Midstream's other securities outstanding.

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On July 9, 2014, Crestwood Midstream filed a shelf registration statement with the SEC under which holders of the Preferred Units may sell the common units into which the Preferred Units are convertible. The registration statement became effective on July 18, 2014. Crestwood Midstream registered 26,299,076 common units under the registration statement.

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 our consolidated financial statements.

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.

Net Income (Loss) Attributable to Non-Controlling Partners

The components of net income (loss) attributable to non-controlling partners on our consolidated statements of operations for the years ended December 31, 2014, 2013 and 2012 are as follows (in millions):



	Year Ended December 31,
	2014			2013			2012
Crestwood Midstream limited partner interests	$	(100.8	)	$	(62.2	)	$	9.5
Crestwood Niobrara preferred interests	16.8			4.9			—
Crestwood Midstream Class A preferred units	17.2			—			—
Net income (loss) attributable to non-controlling partners	$	(66.8	)	$	(57.3	)	$	9.5

Distributions to Non-Controlling Partners

Crestwood Midstream Limited Partners. 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 $296.5 million and $179.6 million during the year ended December 31, 2014 and 2013. Legacy Crestwood paid cash distributions to its common unitholders of $89.7 million for the year ended December 31, 2012.

The Crestwood Midstream partnership agreement requires them to distribute, within 45 days after the end of each quarter, all available cash (as defined in its partnership agreement) to unitholders of record on the applicable record date. We are not entitled to distributions on our non-economic general partner interest in Crestwood Midstream.

Crestwood Midstream Class A Preferred Unitholders. Crestwood Midstream's partnership agreement requires it to make quarterly distributions to its Class A Preferred Unit holders. The holders of the Class A Preferred Units (the Preferred Units) are entitled to receive fixed quarterly distributions of $0.5804 per unit. For the 12 quarters following the quarter ended June 30, 2014 (the Initial Distribution Period), distributions on the Preferred Units can be made in additional Preferred Units, cash, or a combination thereof, at Crestwood Midstream's election. If Crestwood Midstream elects to pay the quarterly distribution through the issuance of additional Preferred Units, the number of units to be distributed will be calculated as the fixed quarterly distribution of $0.5804 per unit divided by the cash purchase price of $25.10 per unit. Crestwood Midstream accrues the fair value of such distribution at the end of the quarterly period and adjusts the fair value of the distribution on the date the additional Preferred Units are distributed. Distributions on the Preferred Units following the Initial Distribution Period will be made in cash unless, subject to certain exceptions, (i) there is no distribution being paid on Crestwood Midstream's common units and (ii) its available cash (as defined in its partnership agreement) is insufficient to make a cash distribution to its Preferred Unit holders. If Crestwood Midstream fails to pay the full amount payable to its Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.7059 per unit, and (y) Crestwood Midstream will not be permitted to declare or make any distributions to its common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if Crestwood Midstream fails to pay in full any Class A Preferred Distribution (as defined in its partnership agreement), the

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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. For additional information on the Preferred Units, see the Crestwood Midstream Class A Preferred Units section below.

During the year ended December 31, 2014, Crestwood Midstream issued 387,991 Preferred Units to its preferred unitholders in lieu of paying a cash distribution. On February 13, 2015, Crestwood Midstream issued 414,325 Preferred Units to its preferred unitholders for the quarter ended December 31, 2014 in lieu of paying a cash distribution.

Crestwood Niobrara Preferred Unitholders. Crestwood Midstream serves as the managing member of Crestwood Niobrara and, subject to certain restrictions, it has the ability to redeem GE’s preferred interest in either cash or Crestwood Midstream common units at an amount equal to the face amount of the preferred units plus an applicable return. 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. Beginning with the first quarter of 2015, Crestwood Niobrara no longer has the option to pay distributions to GE by issuing additional preferred units in lieu of paying a cash distribution.

Other Partners' Capital Transactions

Equity Distribution Agreement

On July 10, 2014, Crestwood Midstream entered into an equity distribution agreement with Morgan Stanley & Co. LLC, Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets Inc., J.P. Morgan Securities LLC, RBC Capital Markets, LLC, SunTrust Robinson Humphrey, Inc. and Wells Fargo Securities, LLC (each, a Manager), under which it may offer and sell from time to time through one or more of the Managers, its common units having an aggregate offering price of up to $300.0 million. Common units sold pursuant to this at-the-market (ATM) equity distribution program will be issued under a registration statement that became effective on May 27, 2014. Crestwood Midstream will pay the Managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under its ATM program. Crestwood Midstream has not issued any common units under this equity distribution program as of December 31, 2014 and through the date of this filing.

Crestwood Merger

In conjunction with Crestwood Holdings’ acquisition of our general partner, we issued 4,387,889 subordinated units, which are considered limited partnership interests, and have the same rights and obligations as our 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 $0.13 for that quarter. Our subordinated units convert to common units after (i) our common units have received a cumulative distribution in excess of $0.52 during a consecutive four quarter period; and (ii) our Adjusted Operating Surplus (as defined in the agreement) exceeds the distribution on a fully dilutive basis.

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 our consolidated statements of partners’ capital as contribution from Crestwood Holding LLC for the year ended December 31, 2013. We reflected the distribution of $34.9 million as distributions to non-controlling partners on our 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. We reflected the cash paid of approximately $11.8 million related to these vested units as distributions to partners on our consolidated statements 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 our 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 our consolidated statements of partners' capital.

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Acquisitions and Other

CMM. In February 2012, Legacy Crestwood and Crestwood Holdings formed the CMM joint venture. Legacy Crestwood contributed approximately $131.3 million for a 35% membership interest and Crestwood Holdings contributed approximately $243.8 million for a 65% membership interest. On January 8, 2013, Legacy Crestwood 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, the issuance of 6,190,469 Class D units and the issuance of 133,060 general partner units to the Legacy Crestwood general partner. As a result of the acquisition of the additional membership interest, Legacy Crestwood had the ability to control CMM’s operating and financial decisions and policies. The transaction was accounted for as a reorganization of entities under common control and accordingly, the historical results of Legacy Crestwood were retrospectively adjusted to reflect the change in reporting entity as of and for the year ended December 31, 2012. We reflected the $243.8 million contribution by Crestwood Holdings as contributions from non-controlling partners in our consolidated statements of cash flows and statements of partners’ capital for the year ended December 31, 2012. The issuances of the Class D and general partner units in conjunction with the acquisition of the additional interest in CMM were reflected as distributions for additional interest in Crestwood Marcellus Midstream LLC in our consolidated statements of cash flows and statements of 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.

Other. In connection with Crestwood Holdings’ acquisition of Legacy Crestwood, Legacy Crestwood GP agreed to pay Quicksilver conditional consideration in the form of potential additional cash payments of up to $72 million depending on the achievement of certain defined average volume targets above an agreed threshold for 2012.

In February 2012, Crestwood Holdings paid Quicksilver approximately $41.1 million on behalf of Legacy Crestwood GP associated with the average volumes achieved for 2011. We reflected this payment as a non-cash contribution from non-controlling partners on our consolidated statements of partners’ capital for the year ended December 31, 2012. As of December 31, 2012, Quicksilver did not achieve their 2012 average volume target. As such, we determined that the estimated fair value of our remaining conditional consideration to Quicksilver was zero, and we recognized a gain of approximately $6.8 million for the year ended December 31, 2012 related to the elimination of the contingent liability.

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

Note 13 - Equity Plans

Long-term incentive awards are granted under the Crestwood Equity Partners LP Long Term Incentive Plan (Crestwood LTIP) and the Crestwood Midstream Partners LP Long Term Incentive Plan (Crestwood Midstream LTIP) in order to align the 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 solely of grants of restricted common units (which represent limited partner interests of CEQP and Crestwood Midstream) which vest based upon continued service.

During 2014, we have issued restricted unit awards, which were approved by either CEQP's and Crestwood Midstream's Board compensation committee or pursuant to the authority granted by the Chief Executive Officer, to certain key employees. These awards vest upon continued service with the Company.

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Crestwood Equity

Crestwood LTIP. The following table summarizes information regarding restricted unit activity during the year ended December 31, 2014:



	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2014	493,543		$	13.96
Vested - restricted units	(449,936	)	$	13.97
Granted - restricted units	1,377,461		$	13.23
Forfeited	(105,188	)	$	13.73
Unvested - December 31, 2014	1,315,880		$	13.21

As of December 31, 2014 and 2013, we had total unamortized compensation expense of approximately $8.1 million and $1.6 million related to restricted 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 $10.1 million (including $6.9 million that was allocated to Crestwood Midstream) under the Crestwood LTIP during the year ended December 31, 2014, and $10.9 million (including $4.4 million that was allocated to Crestwood Midstream) under the Legacy Inergy long-term incentive plan during the year ended December 31, 2013, which is included in general and administrative expenses on our consolidated statements of operations. We granted restricted units with a grant date fair value of approximately $18.2 million during the year ended December 31, 2014. In January 2015, we filed a registration statement on Form S-8 with the SEC to register an additional 10,000,000 units under the plan for a total of 15,000,000 units registered with the SEC. As of February 13, 2015, we had 12,613,231 units available for issuance under the Crestwood LTIP.

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, 2014 and 2013, we withheld 159,435 and 362,565 common units to satisfy employee tax withholding obligations.

Unit Purchase Plan. Prior to September 2014, Crestwood Equity's general partner sponsored a unit purchase plan for its employees and the employees of its affiliates. The unit purchase plan permitted participants to purchase common units in market transactions from Crestwood Equity, the general partners or any other person. All purchases were made in market transactions, although the plan allowed Crestwood Equity to issue additional units. Under the plan, the general partner had the option to match each participant's cash base pay or salary deferrals by an amount up to 10% of such deferrals and have such amount applied toward the purchase of additional units. The general partner also agreed to pay the brokerage commissions, transfer taxes and other transaction fees associated with a participant's purchase of common units. This plan was discontinued in September 2014. There were 15,369 units purchased through the unit purchase plan by Crestwood Equity and its employees during the year ended December 31, 2014.

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Crestwood Midstream

Crestwood Midstream LTIP. The following table summarizes information regarding restricted unit activity during the year ended December 31, 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

As of December 31, 2014 and 2013, we had total unamortized compensation expense of approximately $9.5 million and $1.8 million related to restricted units issued under the Crestwood Midstream LTIP, which we expect will be amortized during the next three years (or sooner in certain cases, which generally represents the original vesting period of these instruments), except for grants to non-employee directors of the general partner of CEQP, which vest over one year. Crestwood Midstream recognized compensation expense of approximately $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, 2014 and 2013, which is included in general and administrative expenses on our consolidated statements of operations. We granted restricted units with a grant date fair value of approximately $20.3 million during the year ended December 31, 2014. As of December 31, 2014, we had 17,629,657 units available for issuance under the Crestwood Midstream LTIP.

Under the Crestwood Midstream LTIP, participants who have been granted restricted units may elect to have common units withheld to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-vested common units. Any such common units withheld are returned to the Crestwood Midstream LTIP on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When such common units are withheld, Crestwood Midstream is required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. During the year ended December 31, 2014, Crestwood Midstream withheld 71,484 common units to satisfy employee tax withholding obligations.

Employee Unit Purchase Plan. Beginning in September 2014, the board of directors of Crestwood Midstream's general partner made available an employee unit purchase plan under which employees of the general partner may purchase Crestwood Midstream's common units through payroll deductions up to a maximum of 10% of the employees' eligible compensation. Under the plan, CMLP may purchase its common units on the open market for the benefit of participating employees based on their payroll deductions. In addition, CMLP may contribute an additional 10% of participating employees' payroll deductions to purchase additional CMLP common units for participating employees. Unless increased by the board of directors of Crestwood Midstream's general partner, the maximum number of common units that may be purchased under the plan is 200,000. In January 2015, there were 2,011 common units purchased through the unit purchase plan for the year ended December 31, 2014.

Legacy Crestwood

Long-Term Incentive Plan. Prior to the Crestwood Merger, awards of phantom and restricted units were granted under the Legacy Crestwood Fourth Amended and Restated 2007 Equity Plan (the 2007 Equity Plan). The 2007 Equity Plan was terminated in conjunction with the Crestwood Merger. All of the unvested phantom and restricted units became vested upon consummation of the Crestwood Merger and all unamortized compensation expense related to those units was recognized on that date. The following table summarizes information regarding phantom and restricted unit activity:

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	Payable In Cash				Payable In Units
	Units		Weighted- Average Grant Date Fair Value		Units		Weighted- Average Grant Date Fair Value
Unvested - December 31, 2012	8,312		$	26.45	221,992		$	28.35
Vested - phantom units	(7,958	)	$	26.48	(329,825	)	$	26.69
Vested - restricted units	—		$	—	(74,760	)	$	25.60
Granted - phantom units	—		$	—	161,807		$	24.33
Granted - restricted units	—		$	—	27,900		$	24.86
Canceled - phantom units	(354	)	$	25.81	(7,114	)	$	27.96
Unvested - December 31, 2013	—		$	—	—		$	—

As discussed above, the vesting period of our phantom and restricted units were accelerated upon consummation of the Crestwood Merger. Crestwood Midstream recognized compensation expense under the 2007 Equity Plan of approximately $6.5 million and $1.9 million for the years ended December 31, 2013 and 2012, included in operating expenses on our consolidated statements of income. Crestwood Midstream granted phantom and restricted units under the 2007 Equity Plan with a grant date fair value of approximately $4.6 million and $4.7 million for the years ended December 31, 2013 and 2012. During the year ended December 31, 2013, Crestwood Midstream withheld 21,014 common units to satisfy employee tax withholding obligations.

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 75% of their salary, up to statutory limits, which was $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 $3.8 million and $0.5 million in 2014 and 2013. Neither Legacy Crestwood GP nor Legacy Crestwood had any employees. Employees of Crestwood Holdings provided services to Legacy Crestwood GP and Legacy Crestwood pursuant to an omnibus agreement.

Note 15 – Commitments and Contingencies

Legal Proceedings

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

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

In March 2014, the plaintiffs filed their fourth amended motion to name Arrow and numerous other energy companies as additional defendants in the class action lawsuit. The plaintiffs have named at least 53 defendants purportedly involved in the events leading up to the derailment, including the producers and sellers of the crude being transported, the midstream companies that transported the crude from the well head to the rail system, the manufacturers of the rail cars used to transport

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the crude, the railroad companies involved, the insurers of these companies, and the Canadian Attorney General. The plaintiffs allege, among other things, that Arrow (i) was a producer of the crude oil being transported on the derailed train, (ii) was negligent in failing to properly classify the crude delivered to the trucks that hauled the crude to the rail loading terminal, and (iii) owed a duty to the petitioners to ensure the safe transportation of the crude being transported. The motion to authorize the class action and motions in opposition were heard by the Court in June 2014. We anticipate a ruling from the Judge on the Petitioners' motion to authorize the class action in the first quarter of 2015.

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

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

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

General. We are periodically involved in litigation proceedings. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, then we accrue the estimated amount. The results of litigation proceedings cannot be predicted with certainty. We could incur judgments, enter into settlements or revise our expectations regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations or cash flows in the period in which the amounts are paid and/or accrued. As of December 31, 2014 and 2013, we had $1.0 million and less than $0.1 million accrued for our outstanding legal matters. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures for which we can estimate will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.

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

Regulatory Compliance

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

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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. During the year ended December 31, 2014, we recognized $4.6 million of operations and maintenance expense related to these releases, of which $1.1 million was included in other current liabilities on our balance sheet as of December 31, 2014. We will continue our remediation efforts to ensure the impacted lands are restored to their prior state, and we may potentially be subject to fines and penalties. We believe these releases are insurable events under our policies, and we have notified our insurance companies of these events. As of December 31, 2014, we had no amounts accrued for fines and penalties. We have not recorded an insurance receivable as of December 31, 2014.

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, 2014, our accrual of approximately $1.1 million was primarily related to the Arrow water releases described above, which is based on our undiscounted estimate of amounts we will spend on compliance with environmental and other regulations. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures (including the Arrow water releases described above) could range from approximately $1.1 million to $1.5 million. Our accrual and potential exposure related to our environmental matters was immaterial at December 31, 2013.

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, 2014 and 2013, our self-insurance reserves were $14.6 million and $15.8 million. We estimate that $9.7 million of this balance will be paid subsequent to December 31, 2015. As such, $9.7 million has been classified in other long-term liabilities on our consolidated balance sheets.

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 2015 until 2032.

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Future minimum lease payments under 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,
2015	$	16.9
2016	15.5
2017	12.9
2018	11.0
2019	9.9
Thereafter	17.5
Total minimum lease payments	$	83.7

Rent expense for operating leases for the years ended December 31, 2014, 2013 and 2012, totaled $41.8 million, $16.4 million and $7.4 million.

Capital Leases. We have a treating facility and certain auto leases which are accounted for as capital leases. The terms of the agreements vary from 2015 until 2018. We recorded amortization of expense of $3.3 million, $3.6 million and $3.1 million for the years ended December 31, 2014, 2013 and 2012.

Future minimum lease payments related to our capital leases at December 31, 2014 are as follows (in millions):



Year Ending December 31,
2015	$	2.2
2016	1.6
2017	1.2
2018	0.4
Total payments	5.4
Imputed interest	(0.1		)
Present value of future payments	$	5.3

Our capital lease liabilities were $5.3 million and $4.7 million at December 31, 2014 and 2013, and are included in accrued expenses and other liabilities and other long-term liabilities on our consolidated balance sheets.

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, 2014, the total of these firm purchase commitments was $242.9 million, substantially all of which will occur over the course of the next twelve months. We also enter into non-binding agreements with suppliers to purchase quantities of NGLs, distillates and natural gas at variable prices at future dates at the then prevailing market prices.

We have entered into certain purchase commitments in connection with the identified growth projects primarily related to the Arrow development project in the Bakken Shale, certain upgrades to the US Salt facility and growth and maintenance obligations related to our G&P segment. At December 31, 2014, the total of our storage and transportation and NGL and crude services operations' firm purchase commitments was approximately $22.7 million and our gathering and processing segment's purchase commitments totaled approximately $9.8 million. The majority of the purchases associated with these commitments are expected to occur over the next twelve months.

Note 16 – Related Party Transactions

Our general partner is indirectly owned by Crestwood Holdings. The affiliates of Crestwood Holdings and its owners are considered our related parties, including Sabine Oil and Gas LLC and Mountaineer Keystone LLC.

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We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including gas gathering and processing services under long-term contracts, product purchases and various operating agreements. Prior to the Crestwood Merger, we were managed and operated by the directors and officers of Legacy Crestwood’s general partner. We had an omnibus agreement with Crestwood Holdings and the Legacy Crestwood general partner under which Legacy Crestwood reimbursed Crestwood Holdings for the provision of various general and administrative services for its benefit and for direct expenses incurred by Crestwood Holdings on its behalf. Crestwood Holdings billed Legacy Crestwood directly for certain general and administrative costs and allocated a portion of its general and administrative costs to Legacy Crestwood.

The following table shows revenues, costs of goods sold and general and administrative expenses from our affiliates for the years December 31, 2014, 2013 and 2012 (in millions):



	Year Ended December 31,
	2014 (1)		2013		2012
Gathering and processing revenues	$	3.0	$	74.9	$	113.7
Gathering and processing costs of product/services sold⁽²⁾	$	42.2	$	32.5	$	15.2
General and administrative expenses	$	0.5	$	25.3	$	19.5

(1) Concurrent with the Crestwood Merger, Quicksilver Resources Inc. (Quicksilver) is no longer a related party, and as a result our transactions with

Quicksilver subsequent to June 19, 2013, are now considered non-affiliated transactions.

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

The following table shows accounts receivable and accounts payable from our affiliates as of December 31, 2014 and 2013 (in millions):



	December 31, 2014		December 31, 2013
Accounts receivable	$	0.6	$	—
Accounts payable	$	5.6	$	3.6

Note 17 – Segments

Financial Information

We have three operating and reportable segments: (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) NGL and crude services operations. Our gathering and processing operations engage in the gathering, processing, treating, compression, transportation and sales of natural gas and the delivery of NGLs. Our storage and transportation operations provide regulated natural gas storage and transportation services to producers, utilities and other customers. Our NGL and crude services operations provide NGL processing and fractionation, NGLs and crude oil gathering, storage, marketing and transportation, supply and logistics services to producers, refiners, marketers, and other customers that effectively provide flow assurances to our customers, as well as the production and sale of salt products. Our corporate operations include all general and administrative expenses that are not allocated to our reportable segments. We assess the performance of our operating segments based on EBITDA, which represents operating income plus depreciation, amortization and accretion expense.

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



	Year Ended December 31,
	2014			2013			2012
Net income (loss)	$	(10.4	)	$	(50.6	)	$	24.4
Add:
Interest and debt expense, net	127.1			77.9			35.8
Provision for income taxes	1.1			1.0			1.2
Depreciation, amortization and accretion	285.3			167.9			73.2
EBITDA	$	403.1		$	196.2		$	134.6

The following tables summarize the reportable segment data for the years ended December 31, 2014, 2013 and 2012 (in millions).



	Year Ended December 31, 2014
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Intersegment			Corporate			Total
Revenues	$	332.5		$	192.9	$	3,406.9		$	(1.0	)	$	—		$	3,931.3
Costs of product/services sold	71.3			24.8		3,070.2			(1.0		)	—			3,165.3
Operations and maintenance expense	62.9			23.3		117.1			—			—			203.3
General and administrative expense	—			—		—			—			100.2			100.2
Gain (loss) on long-lived assets, net	(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			0.2		(1.4		)	—			—			(0.7		)
Other income, net	—			—		—			—			0.6			0.6
EBITDA	$	139.0		$	178.8	$	184.9		$	—		$	(99.6	)	$	403.1
Goodwill	$	338.3		$	726.3	$	1,427.2		$	—		$	—		$	2,491.8
Total assets	$	2,645.0		$	1,981.2	$	3,631.3		$	—		$	203.9		$	8,461.4
Purchases of property, plant and equipment	$	245.7		$	9.7	$	160.4		$	—		$	8.2		$	424.0

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	Year Ended December 31, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Intersegment		Corporate			Total
Revenues	$	291.2		$	104.2	$	1,031.3		$	—	$	—		$	1,426.7
Costs of product/services sold	56.6			15.7		930.0			—		—			1,002.3
Operations and maintenance expense	54.9			12.1		37.6			—		—			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		)
Loss 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	$	149.7		$	76.4	$	63.4		$	—	$	(93.3	)	$	196.2
Goodwill	$	356.8		$	936.5	$	1,258.9		$	—	$	—		$	2,552.2
Total assets	$	2,507.3		$	2,369.1	$	3,465.8		$	—	$	181.0		$	8,523.2
Purchases of property, plant and equipment	$	271.2		$	18.0	$	56.8		$	—	$	1.0		$	347.0



	Year Ended December 31, 2012
	Gathering and Processing		Storage and Transportation		NGL and Crude Services		Intersegment		Corporate			Total
Revenues	$	239.5	$	—	$	—	$	—	$	—		$	239.5
Costs of product/services sold	39.0		—		—		—		—			39.0
Operations and maintenance expense	43.1		—		—		—		—			43.1
General and administrative expense	—		—		—		—		29.6			29.6
Gain on contingent consideration	6.8		—		—		—		—			6.8
EBITDA	$	164.2	$	—	$	—	$	—	$	(29.6	)	$	134.6
Goodwill	$	352.2	$	—	$	—	$	—	$	—		$	352.2
Total assets	$	2,278.9	$	—	$	—	$	—	$	22.7		$	2,301.6
Purchases of property, plant and equipment	$	51.5	$	—	$	—	$	—	$	1.1		$	52.6

Major Customers

For the year ended December 31, 2014, Tesoro had revenues of $465.2 million which exceeded 10% of our total consolidated revenues. Revenues from Tesoro are reflected in our NGL and crude services segment. No customer accounted for 10% or more of our total consolidated revenues for the year ended December 31, 2013. For the year ended December 31, 2012, Quicksilver and Antero had revenues of approximately $112.6 million and $25.5 million, which exceeded 10% of our total consolidated revenues. Revenues from Quicksilver and Antero are reflected in our gathering and processing segment.

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Note 18 – Condensed Consolidating Financial Information

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

As summarized in the table below, the condensed consolidating statement of cash flows for the year ended December 31, 2013 has been corrected for certain errors in presentation. There was no impact to our consolidated statement of cash flows for the year ended December 31, 2013.



	Parent						Guarantor Subsidiaries						Eliminations
	As Adjusted			As Previously Reported			As Adjusted			As Previously Reported			As Adjusted			As Previously Reported
	(in millions)
Cash flows from operating activities:	$	(12.3	)	$	—		$	14.1		$	1.8		$	—		$	—

Cash flows from investing activities:
Capital contributions from consolidated affiliates, net and other	20.7			76.0			0.1			17.0			(20.7		)	(92.9		)
Net cash provided by (used in) investing activities	20.7			76.0			(6.4		)	10.5			(20.7		)	(92.9		)

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	394.1			—			—			394.1			—			—
Principal payments on long-term debt	(333.3		)	—			—			(333.3		)	—			—
Distributions paid to partners	(68.4		)	(76.0		)	—			(59.1		)	26.2			92.9
Change in intercompany balances	0.4			—			(0.4		)	—			—			—
Other	(1.1		)	0.1			(4.9		)	(11.6		)	(5.5		)	—
Net cash provided by (used in) financing activities	(8.3		)	(75.9		)	(5.3		)	(9.9		)	20.7			92.9

The tables below present condensed consolidating financial statements for us (parent) on a stand-alone, unconsolidated basis, and our combined guarantor and combined non-guarantor subsidiaries as of and for the years ended December 31, 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. As discussed in Note 2, the accounting for the reverse acquisition of Legacy Inergy results in Legacy Inergy's historical operations being acquired on June 19, 2013. The CEQP Senior Notes are thus not included in the financial statements prior to June 19, 2013. Since Legacy Crestwood GP (the accounting predecessor) does not guarantee any debt, the condensed consolidated financial statements do not include financial information for the year ended December 31, 2012.

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Condensed Consolidating Balance Sheet
December 31, 2014
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	3.7	$	0.5	$	4.6	$	—		$	8.8

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

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

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

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

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

Long-term liabilities:
Long-term debt, less current portion	380.0		—		2,012.8		—			2,392.8
Other long-term liabilities	12.9		15.1		31.2		—			59.2
Total long-term liabilities	392.9		15.1		2,044.0		—			2,452.0

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

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Condensed Consolidating Balance Sheet
December 31, 2013
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	0.1	$	2.4	$	2.7	$	—		$	5.2

Accounts receivable	—		207.5		205.1		—			412.6
Accounts receivable - intercompany	—		—		—		—			—
Total accounts receivable	—		207.5		205.1		—			412.6

Inventories	—		66.6		7.0		—			73.6
Other current assets	—		25.8		10.2		(5.4		)	30.6
Total current assets	0.1		302.3		225.0		(5.4		)	522.0

Property, plant and equipment, net	—		400.9		3,504.4		—			3,905.3
Goodwill and intangible assets, net	—		742.4		3,170.2		—			3,912.6
Investment in consolidated affiliates	5,927.1		—		—		(5,927.1		)	—
Investment in unconsolidated affiliates	—		—		151.4		—			151.4
Other assets	—		10.2		21.7		—			31.9
Total assets	$	5,927.2	$	1,455.8	$	7,072.7	$	(5,932.5	)	$	8,523.2

Liabilities and partners' capital
Current liabilities:
Accounts payable	$	—	$	218.3	$	157.1	$	—		$	375.4
Accounts payable - related party	—		—		3.6		—			3.6
Accounts payable - intercompany	—		—		—		—			—
Total accounts payable	—		218.3		160.7		—			379.0

Other current liabilities	4.2		61.6		156.7		(5.4		)	217.1
Total current liabilities	4.2		279.9		317.4		(5.4		)	596.1

Long-term liabilities:
Long-term debt, less current portion	393.0		—		1,867.9		—			2,260.9
Other long-term liabilities	21.4		109.9		26.3		—			157.6
Total long-term liabilities	414.4		109.9		1,894.2		—			2,418.5

Partners' capital	831.6		1,066.0		184.1		(1,250.1		)	831.6
Interest of non-controlling partners in subsidiaries	4,677.0		—		4,677.0		(4,677.0		)	4,677.0
Total partners' capital	5,508.6		1,066.0		4,861.1		(5,927.1		)	5,508.6
Total liabilities and partners' capital	$	5,927.2	$	1,455.8	$	7,072.7	$	(5,932.5	)	$	8,523.2

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Condensed Consolidating Statements of Operations
Year Ended December 31, 2014
(in millions)
	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	—	$	328.5		$	—		$	328.5
Storage and transportation	—			13.8		179.1			—			192.9
NGL and crude services	—			1,366.6		2,040.3			—			3,406.9
Related party	—			—		17.6			(14.6		)	3.0
	—			1,380.4		2,565.5			(14.6		)	3,931.3
Costs of product/services sold:
Gathering and processing	—			—		29.1			—			29.1
Storage and transportation	—			10.5		14.3			—			24.8
NGL and crude services	—			1,218.3		1,851.9			(1.0		)	3,069.2
Related party	—			13.6		42.2			(13.6		)	42.2
	—			1,242.4		1,937.5			(14.6		)	3,165.3
Expenses:
Operations and maintenance	—			64.3		139.0			—			203.3
General and administrative	8.5			6.3		85.4			—			100.2
Depreciation, amortization and accretion	—			44.7		240.6			—			285.3
	8.5			115.3		465.0			—			588.8
Other operating income (expense):
Gain (loss) on long-lived assets, net	—			31.7		(33.6		)	—			(1.9		)
Goodwill impairment	—			—		(48.8		)	—			(48.8		)
Loss on contingent consideration	—			—		(8.6		)	—			(8.6		)
Operating income (loss)	(8.5		)	54.4		72.0			—			117.9
Earnings (loss) from unconsolidated affiliates, net	—			—		(0.7		)	—			(0.7		)
Interest and debt expense, net	(15.7		)	—		(111.4		)	—			(127.1		)
Other income, net	—			0.6		—			—			0.6
Equity in net income (loss) of subsidiary	14.2			—		—			(14.2		)	—
Income (loss) before income taxes	(10.0		)	55.0		(40.1		)	(14.2		)	(9.3		)
Provision for income taxes	0.4			—		0.7			—			1.1
Net income (loss)	(10.4		)	55.0		(40.8		)	(14.2		)	(10.4		)
Net (income) loss attributable to non-controlling partners in subsidiaries	—			—		66.8			—			66.8
Net income (loss) attributable to partners	$	(10.4	)	$	55.0	$	26.0		$	(14.2	)	$	56.4

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Condensed Consolidating Statements of Operations
Year Ended December 31, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues:
Gathering and processing	$	—		$	—		$	216.3		$	—		$	216.3
Storage and transportation	—			14.1			90.1			—			104.2
NGL and crude services	—			761.2			270.1			—			1,031.3
Related party	—			—			82.1			(7.2		)	74.9
	—			775.3			658.6			(7.2		)	1,426.7
Costs of product/services sold:
Gathering and processing	—			—			24.1			—			24.1
Storage and transportation	—			7.0			8.7			—			15.7
NGL and crude services	—			699.6			230.4			—			930.0
Related party	—			7.2			32.5			(7.2		)	32.5
	—			713.8			295.7			(7.2		)	1,002.3
Expenses:
Operations and maintenance	—			31.3			73.3			—			104.6
General and administrative	—			10.0			83.5			—			93.5
Depreciation, amortization and accretion	—			26.0			141.9			—			167.9
	—			67.3			298.7			—			366.0
Other operating income (expense):
Gain (loss) on long-lived assets, net	—			(0.1		)	5.4			—			5.3
Goodwill impairment	—			—			(4.1		)	—			(4.1		)
Loss on contingent consideration	—			—			(31.4		)	—			(31.4		)
Operating income (loss)	—			(5.9		)	34.1			—			28.2
Earnings (loss) from unconsolidated affiliates, net	—			—			(0.1		)	—			(0.1		)
Interest and debt expense, net	(6.5		)	—			(71.4		)	—			(77.9		)
Other income, net	—			0.2			—			—			0.2
Equity in net income (loss) of subsidiary	(43.9		)	—			—			43.9			—
Income (loss) before income taxes	(50.4		)	(5.7		)	(37.4		)	43.9			(49.6		)
Provision for income taxes	0.2			0.1			0.7			—			1.0
Net income (loss)	(50.6		)	(5.8		)	(38.1		)	43.9			(50.6		)
Net (income) loss attributable to non-controlling partners in subsidiaries	—			—			57.3			—			57.3
Net income (loss) attributable to partners	$	(50.6	)	$	(5.8	)	$	19.2		$	43.9		$	6.7

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Condensed Consolidating Statements of Comprehensive Income
Year Ended December 31, 2014
(in millions)
	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Net income (loss)	$	(10.4	)	$	55.0	$	(40.8	)	$	(14.2	)	$	(10.4	)
Change in fair value of Suburban Propane Partners, LP units	(0.5		)	—		—			—			(0.5		)
Comprehensive income (loss)	$	(10.9	)	$	55.0	$	(40.8	)	$	(14.2	)	$	(10.9	)



Condensed Consolidating Statements of Comprehensive Income
Year Ended December 31, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations		Consolidated
Net income (loss)	$	(50.6	)	$	(5.8	)	$	(38.1	)	$	43.9	$	(50.6	)
Change in fair value of Suburban Propane Partners, LP units	(0.1		)	—			—			—		(0.1		)
Comprehensive income (loss)	$	(50.7	)	$	(5.8	)	$	(38.1	)	$	43.9	$	(50.7	)

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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:	$	(25.3	)	$	(14.6	)	$	322.9		$	—		$	283.0

Cash flows from investing activities:
Acquisitions, net of cash acquired	—			—			(19.5		)	—			(19.5		)
Purchases of property, plant and equipment	(3.8		)	(13.2		)	(407.0		)	—			(424.0		)
Investment in unconsolidated affiliates	35.8			—			(144.4		)	—			(108.6		)
Proceeds from the sale of assets	—			2.7			—			—			2.7
Proceeds from the sale of Tres Palacios	66.4			—			—			—			66.4
Capital contributions from consolidated affiliates, net	72.4			—			—			(72.4		)	—
Net cash provided by (used in) investing activities	170.8			(10.5		)	(570.9		)	(72.4		)	(483.0		)

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	734.0			—			2,089.9			—			2,823.9
Principal payments on long-term debt	(746.2		)	—			(1,949.8		)	—			(2,696.0		)
Payments on capital leases	—			—			(3.2		)	—			(3.2		)
Payments for debt-related deferred costs	(1.8		)	—			(0.1		)	—			(1.9		)
Distributions paid to partners	(102.5		)	—			(72.4		)	72.4			(102.5		)
Distributions paid to non-controlling partners	—			—			(296.5		)	—			(296.5		)
Net proceeds from issuance of preferred equity of subsidiary	—			—			53.9			—			53.9
Net proceeds from issuance of CMLP Class A preferred units	—			—			430.5			—			430.5
Taxes paid for unit-based compensation vesting	—			(2.3		)	(1.6		)	—			(3.9		)
Change in intercompany balances	(25.4		)	25.4			—			—			—
Other	—			0.1			(0.8		)	—			(0.7		)
Net cash provided by (used in) financing activities	(141.9		)	23.2			249.9			72.4			203.6

Net change in cash	3.6			(1.9		)	1.9			—			3.6
Cash at beginning of period	0.1			2.4			2.7			—			5.2
Cash at end of period	$	3.7		$	0.5		$	4.6		$	—		$	8.8

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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:	$	(12.3	)	$	14.1		$	186.5		$	—		$	188.3

Cash flows from investing activities:
Acquisitions, net of cash acquired	—			5.9			(561.5		)	—			(555.6		)
Purchases of property, plant and equipment	—			(12.4		)	(334.6		)	—			(347.0		)
Investment in unconsolidated affiliates, net	—			—			(151.5		)	—			(151.5		)
Capital contributions from consolidated affiliates, net and other	20.7			0.1			11.1			(20.7		)	11.2
Net cash provided by (used in) investing activities	20.7			(6.4		)	(1,036.5		)	(20.7		)	(1,042.9		)

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	394.1			—			2,072.8			—			2,466.9
Principal payments on long-term debt	(333.3		)	—			(1,634.3		)	—			(1,967.6		)
Distributions paid to partners	(68.4		)	—			(155.2		)	26.2			(197.4		)
Distributions paid to non-controlling partners	—			—			(204.5		)	—			(204.5		)
Net proceeds from the issuance of CMLP common units	—			—			714.0			—			714.0
Net proceeds from issuance of preferred equity of subsidiary	—			—			96.1			—			96.1
Change in intercompany balances	0.4			(0.4		)	—			—			—
Other	(1.1		)	(4.9		)	(36.3		)	(5.5		)	(47.8		)
Net cash provided by (used in) financing activities	(8.3		)	(5.3		)	852.6			20.7			859.7

Net increase in cash	0.1			2.4			2.6			—			5.1
Cash at beginning of period	—			—			0.1			—			0.1
Cash at end of period	$	0.1		$	2.4		$	2.7		$	—		$	5.2

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Note 19 - Quarterly Financial Data (Unaudited)

Summarized unaudited quarterly financial data is presented below (in millions, except per unit information):



	Quarter Ended
	March 31				June 30			September 30			December 31
2014
Revenues	$	971.6			$	926.3		$	1,036.2		$	997.2
Operating income (loss)	45.7				29.4			43.0			(0.2		)	⁽¹⁾
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	$	0.11			$	(0.02	)	$	0.02		$	0.21
Diluted	$	0.11			$	(0.02	)	$	0.02		$	0.21
2013
Revenues	$	72.4			$	118.9		$	427.2		$	808.2
Operating income (loss)	15.7				7.8			15.8			(11.1		)	⁽²⁾
Earnings (loss) from unconsolidated affiliates, net	—				—			(0.4		)	0.3
Net income (loss)	3.9				(4.5		)	(7.9		)	(42.1		)
Net income (loss) attributable to partners	5.1				1.6			(8.3		)	8.3
Net income (loss) per limited partner unit:
Basic⁽⁴⁾	$	0.13		⁽³⁾	$	0.03		$	(0.05	)	$	0.04
Diluted⁽⁴⁾	$	0.13		⁽³⁾	$	0.03		$	(0.05	)	$	0.04

(1)

Includes goodwill, property, plant and equipment and intangible impairments of approximately $48.8 million, $13.2 million and $21.3 million, respectively. See Note 2 for a further discussion of our impairments recorded during 2014. In addition, include 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)	Includes a $31.4 million loss on contingent consideration which reflects the fair value of an earn-out premium associated with the original acquisition of our Antero assets. See Note 3 for a further discussion of this non-cash charge.


(3)	Basic and diluted net income for the quarter ended March 31, 2013, were 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.


(4)	The accumulation of basic and diluted net income (loss) per limited partner unit does not total the amount for the year due to changes in ownership percentages throughout the year.

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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)

Dated:	February 27, 2015	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 and directors of Crestwood Equity GP, LLC, as general partner of Crestwood Equity Partners LP, the registrant, in the capacities and on the dates indicated.



Date		Signature and Title
February 27, 2015		/S/ ROBERT G. PHILLIPS Robert G. Phillips, President, Chief Executive Officer and Director (Principal Executive Officer)

February 27, 2015		/S/ MICHAEL J. CAMPBELL Michael J. Campbell, Senior Vice President and Chief Financial Officer (Principal Financial Officer)

February 27, 2015		/S/ STEVEN M. DOUGHERTY Steven M. Dougherty, Senior Vice President and Chief Accounting Officer (Principal Accounting Officer)

February 27, 2015		/S/ ALVIN BLEDSOE Alvin Bledsoe, Director

February 27, 2015		/S/ MICHAEL G. FRANCE Michael G. France, Director

February 27, 2015		/S/ WARREN H. GFELLER Warren H. Gfeller, Director

February 27, 2015		/S/ ARTHUR B. KRAUSE Arthur B. Krause, Director

February 27, 2015		/S/ RANDY E. MOEDER Randy E. Moeder, Director

February 27, 2015		/S/ JOHN J. SHERMAN John J. Sherman, Director

February 27, 2015		/S/ JOHN W. SOMERHALDER II John W. Somerhalder II, Director

February 27, 2015		/S/ DAVID M. WOOD David M. Wood, Director

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Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Balance Sheet

(in millions)



	December 31,
	2014		2013
Assets
Current assets:
Cash	$	3.7	$	0.1
Accounts receivable - intercompany	3.2		—
Total current assets	6.9		0.1

Property, plant and equipment, net	2.5		—
Intangible assets	1.7		—
Investment in subsidiaries	5,971.2		5,927.1
Total assets	$	5,982.3	$	5,927.2

Liabilities and partners’ capital
Current liabilities:
Accrued expenses	$	1.9	$	2.0
Current portion of long-term debt	3.0		2.2
Total current liabilities	4.9		4.2

Long-term debt, less current portion	380.0		393.0
Other long-term liabilities	12.9		21.4

Total partners’ capital	5,584.5		5,508.6
Total liabilities and partners’ capital	$	5,982.3	$	5,927.2

See accompanying notes.

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Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statement of Operations

(in millions)



	Year Ended December 31,
	2014			2013			2012
Revenues	$	—		$	—		$	—
Expenses	8.5			—			21.3
Gain on contingent consideration	—			—			6.8
Operating income (loss)	(8.5		)	—			(14.5		)
Interest and debt expense, net	(15.7		)	(6.5		)	—
Equity in net income (loss) of subsidiaries	14.2			(43.9		)	38.9
Income (loss) before income taxes	(10.0		)	(50.4		)	24.4
Provision for income taxes	0.4			0.2			—
Net income (loss)	(10.4		)	(50.6		)	24.4
Net (income) loss attributable to non-controlling partners	—			—			(9.5		)
Net income (loss) attributable to Crestwood Equity Partners LP	$	(10.4	)	$	(50.6	)	$	14.9

See accompanying notes.

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Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statement of Comprehensive Income

(in millions)



	Year Ended December 31,
	2014			2013			2012
Net income (loss)	$	(10.4	)	$	(50.6	)	$	24.4
Change in fair value of Suburban Propane Partners, LP units	(0.5		)	(0.1		)	—
Comprehensive income (loss)	$	(10.9	)	$	(50.7	)	$	24.4

See accompanying notes.

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Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statement of Cash Flows

(in millions)



	Year Ended December 31,
	2014			2013			2012
Cash flows from operating activities	$	(25.3	)	$	(12.3	)	$	—

Cash flows from investing activities	170.8			20.7			(146.2		)

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	734.0			394.1			—
Principal payments on long-term debt	(746.2		)	(333.3		)	—
Payments for debt-related deferred costs	(1.8		)	—			—
Distributions paid to partners	(102.5		)	(68.4		)	(103.5		)
Contributions received	—			—			249.7
Change in intercompany balances	(25.4		)	0.4			—
Other	—			(1.1		)	—
Net cash provided by (used in) financing activities	(141.9		)	(8.3		)	146.2

Net change in cash	3.6			0.1			—
Cash at beginning of period	0.1			—			—
Cash at end of period	$	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.

The condensed statement of cash flows for the year ended December 31, 2013 has been corrected for certain errors in presentation. There was no impact to our condensed statement of cash flows for the year ended December 31, 2013. The following table summarizes the impact of the adjustments (in millions):



	As Adjusted			As Previously Reported
Cash flows from operating activities:	$	(12.3	)	$	—

Cash flows from investing activities:	20.7			76.0

Cash flows from financing activities:
Proceeds from the issuance of long-term debt	394.1			—
Principal payments on long-term debt	(333.3		)	—
Distributions paid to partners	(68.4		)	(76.0		)
Distributions paid to non-controlling partners	—			—
Change in intercompany balances	0.4			—
Other	(1.1		)	0.1
Net cash used in financing activities	$	(8.3	)	$	(75.9	)

Note 2. Distributions

During the years ended December 31, 2014, 2013 and 2012, we received cash distributions from Crestwood Midstream Partners LP of approximately $72.4 million, $26.2 million and $25.8 million.

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Schedule II

Crestwood Equity Partners LP

Valuation and Qualifying Accounts

For the Years Ended December 31, 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⁽¹⁾
2014	$	0.1	$	—		$	—	$	—	$	0.1
2013	—		(1.1		)	1.2		—		0.1

(1) There was no activity for the year ended December 31, 2012.

165