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

OR

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

COMMISSION FILE NUMBER: 001-35377

Crestwood Midstream Partners LP

(Exact name of registrant as specified in its charter)

Delaware	20-1647837
(State or other jurisdiction of incorporation or organization)	(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  ¨

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.

Large accelerated filer	x	Accelerated filer	¨
Non-accelerated filer	¨  (Do not check if a smaller reporting company)	Smaller reporting company	¨

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

The aggregate market value of the 153,572,091 common units of the registrant held by non-affiliates computed by reference to the $14.99 closing price of such common units on February 13, 2015, was $2.3 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 $3.3 billion based on a closing price of $22.07 per common unit as reported on the New York Stock Exchange on such date. As of February 13, 2015, the registrant had 188,356,692 common units outstanding.

DOCUMENTS INCORPORATED BY REFERENCE

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

CRESTWOOD MIDSTREAM PARTNERS LP

INDEX TO ANNUAL REPORT ON FORM 10-K

		Page
	PART I
Item 1.	Business	6
Item 1A.	Risk Factors	24
Item 1B.	Unresolved Staff Comments	43
Item 2.	Properties	43
Item 3.	Legal Proceedings	43
Item 4.	Mine Safety Disclosures	43
	PART II
Item 5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	44
Item 6.	Selected Financial Data	45
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	68
Item 8.	Financial Statements and Supplementary Data	69
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	69
Item 9A.	Controls and Procedures	69
Item 9B.	Other Information	70
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	71
Item 11.	Executive Compensation	76
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	79
Item 13.	Certain Relationships and Related Transactions, and Director Independence	80
Item 14.	Principal Accountant Fees and Services	83
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	85

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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 Codifications.
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 Midstream,” and similar terms refer to Crestwood Midstream Partners LP and its consolidated subsidiaries, as the context requires, (ii) “Legacy Inergy” refers to Inergy Midstream, L.P. and its consolidated subsidiaries prior to the Crestwood Merger (defined below), and (iii) “Legacy Crestwood” refers to either Crestwood Midstream Partners LP itself or 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 Midstream, a Delaware limited partnership formed in 2004, is a growth-oriented master limited partnership (MLP) that develops, acquires, owns 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 “CMLP.”

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 primarily 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 1.7 million barrels of storage capacity; and

• 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.

Our primary business objective is to increase the cash distributions that we pay to our unitholders by growing 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 expect to increase cash available for distribution to our unitholders through organic growth and increased operational efficiencies. We also anticipate growing our business through strategic and bolt-on acquisitions, including asset drop downs, with an emphasis on acquisitions that further expand our existing asset footprint and the combination of value chain services we provide for our customers.

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Ownership Structure

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

7

On October 7, 2013, the operations of our company and Legacy Crestwood were combined when (i) one of our wholly-owned subsidiaries merged with and into Legacy Crestwood, with Legacy Crestwood surviving the merger and becoming a wholly-owned subsidiary of us, and (ii) Legacy Crestwood immediately thereafter merged with and into our company (collectively, the Crestwood Merger). Contemporaneously with the Crestwood Merger, we changed our name to Crestwood Midstream Partners LP and changed our NYSE listing symbol to “CMLP.” See Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 1 for additional information on the Crestwood Merger and certain transactions related thereto.

Our non-economic general partner interest is held by Crestwood Midstream GP LLC, which we refer to as our general partner and which is owned by CEQP. CEQP also owns 100% of our incentive distribution rights (IDRs) and, as of December 31, 2014, approximately 4% of our common units representing limited partnership interests. Given that CEQP owns and controls our general partner, and the entity that owns and controls CEQP’s general partner is substantially owned and controlled by First Reserve Management, L.P. (First Reserve), we are effectively controlled by First Reserve.

Our Assets

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) New Mexico	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.

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.

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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 system (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/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/Bone Spring Shale 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	10
	Processing	Mixed	—	Sabine Oil and Gas, Trinity	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 agreements. 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 formed the Tres Holdings joint venture with Brookfield Infrastrucure Group (Brookfield) to acquire 100% of the membership interest in Tres Palacios, which owns a 38.4 Bcf multi-cycle salt dome gas storage facility located in Texas. 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 acquisition, we own a 50.01% interest in Tres Palacios and operate its natural gas storage facility. Brookfield owns the remaining 49.99% interest in Tres Palacios. See Part IV, Item 15, Exhibit, Financial Statement Schedules, Note 6 for a further discussion of our acquisition 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

• 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

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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 crude oil rail terminals, the Arrow gathering system, our fleet of over-the-road crude oil and produced water transportation assets, an NGL storage facility, and US Salt, LLC (US Salt).

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

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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.

Bath. Our NGL storage assets include the Bath storage facility, a 1.7 million barrel NGL storage facility located near Bath, New York. The facility is located approximately 210 miles northwest of New York City. It is supported by both rail and truck terminal facilities capable of loading and unloading 23 railcars per day and approximately 100 truck transports per day.

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 Power 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.

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.	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 the emerging PRB Niobrara continues to increase.

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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.

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.

In December 2014, we entered into an agreement to lease crude oil rail cars comprising two 120-car unit trains. We began receiving the unit trains in December 2014, and we expect to receive and take possession of all unit trains by the end of February 2015. We plan to deploy the unit trains as part of our crude oil marketing operations, which focuses primarily on the marketing of crude oil sourced in the Bakken and PRB Niobrara.

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.

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Customers

For the fiscal year ended December 31, 2014, Tesoro, QEP Resources Inc. and Eighty-Eight Oil LLC accounted for approximately 16%, 11% and 11% of our total consolidated revenues. For the fiscal year ended December 31, 2013, Quicksilver accounted for approximately 15% of our total consolidated revenues. For the fiscal 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; store crude oil, natural gas and NGLs; and transport crude oil and natural gas.

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

Crude Oil

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

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

Natural Gas

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

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

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plants extract the NGLs, leaving residual lean gas that meets transmission pipeline quality specifications for ultimate consumption. Processing plants also produce marketable NGLs, which, on an energy equivalent basis, typically have a greater economic value as a raw material for petrochemicals and motor gasolines than as a component of the natural gas stream.

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

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

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

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

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

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.

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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 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.

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).

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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 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

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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 NYSDEC therefore regulates aspects of our Stagecoach, Thomas Corners, Seneca Lake and Steuben natural gas storage facilities.

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

Natural Gas Gathering

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

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

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

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

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NGL Storage

Our Bath storage terminal is subject primarily to state and local regulation. For example, the NYSDEC has jurisdiction over the underground storage of NGLs and well drilling, conversion and plugging in New York. Thus, 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.

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

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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. 

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.

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

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, our subsidiary, US Salt, had 130 employees, 96 of which are members of the United Steel Workers union. We do not otherwise have employees, and we rely on CEQP under an omnibus agreement to provide us the corporate and other employees needed to carry out our operations. 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 Midstream Partners LP, 700 Louisiana Street, Suite 2550, Houston, Texas 77002, and our telephone number is (832) 519-2200.

We also make available within the “Corporate Governance” section of our website our corporate governance guidelines, the charter of our Audit Committee and our Code of Business Conduct and Ethics. Requests for copies may be directed in writing to Crestwood Midstream 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 Midstream 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) each accounted for approximately 4%, respectively, of our total consolidated revenues in 2014. Within our NGL and crude services segment, five producers primarily on our Arrow system in the Bakken Shale accounted for approximately 49% of our total consolidated revenues in 2014. Given the current commodity price environment and its anticipated impact on shale production, we expect our gathering 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.

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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 $2.0 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:

• 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.

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

We have a $1 billion revolving credit facility (expandable up to $1.25 billion) that matures in October 2018. Our revolving credit facility will be available to fund working capital and our growth projects, make acquisitions and for general partnership purposes.

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

• incur additional debt;

• make distributions on or redeem or repurchase units;

• make certain investments and acquisitions; 

• incur or permit certain liens to exist; 

• enter into certain types of transactions with affiliates;

• merge, consolidate or amalgamate with another company; and 

• transfer or otherwise dispose of assets.

Furthermore, our revolving credit facility contains covenants requiring us to maintain certain financial ratios. For example, our revolving credit facility requires maintenance of a consolidated leverage ratio (as defined in our 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 our credit agreement) of not less than 2.50 to 1.00. Borrowings under our revolving credit facility are secured by (i) pledges of the equity interests of, and guarantees by, substantially all of our existing and future restricted domestic subsidiaries, and (ii) liens on substantially all of our real property (outside of New York) and personal property.

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

A change of control could result in us facing substantial repayment obligations under our revolving credit facility.

Our credit agreement contains provisions relating to change of control of our general partner and our partnership. 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 facility 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.

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

Historically, we have used cash flow from operations, borrowings under our revolving credit facility and issuances of debt and equity to fund our capital program, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our operations to fund our 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.

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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.

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.

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

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

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

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

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

• rates, operating terms and conditions of service;

• the form of tariffs governing service;

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

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

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

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

• creditworthiness and credit support requirements; 

• the maintenance of accounts and records;

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

• the initiation and discontinuation of services; and 

• various other matters.

Natural gas companies may not charge rates that, upon review by 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 and Steuben facilities and (ii) negotiated rates for interstate transportation services provided by our North-South Facilities and our 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

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these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to $1,000,000 per day, per violation.

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

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

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

Our operations are subject to compliance with environmental and operational safety laws and regulations that may expose us to significant costs and liabilities.

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

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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 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 use, 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

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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 environmentalor suspension of operations.

These risks could result in substantial losses due to breaches of contractual commitments, personal injury and/or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage. For example, we 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 also share insurance coverage with Crestwood Equity, for which we reimburse Crestwood Equity pursuant to the terms of the omnibus agreement. To the extent Crestwood Equity experiences covered losses under the insurance policies, the limit of our coverage for potential losses may be decreased.

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.

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

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

Risks Inherent in an Investment in Us

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

We may not have sufficient cash each quarter to continue payments consistent with the full amount of our quarterly distribution of $0.41 per common unit, or $1.64 per common unit per year. 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 cash distributions on our preferred and common units, we will establish reserves and pay fees and expenses, including reimbursements to our general partner and its affiliates, including Crestwood Equity, 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 unitholders and, to the extent we are unable to declare and pay fixed cash distributions on our Class A Preferred Units following the quarter ending June 30, 2017, we cannot make cash distributions to our common unitholders until all payments accruing on the preferred units have been repaid.

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

• the rates we charge for storage and transportation services and the amount of services our customers purchase from us, which will be affected by, among other things, the overall balance between the supply of and demand for natural gas, 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 preferred and 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. Subject to certain restrictions that apply if we are not able to pay

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cash distributions to our preferred unitholders following the quarter ending June 30, 2017, there are no limitations in our partnership agreement, or in our revolving credit facility, on our ability to issue additional 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 unitholders.

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

Subject to limited exception, 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 Equity, as a result of it owning our general partner, and not by our common unitholders. Unlike publicly traded corporations, we will not conduct annual meetings of our common unitholders to elect directors or conduct other matters routinely conducted at annual meetings of stockholders of corporations. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

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

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

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

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

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

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.

Reimbursements due to our general partner and its affiliates for services provided to us or on our behalf will reduce cash available for distribution to our common unitholders. The amount and timing of such reimbursements will be determined by our general partner.

Prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including Crestwood Equity, for all administrative costs and other expenses they incur and payments they make on our behalf pursuant to the omnibus agreement. Under the omnibus agreement, we will reimburse our general partner and its affiliates for all expenses incurred on our behalf, including administrative costs, such as compensation expense for those persons who provide services necessary to run our business, and insurance expenses. As of December 31, 2014, we reimbursed our general partner and its affiliates approximately $105.6 million (including $48.9 million in reimbursements of direct personnel related expenses). Neither our partnership agreement nor the omnibus agreement limits the amount of expenses for which our general partner and its affiliates may be reimbursed. Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us. The reimbursement of expenses and payment of fees, if any, to our general partner and its affiliates will reduce the amount of available cash to pay cash distributions to our common unitholders.

The credit and risk profile of our general partner and its owner, Crestwood Equity, could adversely affect our credit ratings and risk profile, which could increase our borrowing costs or hinder our ability to raise capital.

The credit and business risk profiles of our general partner and Crestwood Equity may be factors considered in credit evaluations of us. This is because our general partner, which is owned by Crestwood Equity, controls our business activities, including our cash distribution policy and growth strategy. Any adverse change in Crestwood Equity's financial condition, including the degree of its financial leverage and its dependence on cash flow from us to service its debt, may adversely affect our credit ratings and risk profile.

If we were to seek a credit rating in the future, our credit rating may be adversely affected by the leverage of our general partner or Crestwood Equity, as credit rating agencies such as Standard & Poor's Ratings Services and Moody's Investors Service may consider the leverage and credit profile of Crestwood Equity and its affiliates because of their ownership interest in and control of us. Any adverse effect on our credit rating would increase our cost of borrowing or hinder our ability to raise financing in the capital markets, which would impair our ability to grow our business and make distributions to common unitholders.

Our general partner has a limited call right that may require unitholders to sell their common 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 common units held by unaffiliated persons at a price equal to the greater of (i) the average of the daily closing prices per limited partner interest of the class purchased for the 20 consecutive trading days immediately prior to the date three days before the date our general partner first mails notice of its election to purchase those limited partner interests, and (ii) the highest price paid by our general partner or any of its affiliates for any limited partner interests of the class purchased during the 90-day period preceding the date that the notice is mailed. As a result, our unitholders may be required to sell their common units at an undesirable time or price and may not receive any return or a negative return on their investment. Unitholders may also incur a tax liability upon a sale of their common units. Our general partner is not obligated to obtain a fairness opinion regarding the value of the common units to be repurchased by it upon exercise of the limited call right. There

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is no restriction in our partnership agreement that prevents our general partner from issuing additional common units and exercising its call right. If our general partner exercised its limited call right, the effect would be to take us private and, if the units were subsequently deregistered, we would no longer be subject to the reporting requirements of the Exchange Act. As of December 31, 2014 Crestwood Equity owns, directly or indirectly, an aggregate of approximately 4% of our common units.

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 27,995,823 common 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.

Our Class A Preferred Units contain covenants that may limit our business flexibility.

Our Class A Preferred Units contain covenants preventing us from taking certain actions without the approval of the holders of a majority or a super-majority of the Class A Preferred Units, depending on the action as described below. The need to obtain the approval of holders of the Class A Preferred Units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of our unitholders. The affirmative vote of the then-applicable voting threshold of the outstanding Class A Preferred Units, voting separately as a class with one vote per Class A Preferred Unit, shall be necessary to amend our Partnership Agreement in any manner that (1) alters or changes the rights, powers, privileges or preferences or duties and obligations of the Class A Preferred Units in any material respect, (2) except as contemplated in the Partnership Agreement, increases or decreases the authorized number of Class A Preferred Units, or (3) otherwise adversely affects the Class A Preferred Units, including without limitation the creation (by reclassification or otherwise) of any class of senior securities (or amending the provisions of any existing class of Partnership interests to make such class of partnership interests a class of senior securities). In addition, our Partnership Agreement provides certain rights to the Preferred Unitholders that could impair our ability to consummate (or increase the cost of consummating) a change-in-control transaction, which could result in less economic benefits accruing to our common unitholders.

Risks Inherent in Our Structure and Relationship with Crestwood Equity

Crestwood Equity controls our general partner, which has sole responsibility for conducting our business and managing our operations. Our general partner and its affiliates, including Crestwood Equity, have conflicts of interest with us and limited duties, and they may favor their own interests to the detriment of us and our common unitholders.

Crestwood Equity owns and controls our general partner and appoints all of the directors of our general partner. Although our general partner has a duty to manage our partnership in a manner it believes is in our best interests, the executive officers and directors of our general partner have a fiduciary duty to manage our general partner in a manner beneficial to Crestwood Equity. Therefore, conflicts of interest may arise between our general partner and its affiliates, including Crestwood Equity, on the one hand, and us and our common unitholders, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its affiliates over the interests of our common unitholders.

Crestwood Equity and other affiliates of our general partner may compete with us and are not obligated to offer us the opportunity to acquire additional assets or businesses, which could limit our ability to grow and could adversely affect our results of operations and cash available for distribution to our unitholders.

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. Affiliates of our general partner, including Crestwood Equity, are not prohibited from engaging in other businesses or activities, including those that might be in direct competition with us. Crestwood Equity currently holds interests in NGL midstream assets, and may make investments in or purchases of entities that acquire, own and operate crude oil, natural gas or NGL midstream assets. In addition, Crestwood Equity is entitled under the omnibus agreement to review and has the first option on any third-party acquisition opportunities presented to us or to Crestwood Equity and is under no obligation to make acquisition opportunities available to us. These investments and acquisitions may include entities or assets that we would have been interested in acquiring. Therefore, Crestwood Equity may compete with us for investment opportunities, and may own interests in entities that compete with us.

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Pursuant to the terms of our partnership agreement, the doctrine of corporate opportunity, or any analogous doctrine, does not apply to our general partner or any of its affiliates, including its executive officers and directors and Crestwood Equity. Any such person or entity that becomes aware of a potential transaction, agreement, arrangement or other matter that may be an opportunity for us will not have any duty to communicate or offer such opportunity to us. Any such person or entity will not be liable to us or to any limited partner for breach of any fiduciary duty or other duty by reason of the fact that such person or entity pursues or acquires such opportunity for itself, directs such opportunity to another person or entity or does not communicate such opportunity or information to us. This may create actual and potential conflicts of interest between us and affiliates of our general partner and result in less than favorable treatment of us and our common unitholders.

Our general partner intends to limit its liability regarding our contractual and other obligations.

Our general partner intends to limit its liability under our contractual and other obligations so that the counterparties to such arrangements have recourse only against our assets and not against our general partner or its assets. Our general partner may therefore cause us to incur indebtedness or other obligations that are nonrecourse to our general partner. Our partnership agreement provides that any action taken by our general partner to limit its liability is not a breach of our general partner's duties, even if we could have obtained more favorable terms without the limitation on liability. In addition, we are obligated to reimburse or indemnify our general partner to the extent that it incurs obligations on our behalf. Any such reimbursement or indemnification payments would reduce the amount of cash otherwise available for distribution to our common unitholders.

Our partnership agreement restricts the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions that restrict the remedies available to our common unitholders for actions taken by our general partner that might otherwise constitute breaches of duty under state law with respect to fiduciary duties. For example, our partnership agreement provides that:

• whenever our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) makes a determination or takes, or declines to take, any other action in their respective capacities, our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee), as applicable, is required to make such determination, or take or decline to take such other action, in good faith, and is not subject to any higher standard imposed by our partnership agreement, Delaware law or any other law, rule or regulation, or at equity; 

• a determination, other action or failure to act by our general partner, the board of directors of our general partner or any committee thereof (including the conflicts committee) is deemed to be in good faith unless our general partner, the board of directors of our general partner or any committee thereof believed such determination, other action or failure to act was not in the best interests of the partnership; 

• our general partner does not have any liability to us or our common unitholders for decisions made in its capacity as a general partner so long as it acted in good faith; and 

• our general partner and its officers and directors are not be liable for monetary damages to us or our limited partners for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that our general partner or those other persons acted in bad faith or, in the case of a criminal matter, acted with knowledge that the conduct was unlawful. 

Whenever a conflict arises between our general partner or its affiliates, on the one hand, and us and our limited partners, on the other hand, the resolution or course of action in respect of such conflict of interest shall be permitted and deemed approved by all our limited partners and shall not constitute a breach of our partnership agreement, of any agreement contemplated thereby or of any duty, if the resolution or course of action in respect of such conflict of interest is (i) approved by the conflicts committee of the board of directors of our general partner, although our general partner is not obligated to seek such approval; or (ii) approved by the vote of a majority of the outstanding common units, excluding any common units owned by our general partner or its affiliates.

In connection with a situation involving a transaction with an affiliate or a conflict of interest, any determination by our general partner must be made in good faith. If an affiliate transaction or the resolution of a conflict of interest is not approved by our common unitholders or the conflicts committee then it will be presumed that, in making its decision, taking any action or failing to act, the board of directors acted in good faith, and in any proceeding brought by or on behalf of any limited partner or the partnership, the person bringing or prosecuting such proceeding will have the burden of overcoming such presumption.

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Unlike many other master limited partnerships, which require at least two independent members of the conflicts committee, our partnership agreement provides that a conflicts committee may be comprised of one or more directors. If we establish a conflicts committee with only one director, your interests may not be as well served as if we had a conflicts committee comprised of at least two independent directors. A single member conflicts committee would not have the benefit of discussion with and input from other independent directors.

Our partnership agreement limits our general partner's duties to holders of our common units.

Our partnership agreement contains provisions that modify and reduce the standards to which our general partner would otherwise be held by state law with respect to fiduciary duties. For example, our partnership agreement permits our general partner to make a number of decisions in its individual capacity, as opposed to in its capacity as our general partner, or otherwise free of contractual or fiduciary duties to us and our common unitholders. This entitles our general partner to consider only the interests and factors that it desires and relieves it of any duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or our limited partners. Examples of decisions that our general partner may make in its individual capacity include:

• how to allocate business opportunities among us and its affiliates; 

•whether to exercise its limited call right; 

•how to exercise its voting rights with respect to any common units it owns; 

•whether to exercise its registration rights; and

•whether or not to consent to any merger or consolidation of us or amendment to the partnership agreement.

By purchasing a common unit, a common unitholder is treated as having consented to the provisions in the partnership agreement, including the provisions discussed above. 

Crestwood Equity may elect to cause us to issue common units to it in connection with a resetting of the quarterly distribution related to its IDRs, without the approval of the conflicts committee of the board of directors of our general partner or the holders of our common units. This election could result in lower distributions to our common unitholders.

Crestwood Equity has the right to reset, at a higher level, the quarterly distribution based on our cash distributions at the time of the exercise of the reset election. Following a reset election, the quarterly distribution will be reset to an amount equal to the cash distribution amount per common unit for the quarter immediately preceding the reset election (which amount we refer to as the reset quarterly distribution).

If Crestwood Equity elects to reset the quarterly distribution, it will be entitled to receive a number of newly issued common units. The number of common units to be issued to Crestwood Equity will equal the number of common units that would have entitled the holder to the quarterly cash distribution in the prior quarter equal to the distribution to Crestwood Equity on the IDRs in such prior quarter. It is possible that Crestwood Equity could exercise this reset election at a time when it is experiencing, or expects to experience, declines in the cash distributions it receives related to its IDRs and may, therefore, desire to be issued common units rather than retain the right to receive incentive distributions based on the quarterly distribution. As a result, a reset election may cause our common unitholders to experience a reduction in the amount of cash distributions that our common unitholders would have otherwise received had we not issued new common units to Crestwood Equity in connection with resetting the quarterly distribution.

Even if holders of our common units are dissatisfied, they cannot currently remove our general partner without its consent.

If our common unitholders are dissatisfied with the performance of our general partner, they have limited ability to remove our general partner. The vote of the holders of at least two-thirds of all our outstanding partnership interests voting together as a class is required to remove our general partner. As of December 31, 2014, Crestwood Equity owns, directly or indirectly, an aggregate of 4% of our common units.

Our general partner interest, our IDRs and control of our general partner may be transferred without common unitholder consent.

Our partnership agreement provides that, at any time, our general partner may transfer all or any of its general partner interest or common units to another person without the consent of our common unitholders. If the sole member of our general partner transfers its membership interest in our general partner to a third party, the third party would be in a position to replace the board of directors and executive officers of our general partner with its designees and thereby exert significant control over the decisions taken by the board of directors and executive officers of our general partner. This effectively permits a “change of

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control” without the vote or consent of the common unitholders. Our partnership agreement also provides that the holder of the IDRs may transfer those interests to a third party at any time without the consent of our common unitholders. Crestwood Equity indirectly owns all of our IDRs. If Crestwood Equity transfers its IDRs to a third party, Crestwood Equity may not have the same incentive to grow our partnership and increase quarterly distributions to common unitholders over time as it would if it had retained ownership of the IDRs.

Tax Risks to Common Unitholders

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

The anticipated after-tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations, we believe we satisfy the qualifying income requirement.

Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, as well as any applicable state or local taxes. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our common units.

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

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. For example, the Obama administration’s budget proposal for fiscal year 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 a corporation upon which we 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 to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

If the IRS 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.

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

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

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

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

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The 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 saleof common units) may be considered as having disposed of those common units. If so, hewould no longer be treated for tax purposes as a partner with respect to thosecommon units during the period of the loan and may recognize gain or loss from thedisposition.

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 portion of our gathering and processing operations, and we own 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 and real property interests located outside of the State of New York. 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.

See Part IV, Item 15, Exhibits and Financial Statement Schedules, Note 12 for information related to our legal proceedings.

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 “CMLP.” 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	$	13.73	$	22.78	$	0.410
September 30, 2014	20.23		24.25		0.410
June 30, 2014	21.25		24.20		0.410
March 31, 2014	21.62		24.88		0.410
2013
December 31, 2013	$	20.40	$	24.94	$	0.410
September 30, 2013	21.41		25.60		0.405
June 30, 2013	21.03		26.01		0.400
March 31, 2013	22.27		25.00		0.395

The last reported sale price of our common units on the NYSE on February 13, 2015, was $14.99. As of that date, we had 188,356,692 common units issued and outstanding, which were held by 265 unitholders of record.

Cash Distribution Policy

Class A Preferred Units. Our partnership agreement requires us to make quarterly distributions to our Class A Preferred Unit holders. The holders of our Class A Preferred Units (the Preferred Units) are entitled to receive fixed quarterly distributions of $0.5804 per unit. For the 12 quarters following the quarter ended June 30, 2014 (the Initial Distribution Period), distributions on our Preferred Units can be made in additional Preferred Units, cash, or a combination thereof, at our election. If we elect to pay the quarterly distribution through the issuance of additional Preferred Units, the number of units to be distributed will be calculated as the fixed quarterly distribution of $0.5804 per unit divided by the cash purchase price of $25.10 per unit. We accrue the fair value of such distribution at the end of the quarterly period and adjust the fair value of the distribution on the date the additional Preferred Units are distributed. Distributions on our Preferred Units following the Initial Distribution Period will be made in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to our Preferred Unit holders. If we fail to pay the full amount payable to our Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.7059 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if we fail to pay in full any Class A Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

On February 13, 2015 we issued 414,325 Class A Preferred Units to our preferred unitholders for the quarter ended December 31, 2014 in lieu of paying a cash distribution.

Common Units. 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 our 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;

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

On February 13, 2015, we paid a distribution of $0.41 per common unit ($1.64 per common unit on an annualized basis) to all unitholders of record on February 6, 2015.

Incentive Distribution Rights

CEQP holds IDRs that entitle it to receive 50% of all distributions paid by us in excess of our initial quarterly distribution of $0.37 per common unit.

Issuer Purchases of Equity Securities

For the year ended December 31, 2014, 71,484 common units were relinquished to cover payroll taxes upon the vesting of restricted units. 

Equity Compensation Plan Information

The following table sets forth in tabular format, a summary of our 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	—	$	—	17,629,657
Total	—	$	—	17,629,657

Item 6. Selected Financial Data.

Our consolidated financial statements were originally the financial statements of Legacy Crestwood prior to the Crestwood Merger on October 7, 2013. Crestwood Holdings acquisition of control of CEQP’s general partner on June 19, 2013 was accounted for as a reverse acquisition under the purchase method of accounting in accordance with accounting standards for business combinations.  The accounting for a reverse merger results in the legal acquiree (Crestwood Gas Services GP LLC) being the acquirer for accounting purposes.  The accounting acquiree (Inergy, inclusive of Inergy Midstream) was subject to the purchase method of accounting and its balance sheet was adjusted to fair market value as of June 19, 2013.  The merger of Legacy Crestwood and Inergy Midstream on October 7, 2013 was accounted for as a reverse merger amongst entities under common control.  Although Legacy Crestwood was the surviving entity for accounting purposes, Inergy Midstream was the surviving entity for legal purposes, and consequently we changed our name from Inergy Midstream, LP to Crestwood Midstream Partners, LP.  As the reverse merger was amongst entities under common control, the financial statements have been recast to reflect the operations of Inergy Midstream as being acquired by Legacy Crestwood on June 19, 2013, the date in which Inergy Midstream and Legacy Crestwood came under common control. 

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.

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EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company's operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. 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, 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.

	Crestwood Midstream Partners LP  Year Ended December 31, (in millions, except per unit data)
	2014			2013 (1)			2012			2011			2010
Statement of Income Data:
Revenues	$	2,565.5		$	658.6		$	239.5		$	205.8		$	113.6
Operating income	90.9			57.1			75.9			73.9			47.9
Income (loss) before income taxes	(21.2		)	(14.4		)	40.1			46.3			34.3
Net income (loss)	(21.9		)	(15.1		)	38.9			45.0			34.9
Net income (loss) attributable to partners	(55.9		)	(20.0		)	38.9			45.0			34.9
Performance Measures:
Diluted limited partner income (loss) per unit(2):
From net income (loss)	$	(0.46	)	$	(0.82	)	$	0.26		$	0.58		$	0.50
Distributions declared per limited partner unit(3)	$	1.64		$	1.61		$	1.525		$	0.04		$	—
Other Financial Data:
EBITDA (unaudited)	$	311.9		$	178.7		$	127.8		$	107.7		$	70.2
Adjusted EBITDA (unaudited)	442.5			261.9			134.4			110.9			78.4
Net cash provided by operating activities	322.9			186.5			102.1			86.3			48.0
Net cash used in investing activities	(570.9		)	(1,036.5		)	(616.6		)	(456.5		)	(149.3		)
Net cash provided by financing activities	249.9			852.6			513.8			371.0			100.6
Balance Sheet Data:
Property, plant and equipment, net	$	3,518.1		$	3,350.1		$	939.9		$	746.0		$	531.4
Total assets	6,596.5			6,401.8			1,610.6			1,026.9			570.6
Total debt, including current portion	2,013.5			1,870.8			685.2			512.5			283.5
Other long-term liabilities(4)	31.2			26.3			17.2			15.5			9.9
Partners' capital	4,297.4			4,193.1			859.7			455.6			258.7

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	2014			2013			2012			2011			2010
Reconciliation of Net Income to EBITDA and Adjusted EBITDA:
Net income (loss)	$	(21.9	)	$	(15.1	)	$	38.9		$	45.0		$	34.9
Depreciation, amortization and accretion	221.7			121.7			51.9			33.8			22.4
Interest and debt expense, net	111.4			71.4			35.8			27.6			13.5
Provision (benefit) for income taxes	0.7			0.7			1.2			1.3			(0.6		)
EBITDA	$	311.9		$	178.7		$	127.8		$	107.7		$	70.2
Unit-based compensation charges	18.1			15.8			1.9			0.9			5.5
(Gain) loss on long-lived assets, net(5)	33.6			(5.4		)	—			(1.1		)	—
Goodwill impairment(6)	48.8			4.1			—			—			—
Loss on contingent consideration(7)	8.6			31.4			—			—			—
Loss from unconsolidated affiliates, net	0.7			0.1			—			—			—
Adjusted EBITDA from unconsolidated affiliates, net	6.9			2.5			—			—			—
Significant transaction and environmental-related costs and other items(8)	13.9			34.7			4.7			3.4			2.7
Adjusted EBITDA	$	442.5		$	261.9		$	134.4		$	110.9		$	78.4
Reconciliation of Net Cash Provided by Operating Activities to EBITDA and Adjusted EBITDA:
Net cash provided by operating activities	$	322.9		$	186.5		$	102.1		$	86.3		$	48.0
Net changes in operating assets and liabilities	(5.4		)	(24.7		)	(4.1		)	(4.2		)	18.9
Amortization of debt-related deferred costs, discounts and premiums	(7.3		)	(9.1		)	(5.5		)	(3.5		)	(1.3		)
Interest and debt expense, net	111.4			71.4			35.8			27.6			13.5
Unit-based compensation charges	(18.1		)	(15.8		)	(1.9		)	(0.9		)	(5.5		)
Gain (loss) on long-lived assets, net(5)	(33.6		)	5.4			—			1.1			—
Goodwill impairment(6)	(48.8		)	(4.1		)	—			—			—
Loss on contingent consideration(7)	(8.6		)	(31.4		)	—			—			—
Loss from unconsolidated affiliates, net	(0.7		)	(0.1		)	—			—			—
Deferred income taxes	(0.6		)	—			—			—			0.8
Provision (benefit) for income taxes	0.7			0.7			1.2			1.3			(0.6		)
Other non-cash income	—			(0.1		)	0.2			—			(3.6		)
EBITDA	$	311.9		$	178.7		$	127.8		$	107.7		$	70.2
Unit-based compensation charges	18.1			15.8			1.9			0.9			5.5
(Gain) loss on long-lived assets, net(5)	33.6			(5.4		)	—			(1.1		)	—
Goodwill impairment(6)	48.8			4.1			—			—			—
Loss on contingent consideration(7)	8.6			31.4			—			—			—
Loss from unconsolidated affiliates, net	0.7			0.1			—			—			—
Adjusted EBITDA from unconsolidated affiliates, net	6.9			2.5			—			—			—
Significant transaction and environmental-related costs and other items(8)	13.9			34.7			4.7			3.4			2.7
Adjusted EBITDA	$	442.5		$	261.9		$	134.4		$	110.9		$	78.4

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

(2) Diluted net income per unit for the years ended December 31, 2012, 2011 and 2010, were computed based on the number of common units issued by Legacy Inergy to Legacy Crestwood unitholders as part of the Crestwood Merger.

(3) Reported amounts include the fourth quarter distribution, which was paid in the first quarter of the subsequent year. In addition, for the year ended December 31, 2011, the amount includes the period beginning December 21, 2011 (the closing date of Legacy Inergy's IPO) through December 31, 2011. Accordingly, the $0.04 cash distribution per unit corresponds to a pro-rated quarterly distribution per unit of $0.37.

(4) Other long-term liabilities primarily include our capital leases and asset retirement obligations.

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(5) During 2014, we recorded property, plant and equipment and intangible impairments of approximately $13.2 million and $21.3 million, respectively, for the year ended December 31, 2014. 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 will continue to benefit from 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 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 growth-oriented MLP that manages, owns and operates crude oil, natural gas and NGL midstream assets and operations. Headquartered in Houston, Texas, we are a fully-integrated midstream solution provider that specializes in connecting shale-based energy supplies to key demand markets. We conduct gathering, processing, storage and transportation operations in the most prolific shale plays across the United States.

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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 1.7 million barrels of storage capacity; and

• 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.

Our primary business objective is to increase the cash distributions that we pay to our unitholders. 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 cash available for distribution through organic growth and increased operational efficiencies. We also anticipate growing our business through strategic and bolt-on acquisitions, including asset drop downs, 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.

Our three business segments include (i) gathering and processing, which includes our natural gas G&P operations; (ii) storage and transportation, which includes our natural gas storage and transportation operations; and (iii) NGL and crude services, which includes our crude oil facilities and fleet, NGL storage facility and salt production business.

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 (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

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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 interconnected 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 relative to New York City and other premium demand markets along the East Coast helps to insulation our operations from production and commodity price changes that can more easily impact storage and transportation operators in other geographic regions.

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 formed a joint venture (Tres Holdings) with an affiliate of Brookfield to acquire Tres Palacios for total cash consideration of approximately $132.8 million, of which we paid approximately $66.4 million. We operate Tres Palacios and own a 50.01% interest in Tres Holdings, and Brookfield owns the remaining 49.99% interest. 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. In conjunction with the acquisition, Brookfield and Tres Palacios entered into a five-year, fixed fee contract under which Tres Palacios will make 15 Bcf of firm storage capacity and 150,000 Dth/d of enhanced interruptible 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 crude oil gathering systems and rail terminals, NGL storage facilities and US Salt. We have facilities located in the core of the Bakken Shale, one of the most prolific crude oil shales in North America, and the premium Northeast demand market. We utilize these facilities to provide gathering, storage and terminal services to our anchor customers, and we utilize our crude oil and NGL assets on a portfolio basis to provide integrated supply and logistics solutions to producers, refiners and other customers.

Our NGL and crude services operations primarily include:

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• 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;

• Bath Storage Facility. Our Bath facility, a 1.7 million barrel underground NGL storage facility in Bath, New York, is supported by rail and truck terminal facilities capable of loading and unloading 23 railcars and approximately 100 truck transports per day;

• 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 the Arrow operations are primarily fee-based with creditworthy counterparties under contracts with original terms ranging from 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 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 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.

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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, the significant growth capital projects that we completed in 2014, and the fact that over 90% of our contracts are fixed-fee in nature.  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.

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., the transportation of crude oil by rail). We also anticipate greater regulatory oversight in states like North Dakota and tribal sovereignties like the MHA Nation, where regulation in certain areas is now starting to align with the tremendous production growth experienced in those jurisdictions in a short period of time.

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How We Evaluate Our Operations

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

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

EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company's operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. EBITDA is defined as income before income taxes, plus 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, and other transactions identified in a specific reporting period. EBITDA and Adjusted EBITDA are not measures calculated in accordance with GAAP, as they do not include deductions for items such as depreciation, amortization and accretion, interest and income taxes, which are necessary to maintain our business. EBITDA and Adjusted EBITDA should not be considered an alternative to net income, operating cash flow or any other measure of financial performance presented in accordance with GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.

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

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Results of Operations

The following table summarizes our results of operations for 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.

	Year Ended December 31,
	2014			2013			2012
Revenues	$	2,565.5		$	658.6		$	239.5
Costs of product/services sold	1,937.5			295.7			39.0
Operations and maintenance	139.0			73.3			43.1
General and administrative	85.4			80.7			29.6
Depreciation, amortization and accretion	221.7			121.7			51.9
Gain (loss) on long-lived assets, net	(33.6		)	5.4			—
Goodwill impairment	(48.8		)	(4.1		)	—
Loss on contingent consideration	(8.6		)	(31.4		)	—
Operating income	90.9			57.1			75.9
Loss from unconsolidated affiliates, net	(0.7		)	(0.1		)	—
Interest and debt expense, net	(111.4		)	(71.4		)	(35.8		)
Provision for income taxes	(0.7		)	(0.7		)	(1.2		)
Net income (loss)	$	(21.9	)	$	(15.1	)	$	38.9
Add:
Interest and debt expense, net	111.4			71.4			35.8
Provision for income taxes	0.7			0.7			1.2
Depreciation, amortization and accretion	221.7			121.7			51.9
EBITDA	$	311.9		$	178.7		$	127.8
Unit-based compensation charges	18.1			15.8			1.9
(Gain) loss on long-lived assets, net	33.6			(5.4		)	—
Goodwill impairment	48.8			4.1			—
Loss on contingent consideration	8.6			31.4			—
Loss from unconsolidated affiliates, net	0.7			0.1			—
Adjusted EBITDA from unconsolidated affiliates, net	6.9			2.5			—
Significant transaction and environmental-related costs and other items(1)	13.9			34.7			4.7
Adjusted EBITDA	$	442.5		$	261.9		$	134.4

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	Year Ended December 31,
	2014			2013			2012
EBITDA:
Net cash provided by operating activities	$	322.9		$	186.5		$	102.1
Net changes in operating assets and liabilities	(5.4		)	(24.7		)	(4.1		)
Amortization of debt-related deferred costs, discounts and premiums	(7.3		)	(9.1		)	(5.5		)
Interest and debt expense, net	111.4			71.4			35.8
Unit-based compensation charges	(18.1		)	(15.8		)	(1.9		)
Gain (loss) on long-lived assets, net	(33.6		)	5.4			—
Goodwill impairment	(48.8		)	(4.1		)	—
Loss on contingent consideration	(8.6		)	(31.4		)	—
Loss from unconsolidated affiliates, net	(0.7		)	(0.1		)	—
Deferred income taxes	(0.6		)	—			—
Provision for income taxes	0.7			0.7			1.2
Other non-cash income	—			(0.1		)	0.2
EBITDA	$	311.9		$	178.7		$	127.8
Unit-based compensation charges	18.1			15.8			1.9
(Gain) loss on long-lived assets, net	33.6			(5.4		)	—
Goodwill impairment	48.8			4.1			—
Loss on contingent consideration	8.6			31.4			—
Loss from unconsolidated affiliates, net	0.7			0.1			—
Adjusted EBITDA from unconsolidated affiliates, net	6.9			2.5			—
Significant transaction and environmental-related costs and other items(1)	13.9			34.7			4.7
Adjusted EBITDA	$	442.5		$	261.9		$	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		$	179.1	$	2,053.9
Costs of product/services sold	71.3			14.3		1,851.9
Operations and maintenance expense	62.9			16.6		59.5
Gain (loss) on long-lived assets, net	(32.7		)	0.6		(1.5		)
Goodwill impairment	(18.5		)	—		(30.3		)
Loss on contingent consideration	(8.6		)	—		—
Earnings (loss) from unconsolidated affiliates	0.5			0.2		(1.4		)
EBITDA	$	139.0		$	149.0	$	109.3
	Year Ended December 31, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services
Revenues	$	291.2		$	90.1	$	277.3
Costs of product/services sold	56.6			8.7		230.4
Operations and maintenance expense	54.9			9.9		8.5
Gain on long-lived assets	5.4			—		—
Goodwill impairment	(4.1		)	—		—
Loss on contingent consideration	(31.4		)	—		—
Earnings (loss) from unconsolidated affiliates	0.1			—		(0.2		)
EBITDA	$	149.7		$	71.5	$	38.2
	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			—		—
EBITDA	$	157.4		$	—	$	—

(1) General and administrative expenses related to our Corporate operations totaled $85.4 million, $80.7 million and $29.6 million for the years ended December 31, 2014, 2013 and 2012.

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 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 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.

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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 $7.7 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 and 2013, 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 discussion 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;

• $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.

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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 CEQP’s general partner), which should be considered in the following discussion of the results of operations of our storage and transportation segment for the year ended December 31, 2014 compared to the year ended December 31, 2013.

EBITDA for our storage and transportation segment increased by approximately $77.5 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. 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 formed joint venture with Brookfield to acquire 100% of the membership interest in Tres Palacios, for total cash consideration of approximately $132.8 million, of which we paid approximately $66.4 million. We own a 50.01% interest in Tres Holdings and we operate the assets of Tres Palacios. Brookfield owns the remaining 49.99% interest in Tres Holdings. For the year ended December 31, 2014, we recorded earnings from our unconsolidated affiliate, Tres Holdings, of approximately $0.2 million, which primarily related to (i) our proportionate share of Tres Holdings’ net income and (ii) the amortization of the excess of our investment balance compared to Tres Holdings’ net assets which was approximately $0.1 million for the years ended December 31, 2014. 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 results were included in our consolidated results of operations beginning June 19, 2013 (the date that Crestwood Holdings acquired control of CEQP’s general partner), which should be considered in the following discussion of the results of operations of our NGL and crude services segment for the year ended December 31, 2014 compared to the year ended December 31, 2013.

Our NGL and crude services segment's EBITDA increased by approximately $71.1 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, higher operations and maintenance expense and goodwill impairments of our Watkins Glen and US Salt reporting units.

Our NGL and Crude Services revenues increased by $1,776.6 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 $1,621.5 million increase in costs of product/services sold and a $51.0 million increase in operations and maintenance expenses, primarily due to our 2014 results having a full year of operations compared to six months in 2013 for Legacy Inergy and two months for Arrow's operations.

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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 $311.9 million, an increase of $133.2 million from 2013 and an increase of $50.9 million for the year ended December 31, 2013 compared to 2012. Our consolidated Adjusted EBITDA for the year ended December 31, 2014 was $442.5 million, an increase of $180.6 million from 2013 and an increase of $127.5 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 $4.7 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 $34.7 million of transaction costs incurred in 2013 primarily related to the Crestwood Merger and Arrow Acquisition. Our general and administrative expenses increased by approximately $51.1 million for the year ended December 31, 2013 compared to 2012 due primarily 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.

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 $0.7 billion of long-term debt due to the Crestwood Merger; and (iv) the issuance of $600 million of 6.125% 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	$	18.1	$	19.5	$	17.6
Senior notes	93.9		49.3		17.8
Capital lease interest	0.1		0.2		0.2
Other debt-related costs	6.8		5.8		0.4
Gross interest and debt expense	118.9		74.8		36.0
Less: capitalized interest	7.5		3.4		0.2
Interest and debt expense, net	$	111.4	$	71.4	$	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 and preferred units. Our operating subsidiaries use cash from their respective operations to fund their operating activities and

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maintenance capital expenditures. We utilize a variety of sources to service our outstanding indebtedness, fund growth capital expenditures, and make distributions to unitholders. These sources include funds cash generated by our operating subsidiaries, borrowings under our Credit Facility, and proceeds from the issuance of preferred and common units. We believe our current liquidity sources and operating cash flows will be sufficient to fund our future operating and capital requirements.

• Credit Facility. As of December 31, 2014, we had $429.9 million of available capacity under the Credit Facility considering our most restrictive debt covenants under the facility. See Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 7 for a more detailed description of our Credit Facility.

• Preferred Units. On June 17, 2014, we entered into definitive agreements with a group of investors under which we have agreed to sell and they 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, we 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). We expect to issue $60.0 million of Preferred Units to the Class A Purchasers before September 30, 2015, and to use the net proceeds from such issuances to fund expansion and development projects, to reduce borrowings under our Credit Facility, and for other general partnership purposes. See Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 10 for a more detailed description of the Preferred Units.

• Equity Distribution Agreement. On July 10, 2014, we entered into an equity distribution agreement with several financial institutions under which we may offer and sell from time to time through one or more managers 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 our ATM registration statement that became effective on May 27, 2014. We will pay the managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under our 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 our Credit Facility, and for other general partnership purposes. We have not issued any common units under this equity distribution program. See Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 10 for more information on our ATM equity distribution program.

As of December 31, 2014, we were in compliance with all our debt covenants related to our Credit Facility and our Senior Notes. See Part IV, Item 15, Exhibits and Financial Statement Schedules, Note 7 for a more detailed description of our Credit Facility and Senior Notes.

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	$	322.9		$	186.5		$	102.1
Net cash used in investing activities	(570.9		)	(1,036.5		)	(616.6		)
Net cash provided by financing activities	249.9			852.6			513.8

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Operating Activities

Our operating cash flows increased approximately $136.4 million during the year ended December 31, 2014 compared to 2013 and increased approximately $84.4 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 $1,906.9 million in 2014 compared to 2013 and $419.1 million in 2013 compared to 2012, partially offset by (i) higher costs of products/services sold, operations and maintenance expenses and general and administrative expenses of approximately $1,712.2 million in 2014 compared to 2013 and $338.0 million in 2013 compared to 2012 and (iii) a decrease in cash associated with net changes in working capital of approximately $19.3 million in 2014 compared to 2013 and an increase in cash associated with net changes in working capital of approximately $20.6 million in 2013 compared to 2012. In addition, our interest paid increased approximately $40.2 million during the year ended December 31, 2014 compared to 2013 and approximately $28.8 million during the year ended December 31, 2013 compared to 2012, due to higher outstanding balances on our credit facility.

Investing Activities

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

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

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

The following table summarizes our capital expenditures for the year ended December 31, 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	$	320.3
Maintenance capital	20.3
Other(1)	66.4
Purchases of property, plant and equipment	407.0
Reimbursements of property, plant and equipment	21.5
Net purchases of property, plant and equipment	$	385.5

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

During 2015, we anticipate growth capital expenditures of approximately $115 million to $125 million, which includes contributions to our equity investments related to their capital projects. In addition, we expect to spend between approximately $22 million to $25 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 through a combination of additional capital market transactions, borrowings under our credit facility, proceeds from issuance of preferred units, sale of common units and operating cash flows.

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

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Acquisitions. During the years ended December 31, 2014, 2013 and 2012, we paid approximately $19.5 million, $561.5 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. In December 2014, we acquired a 50.01% interest in Tres Palacios from Crestwood Equity for approximately $66.4 million, which represents the fair value of the net assets of Tres Palacios. The acquisition of our 50.01% interest in Tres Palacios was considered a transaction between entities under common control, and as a result, we recorded our investment at Crestwood Equity's historical cost of approximately $35.8 million. We reflected the difference between Crestwood Equity's historical basis in the Tres Palacios assets and the consideration paid by us in excess of Crestwood Equity's basis as a distribution to general partner. 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.

Financing Activities

Significant items impacting our financing activities during the three years ended December 31, 2014, 2013 and 2012 included the following:

Equity Transactions

• $107.6 million increase in distributions to partners in 2014 compared to 2013, and $127.2 million increase in 2013 compared to 2012;

• $30.6 million distribution to Crestwood Equity, which represents the difference between the cash paid to acquire our 50.01% interest in Tres Holdings and Crestwood Equity's historical basis in the Tres Palacios assets (see Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 6 for a further discussion of this transaction);

• $430.5 million net proceeds from the issuances of 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;

• $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 Legacy Inergy 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

• $298.4 million decrease in net borrowings of long-term debt from $438.5 million in 2013 to $140.1 million in 2014, primarily due to liquidity obtained through equity issuances and $265.8 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.

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Contractual Obligations

We are party to various contractual obligations. A portion of these obligations are reflected in our financial statements, such as long-term debt and other accrued liabilities, while other obligations, such as operating leases, capital commitments and contractual interest amounts are not reflected on our balance sheet. The following table and discussion summarizes our contractual cash obligations as of December 31, 2014 (in millions):

	Less than 1 Year		1-3 Years		3-5 Years		Thereafter		Total
Long-term debt:
Principal	$	0.7	$	1.4	$	906.4	$	1,100.0	$	2,008.5
Interest(1)	109.9		215.0		177.6		108.4		610.9
Future minimum payments under operating leases(2)	6.6		11.2		9.4		16.3		43.5
Future minimum payments under capital leases(2)	1.4		1.3		0.2		—		2.9
Asset retirement obligations	—		—		—		22.0		22.0
Standby letters of credit	15.1		—		—		—		15.1
Growth capital-related purchase commitments and other contractual obligations(3)	30.9		—		—		—		30.9
Total contractual obligations	$	164.6	$	228.9	$	1,093.6	$	1,246.7	$	2,733.8

(1) $555.0 million of our long-term debt is variable interest rate debt at prime rate or LIBOR plus an applicable spread. These rates plus their applicable spreads were between 2.66% and 4.75% 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 12 for a further discussion of these obligations.

(3) Includes identified growth projects primarily related to 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.

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):

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Reporting Segment and Unit	Goodwill
G&P
Marcellus	$	8.6
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
US Salt	12.6
Watkins Glen	66.2
Crude Transportation	3.2
Total	$	1,632.6

(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.

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.

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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 Services 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.

Long-Lived Assets

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

We 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 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 in 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

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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 $11.6 million and $1.6 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 $1,455.0 million and $1,415.4 million, respectively. As of December 31, 2013, the carrying value and fair value of our fixed rate debt instruments was approximately $1,455.9 million and $1,510.4 million, respectively. For a further discussion of our fixed rate debt, see Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 7.

As of December 31, 2014, we had a $1.0 billion revolving credit facility subject to the risk of loss associated with changes in interest rates. At December 31, 2014, we had obligations totaling $555.0 million under our revolving credit facility. These obligations expose us to the risk of increased interest payments in the event of increases in short-term interest rates. We may hedge portions of our borrowings under our revolver from time to time; however, we did not have any hedging instruments as of December 31, 2014. 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 revolver were to fluctuate by 1% from the rate as of December 31, 2014, our annual interest expense would have changed by a total of $5.6 million.

Commodity Price, Market and Credit Risk

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

Market Risk

We typically do not take title to the natural gas, NGLs or crude oil that we gather, store, or transport for our customers. However, we do take title to (i) 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 from third party producers for our proprietary 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) and line fill that we purchase for our crude oil transportation commitments (NGL and crude oil 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. 

During the third quarter of 2014, we entered into daily and short-term forward crude purchase and sale agreements in our NGL and crude services segment related to available capacity on our crude contracts and facilities for our operations located in the Bakken and PRB Niobrara Shale plays. We entered into such contracts to reduce the effect of price volatility on our product costs and protect the value of our inventory positions. We attempt to balance our contractual portfolio by purchasing volumes only when we have a matching purchase commitment from our marketing customers. As of December 31, 2014, our outstanding positions related to these activities were not material.

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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 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.

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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 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 Midstream Partners LP

Crestwood Midstream GP LLC, our general partner, manages our operations and activities on our behalf through its directors and officers. Our general partner is not elected by our common unitholders and will not be subject to re-election in the future. Directors of our general partner oversee our operations. Common unitholders are not entitled to elect the directors of our general partner, which are appointed by Crestwood Midstream Holdings LP, which is the sole member of our general partner and is controlled by CEQP. Similarly, our unitholders are limited partners and do not or participate, directly or indirectly, in our management or operations. The board of directors of our general partner, which we refer to as “our board of directors” or “our board,” is presently composed of eight directors.

The officers of our general partner, which we refer to as “our officers,” manage the day-to-day affairs of our business. All of our officers are employed by Crestwood Operations LLC, a wholly-owned subsidiary of CEQP. Certain of our officers devote the majority of their time to our business, while other officers have responsibilities for both us and CEQP and devote less than a majority of their time to our business. We also utilize employees of Crestwood Operations LLC to operate our business and provide us with administrative services.

Neither our general partner nor CEQP receives any management fee or other compensation in connection with our general partner’s management of our business. However, prior to making any distributions on our common units, we are obligated to reimburse our general partner and its affiliates, including CEQP, for all expenses they incur and payments they make on our behalf. We have entered into an omnibus agreement with CEQP and its general partner, pursuant to which we agreed upon certain aspects of our relationship with them, including the provision by CEQP to us of certain administrative services and employees and our agreement to reimburse CEQP’s general partner for the cost of such services and employees.

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
Philip D. Gettig	69	Director
Warren H. Gfeller	62	Director
David Lumpkins	60	Director
John J. Sherman	59	Director
David M. Wood	57	Director

(1) On January 16, 2015, Michael J. Campbell resigned as Chief Financial Officer of our general partner and CEQP's general partner, effective as of March 31, 2015. On January 20, 2015, the board of directors of general partner and CEQP's 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 CEQP’s general partner in June 2013. He served as Chairman, President and Chief Executive Officer 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

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Partners L.P. from September 2004 until February 2005. Mr. Phillips also served on the Board of Directors of Enterprise GP Holdings L.P., the general partner of Enterprise Products Partners L.P., from February 2006 until April 2007. He previously served as Chairman of the Board and CEO of GulfTerra Energy Partners, L.P. (GTM), from 1999-2004, prior to GTM's merger with Enterprise Product Partners, LP, and held senior executive management positions with El Paso Corporation, including President of El Paso Field Services from 1996-2004. Prior to that he was Chairman, President and CEO of Eastex Energy, Inc. from 1981-1995. Mr. Phillips previously served as a Director of Pride International, Inc. from October 2007 to May 31, 2011, one of the world’s largest offshore drilling 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 CEQP’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 CEQP’s general partner in October 2013. He served as President - Inergy Services from November 2011 until 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. Campbellhas served as the Senior Vice President - Chief Financial Officer of our general partner and CEQP’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 and CEQP's general partner, effective as of March 31, 2015.

Steven M. Dougherty was appointed Senior Vice President, Chief Accounting Officer of our general partner and CEQP’s general partner in October 2013. He served as Senior Vice President, Interim Chief Financial Officer and Chief Accounting Officer of 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 CEQP’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 CEQP’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 CEQP’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

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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 CEQP’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 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 CEQP’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.

Philip D. Gettig was appointed as a director of our general partner in June 2013. He served as a director of Legacy Crestwood from July 2007 to October 2013. From February 2000 to December 2005, Mr. Gettig served as the Vice President, General Counsel and Secretary of Prism Gas Systems I, L.P. (“Prism”), a natural gas gathering and processing company that was purchased by Martin Midstream Partners L.P., a publicly-traded limited partnership, in November 2005. From 1981 to 1999, Mr. Gettig held various positions in the law department of Union Pacific Resources Company (UPR), a publicly-traded exploration and production company with substantial natural gas gathering, processing and marketing operations. Positions held by Mr. Gettig included Managing Senior Counsel from 1996 to 1999. Mr. Gettig also served as General Counsel of Union Pacific Fuels, Inc., UPR’s wholly-owned gathering, processing and marketing affiliate, from 1996 to 1999. Since retiring from Prism in 2005, he has provided consulting and legal counsel to Prism and he has also provided such services to individuals and small businesses. Mr. Gettig was selected to serve as a director of our general partner because he has over 30 years of legal experience within the oil and gas industry.

Warren H. Gfellerhas 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.

David Lumpkins was appointed as a member of our general partner’s board of directors in October 2013.He served as the Executive Chairman of the board of PetroLogistics GP LLC, the general partner of PetroLogistics LP. prior to its acquisition by Flint Hills Resources LLC in July 2014. Mr. Lumpkins has been affiliated with the private equity firm Lindsay Goldberg since 2000, during which time he has worked on a number of investment opportunities in the petrochemical and energy mid-stream industries. Prior to his affiliation with Lindsay Goldberg, Mr. Lumpkins worked in the investment banking industry for 17 years principally for Morgan Stanley and Credit Suisse. In 1995, Mr. Lumpkins opened Morgan Stanley’s Houston office and served as head of the firm’s southwest region. Mr. Lumpkins currently serves on the board of directors of Westlake Chemical Partners GP LLC. He is a graduate of the University of Texas where he also received his MBA. Mr. Lumpkins’ extensive experience in the petrochemical, energy midstream and finance industries adds significant value to the board of directors of our general partner.

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John J. Shermanhas 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.

David M. Wood was appointed as a director of our general partner and CEQP’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, Philip Gettig and David Lumpkins 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, Philip Gettig and David Lumpkins. Our board has determined that each of the members of our audit committee meets 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 Philip Gettig and David Lumpkins. 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 David Lumpkins.

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 we operate, 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.

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.

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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. Except for a one day late Form 4 filing for John Sherman reporting the sale of 30,000 CMLP units, 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 other 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

All of our executive officers and other personnel necessary for the management of our business are employed and compensated by a subsidiary of Crestwood Equity Partners LP, subject to our reimbursement for services provided to us.

Responsibility and authority for cash compensation-related decisions for our executive officers resides with the compensation committee of the board of directors of Crestwood Equity GP LLC. Our executive officers manage our business as part of the service provided by Crestwood Equity Partners LP under the omnibus agreement, and the cash compensation for all of our executive officers is partially and indirectly paid by us through reimbursement to Crestwood Equity Partners LP. The compensation committee of the board of directors of our general partner is responsible for the administration of our long-term incentive plan and for compensation of our general partner’s non-employee directors.

Certain of our officers devote the majority of their time to our business, while other officers have responsibilities for both us and Crestwood Equity Partners LP and devote less than a majority of their time to our business. Because the officers of our general partner are employees of a subsidiary of Crestwood Equity Partners LP, cash compensation is paid by Crestwood Equity Partners LP and we reimburse Crestwood Equity Partners LP in exchange for the employees’ services provided to us. The officers of our general partner, as well as the employees of Crestwood Equity Partners LP who provide services to us, may participate in employee benefit plans and arrangements sponsored by Crestwood Equity Partners LP and its subsidiaries including plans that may be established in the future.

Compensation Philosophy and Objectives

We do not directly employ any of the persons responsible for managing our business. Our general partner manages our operations and activities, and its board of directors and executive officers will make decisions on our behalf and we have no control over such costs. All of our executive officers also serve as executive officers of Crestwood Equity Partners LP or one of its subsidiaries. We are only responsible for the reimbursement that we pay to Crestwood Equity Partners LP pursuant to the omnibus agreement. However, from time to time the shared executives may receive awards of equity in us pursuant to our long-term incentive plan and we will bear the costs of the awards granted under our long-term incentive plan.

Additional Information

A full discussion of the compensation programs for Crestwood Equity Partners LP’s executive officers and the policies and philosophy of the compensation committee of the board of directors of Crestwood Equity GP LLC is set forth in Crestwood Equity Partners LP’s annual report on Form 10-K under the heading “Executive Compensation.” Specifically, compensation paid directly by us through our long-term incentive plan or indirectly by us through reimbursement pursuant to the Omnibus Agreement is included in the amounts set forth in certain of the tables set forth in Item 11 of Crestwood Equity Partners LP annual report on Form 10-K, with awards outstanding pursuant to our long-term incentive plan separately identified.

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Crestwood Midstream Partners LP Long Term Incentive Plan

Our general partner sponsors the Crestwood Midstream Partners LP Long Term Incentive Plan for its directors, consultants and employees and the employees and consultants of its affiliates who perform services for it. The plan is administered by the compensation committee of our general partner’s board of directors.

Restricted Units

The Crestwood Midstream Partners LP Long Term Incentive Plan currently permits, and our general partner has made, grants of restricted units. Restricted units are subject to a restricted period the terms of which are set forth in a restricted unit award agreement. In general, restricted units vest over a three year period. The individual award agreement also sets forth the conditions under which the restricted units may become vested or forfeited, which may include, without limitation, the accelerated vesting upon termination without cause, change in control, the achievement of specified performance goals, or the forfeiture for failing to achieve specified performance goals and such other terms and conditions as the committee may establish. Unless otherwise specifically provided for in an award agreement, distributions are paid to the holder of the restricted units without restriction. Restricted units are designed to furnish additional compensation to employees and directors and to align their economic interests with those of common unitholders. Grants of restricted units pursuant to the Crestwood Midstream Partners LP Long Term Incentive Plan are reflected in the tables contained in Crestwood Equity Partners LP’s annual report on Form 10-K under the heading “Executive Compensation.”

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

Director Compensation Tables

The following table sets forth the cash and non-cash compensation by each person who served as a non-employee director of our general partner during Fiscal 2014.

Name	Fees Earned or Paid in Cash ($)	Unit Awards ($)(1)	Total ($)
Alvin Bledsoe	80,000	79,257	159,257
Michael France	60,000	79,257	139,257
Philip Gettig	100,000	79,257	179,257
Warren Gfeller	80,000	79,257	159,257
David Lumpkins	90,000	79,257	169,257
John Sherman	60,000	79,257	139,257
David Wood	70,000	79,257	149,257

(1) Reflects the value of restricted unit awards, calculated in accordance with ASC 718, disregarding estimated forfeitures. See Part IV, Item 15, Exhibits, Financial Statement Schedules, Note 11 to our consolidated financial statements for the fiscal year ending December 31, 2014 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 ratably over a three year period beginning one year from the grant date. As of December 31 2014, Messrs. Bledsoe, France, Gettig, Lumpkins, Sherman and Wood each held 4,127 restricted units and Mr. Gfeller held 4,878 restricted units.

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Compensation of Directors

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 Crestwood Equity Partners GP LLC, 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

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 common units by:

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

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

• each of the directors of our general partner; and

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

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

Name of Beneficial Owner(1)	Common Units Beneficially Owned	Percentage of Common Units Beneficially Owned		Class A Preferred Units Beneficially Owned	Percentage of Class A Preferred Units Beneficially Owned
Magnetar Financial LLC(2)	—	—		10,266,029	56.0	%
GSO COF II Holdings Partners LP(3)	—	—		7,332,878	40.0	%
Crestwood Holdings Partners LLC(4)(6)	27,995,823	14.9	%	—	—
Crestwood Gas Services Holdings LLC(5)(7)	18,339,314	9.7	%	—	—
Crestwood Holdings LLC(6)(8)	2,497,071	*		—	—
Crestwood Equity Partners LP(7)(8)	7,159,438	3.8%		—	—
Crestwood Gas Services GP LLC	21,597	*		—	—
Kayne Anderson Capital Advisors, L.P.(9)	19,490,644	10.4	%	—	—
Neuberger Berman Group LLC (10)	19,866,291	10.5	%	—	—
Oppenheimer Funds, Inc.(11)	13,632,073	7.3	%	—	—
ALPS Advisors, Inc.(12)	9,546,176	5.0	%	—	—
Alvin Bledsoe	76,602	*		—	—
Michael J. Campbell	63,781	*		—	—
J. Heath Deneke	45,591	*		—	—
Steven M. Dougherty	47,028	*		—	—
Michael G. France	16,652	*		—	—
William C. Gautreaux	1,242,733	*		—	—
Philip D. Gettig	34,493	*		—	—
Warren H. Gfeller	73,562	*		—	—
Joel C. Lambert	30,361	*		—	—
David Lumpkins	49,397	*		—	—
William H. Moore	47,644	*		—	—
Joel D. Moxley	19,891	*		—	—
Robert G. Phillips	149,059	*		—	—
John J. Sherman	4,882,587	2.6	%	—	—
David M. Wood	9,397	*		—	—
Directors and executive officers as a group (15 persons)	6,788,778	3.6	%	—	—

* 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.

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(2) Class A Units are held in various Magnetar funds and managed accounts as follows: MTP Energy Master Fund Ltd. (4,583,052), MTP Energy CM LLC (2,310,700), MTP Energy Opportunities Fund LLC (1,099,930), Magnetar Structured Credit Fund, LP (454,936), Magnetar Constellation Fund IV LLC (379,842), Compass HTV LLC (364,036), Magnetar Capital Fund II LP (311,379), Blackwell Partners LLC (227,228), Magnetar Global Event Driven Fund LLC (226,380), Magnetar Andromeda Select Fund LLC (183,316), Hipparchus Fund LP (73,749) and Spectrum Opportunities Fund LP (51,481). The address for Magnetar Financial LLC is 1603 Orrington Avenue, 13^th Floor, Evanston, IL 60201.

(3) Mailing address for GSO COF Holdings Partners LP is 345 Park Avenue, 31^st Floor, New York, NY 10154.

(4) 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.

(5) Crestwood Gas Services Holdings LLC, an indirect wholly owned subsidiary of Crestwood Holdings, owns a 100% interest in our General Partner and a 9.8% limited partner interest in us.

(6) Crestwood Holdings LLC is an indirect wholly owned subsidiary of Crestwood Holdings.

(7) Crestwood Holdings owns an indirect 28.9% limited partner unit interest in Crestwood Equity Partners LP , including the ownership of 4,387,889 subordinated units. Crestwood Holdings indirectly owns the sole general partner Crestwood Equity Partners LP.

(8) 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 27,995,823 common units of Crestwood Midstream Partners LP. Crestwood Midstream Holdings LP owns the sole general partner of CMLP and incentive distribution rights (which represent the right to receive increasing percentages of quarterly distributions in excess of specified amounts) in us.

(9) According to a Schedule 13G/A filed by Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne with the SEC on January 10, 2014, Kayne Anderson Capital Advisors, L.P. together with Richard A. Kayne have shared voting and dispositive power over 19,490,644 common units. The reported units are owned by investment accounts (investment limited partnerships, a registered investment company and institutional accounts) managed, with discretion to purchase or sell securities, by Kayne Anderson Capital Advisors, L.P., as a registered investment adviser. Kayne Anderson Capital Advisors, L.P. is the general partner (or general partner of the general partner) of the limited partnerships and investment adviser to the other accounts. Richard A. Kayne is the controlling shareholder of the corporate owner of Kayne Anderson Investment Management, Inc., the general partner of Kayne Anderson Capital Advisors, L.P. Mr. Kayne is also a limited partner of each of the limited partnerships and a shareholder of the registered investment company. Kayne Anderson Capital Advisors, L.P. disclaims beneficial ownership of the units reported, except those units attributable to it by virtue of its general partner interests in the limited partnerships. Mr. Kayne disclaims beneficial ownership of the units reported, except those units held by him or attributable to him by virtue of his limited partnership interests in the limited partnerships, his indirect interest in the interest of Kayne Anderson Capital Advisors, L.P. in the limited partnerships, and his ownership of common stock of the registered investment company. The address of Kayne Anderson Capital Advisors, L.P. and Richard A. Kayne is 1800 Avenue of the Stars, Third Floor, Los Angeles, California 90067.

(10) According to a Schedule 13G/A filed by Neuberger Berman Group LLC, with the SEC on February 9, 2015, Neuberger Berman Group LLC has shared voting power over 19,250,109 common units and shared dispositive power over 19,866,291 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.

(11) According to a Schedule 13G/A filed by Oppenheimer Funds, Inc., with the SEC on February 4, 2015, Oppenheimer Funds, Inc. has shared voting power over 13,632,073 common units and dispositive power over 13,632,073 common units. The address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, New York. Oppenheimer Funds, Inc. disclaims beneficial ownership of these units.

(12) According to a Schedule 13G filed by ALPS Advisors, Inc.., with the SEC on February 17, 2015, ALPS Advisors, Inc. has shared voting power and dispositive over 9,546,176 common units. The address of ALPS Advisors, Inc. is 1290 Broadway, Suite 1100, Denver, Colorado 80203. ALPS Advisors, Inc. disclaims beneficial ownership of these units.

See Item 5 of this report for certain information regarding securities authorized for issuance under equity compensation plans.

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

For a discussion of director independence, see Item 10, Directors, Executive Officers and Corporate Governance.

Our general partner (Crestwood Midstream GP LLC) owns a non-economic general partner interest in us. The sole member of our general partner, Crestwood Midstream Holdings LP, owns all of our IDRs.

Distributions and Payments to Our General Partner and Its Affiliates

The table below summarizes the distributions and payments made or to be made by us to our general partner and its affiliates in connection with our ongoing operations. These distributions and payments were determined by and among affiliated entities.

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Distributions of available cash to our general partner and its affiliates	Assuming we make in-kind distributions on our Class A Preferred Units until the first quarter following the quarter ending June 30, 2017, we will generally make cash distributions 100% to our common unitholders, until each common unit has received the initial quarterly distribution of $0.37. Our general partner will not receive cash distributions on its non-economic general partner interest. If distributions exceed the initial quarterly distribution of $0.37 per unit, CEQP will be entitled to 50% of our cash distributions above the initial quarterly distribution level in respect of its IDRs.
	In 2014, we made approximately $11.7 million of distributions to our general partner and its affiliates as holders of our common units. In 2014, we also paid approximately $30.1 million to our general partner in respect of the IDRs.
Payments to our general partner and its affiliates	Neither our general partner nor CEQP will receive any management fee or other compensation for the management of our business. However, prior to making any distribution on our common units, we will reimburse our general partner and its affiliates, including CEQP, for all direct and indirect expenses incurred on our behalf, which were approximately $105.6 million in 2014 (including $48.9 million in reimbursements of direct personnel related expenses). Our partnership agreement provides that our general partner will determine in good faith the expenses that are allocable to us.
Withdrawal or removal of our general partner	If our general partner withdraws or is removed, its general partner interest will either be sold to the new general partner for cash or converted into common units, in each case for an amount equal to the fair market value of those interests.

Omnibus Agreement

We have entered into an omnibus agreement with our general partner, CEQP and its general partner that governs certain aspects of our relationship with them, including:

• the provision by CEQP to us of certain administrative services and our agreement to reimburse CEQP for such services;

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

• certain indemnification obligations.

CEQP’s indemnification obligations to us includes certain liabilities relating to:

• the ownership and operation of our assets prior to our initial public offering (IPO), provided that amounts are only payable to us after our liabilities have exceeded $100,000 and then only for such amounts in excess of $100,000; and

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

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

Our indemnification obligations to CEQP, its general partner and their affiliates (other than our general partner, us and our subsidiaries) includes certain liabilities relating to:

• certain environmental liabilities attributable to the ownership and operation of our assets, but only to the extent the violations, events, omissions or conditions giving rise to such covered environmental liabilities occur after the closing of our 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

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

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

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

• our agreement to reimburse CEQP for all expenses it incurs as a result of us being a publicly traded partnership; and

• our agreement to reimburse CEQP for all expenses that it incurs or payments it makes on our behalf with respect to insurance coverage for our business.

Neither our partnership agreement nor the omnibus agreement will limit the amount of expenses for which our general partner and its affiliates may be reimbursed. However, we expect these services to be provided at cost.

Except for the indemnification provisions, the omnibus agreement may be terminated by CEQP with 180 days’ prior written notice if (i) Crestwood Midstream GP LLC is removed as our general partner under circumstances where “cause” does not exist and the common units held by CEQP and its affiliates were not voted in favor of such removal; (ii) a change of control of CEQP occurs; or (iii) a change of control of us occurs. Except for the indemnification provisions, we may terminate the omnibus agreement with 180 days’ prior written notice if a change of control of CEQP occurs.

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

Tax Sharing Agreement

We have entered into a tax sharing agreement with CEQP pursuant to which we will reimburse CEQP for our share of state and local income and other taxes borne by CEQP as a result of our income being included in a combined or consolidated tax return filed by CEQP with respect to taxable periods including or beginning on the closing date of our IPO. The amount of any such reimbursement will be limited to the tax that we (and our subsidiaries) would have paid had we not been included in a combined group with CEQP. CEQP may use its tax attributes to cause its combined or consolidated group, of which we may be a member for this purpose, to owe no tax. However, we would nevertheless reimburse CEQP for the tax we would have owed had the attributes not been available or used for our benefit, even though CEQP 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

We provide firm storage services utilizing 100% of the operationally available storage capacity at our Bath storage facility to an affiliate, Crestwood Services LLC, 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, we will provide firm storage services utilizing 100% of the operationally available storage capacity at our proposed Watkins Glen NGL storage facility to Crestwood Services under a five-year contract expiring March 31, 2016, subject to Crestwood Services' renewal rights.  All revenue generated by Crestwood Services from subleasing storage capacity to third parties at the storage facility will be paid to us 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, Tres Palacios Holdings LLC (Tres Holdings), the newly formed joint venture between us and and affiliate of Brookfield Infrastructure Group (Brookfield) completed the acquisition of Tres Palacios Gas Storage LLC (Tres Palacios) from CEQP for total cash consideration of approximately $132.8 million, of which we paid $66.4 million. We own 50.01% of Tres Holdings and are the operator of Tres Palacios and its assets. The terms of the transaction were unanimously

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approved by the board of directors of our general partner and CEQP'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

Although we do not have any formal policy for the review of related party transactions, the Audit Committee would review and approve all transactions or series of related financial transactions, arrangements or relationships between our partnership and any related party, including those that involve an amount that exceeds $120,000.

In addition, pursuant to our Code of Business Conduct and Ethics, our directors and officers are expected to bring to the attention of our Compliance Officer any conflict or potential conflict of interest. If a conflict or potential conflict of interest arises between our partnership and our general partner, the resolution of any such conflict or potential conflict should be addressed by the board in accordance with the provisions of our partnership agreement. At the discretion of the board in light of the circumstances, the resolution may be determined by the board in its entirety or by a conflicts committee meeting the definitional requirements for such a committee under our partnership agreement.

Item 14. Principal Accountant Fees and Services.

Effective as of October 7, 2013, the Audit Committee of the Board (the Board) of Directors of Crestwood Midstream GP LLC dismissed Deloitte & Touche LLP (Deloitte) as the independent registered public accounting firm of Legacy Crestwood 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. Legacy Crestwood is the accounting predecessor to the partnership and its financial statements now constitute the primary financial statements of the partnership.

The audit report on the financial statements of Legacy Crestwood 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’s two most recent fiscal years ended December 31, 2012 and December 31, 2011 and the subsequent interim period through October 6, 2013, (1) there were no disagreements between Legacy Crestwood 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’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’s fiscal years ended December 31, 2012 and 2011 and the subsequent interim period ending October 6, 2013, Legacy Crestwood did not consult E&Y in regards to Legacy Crestwood’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’s financial statements or might be rendered on Legacy Crestwood’s financial statements. During such fiscal years and subsequent interim period ending October 6, 2013, Legacy Crestwood did not consult with E&Y in regards to Legacy Crestwood’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.

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The following table presents fees billed for professional audit services rendered for the audit of our 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)	$	2.3	$	2.8	$	1.1

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

3. Exhibits:

Exhibit Number	Description
2.1	Agreement and Plan of Merger, dated as of October 8, 2013 by and among Crestwood Midstream Partners LP, Crestwood Arrow Acquisition LLC, Arrow Midstream Holdings, LLC,  the Members, and OZ Midstream Holdings, LLC (incorporated herein by reference to Exhibit 10.2 to Crestwood Midstream Partner LP’s Form 10-Q filed on November 8, 2013)
2.2	Agreement and Plan of Merger, dated as of 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 2.1 to Inergy Midstream, L.P.’s Form 8-K filed on May 9, 2013)
2.3	Agreement and Plan of Merger, dated as of October 8, 2013 by and among Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (the “Partnership”), Crestwood Arrow Acquisition LLC, Arrow Midstream Holdings, LLC,  Legion Energy, LLC and OZ Midstream Holdings, LLC (incorporated herein by reference to Exhibit 10.2 to the Partnership’s Form 10-Q filed on November 8, 2013)
3.1	Certificate of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.4 to Inergy Midstream, L.P.'s Form S-1/A filed on November 21, 2011)
3.2	Amendment to the Certificate of Limited Partnership of Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.2 to the Partnership’s Form 8-K filed on October 10, 2013)
3.3	First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P., dated December 21, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)
3.4	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy Midstream, L.P.’s Form 8-K filed on October 1, 2013)
3.5	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.1 to the Partnership’s Form 8-K filed on October 10, 2013)
3.6	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP dated as of June 17, 2014 (incorporated herein by reference to Exhibit 3.1 to the Partnership's Form 8-K filed on June 19, 2014)
3.7	Certificate of Formation of NRGM GP, LLC (incorporated herein by reference to Exhibit 3.7 to Inergy Midstream, L.P.'s Form S-1/A filed on November 21, 2011)
3.8	Certificate of Amendment of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.37 to the Partnership’s Form S-4 filed on October 28, 2013)
3.9	Amended and Restated Limited Liability Company Agreement of NRGM GP, LLC, dated December 21, 2011 (incorporated herein by reference to Exhibit 3.2 to Inergy Midstream, L.P.'s Form 8-K filed on December 22, 2011)

85

Exhibit Number	Description
3.10	Amendment No. 1 to the Amended and Restated Limited Liability Company Agreement of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.39 to the Partnership’s Form S-4 filed on October 28, 2013)
4.1	Indenture, dated December 7, 2012, by and among Inergy Midstream, L.P., NRGM Finance Corp., the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to Inergy Midstream, L.P.’s Form 8-K filed on December 13, 2012)
4.2	Form of 6.0% Senior Notes due 2020 (incorporated herein by reference to Exhibit 4.2 to Inergy Midstream, L.P.'s Form 8-K filed on December 13, 2012)
4.3	Registration Rights Agreement, dated December 7, 2012, by and among Inergy Midstream, L.P., NRGM Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.3 to Inergy Midstream, L.P.’s Form 8-K filed on December 13, 2012)
4.4	First Supplemental Indenture, dated January 18, 2013, by and among Inergy Midstream, L.P., NRGM Finance Corp., the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.4 to Inergy Midstream, L.P.’s Form 10-Q filed on February 6, 2013)
4.5	Second Supplemental Indenture, dated May 22, 2013, by and among Inergy Midstream, L.P., NRGM Finance Corp., the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.1 to Inergy Midstream, L.P.’s Form 8-K filed on May 29, 2013)
4.6	Third Supplemental Indenture, dated October 7, 2013, by and among Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.), Crestwood Midstream Finance Corp. (f/k/a NRGM Finance Corp.), the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.2 to the Partnership’s Form 8-K filed on October 10, 2013)
4.7	Fourth Supplemental Indenture, dated November 8, 2013, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.2 to the Partnership’s Form 8-K filed on November 12, 2013)
4.8	Indenture, dated November 8, 2013, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the Guarantors named therein and U.S. National Bank Association (incorporated herein by reference to Exhibit 4.1 to the Partnership’s Form 8-K filed on November 12, 2013)
4.9	Registration Rights Agreement, dated November 8, 2013, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the Guarantors named therein and the Initial Purchasers named therein (incorporated herein by reference to Exhibit 4.4 to the Partnership’s Form 8-K filed on November 12, 2013)
4.10	Indenture, dated April 1, 2011, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 8-K filed on April 5, 2011)
4.11	Supplemental Indenture No. 1, dated November 29, 2011 to Indenture dated April 1, 2011, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.3 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2011, filed on March 1, 2012)
4.12	Supplemental Indenture No. 2, dated January 6, 2012 to Indenture dated April 1, 2011, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.4 to the Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2011, filed on March 1, 2012)
4.13	Supplemental Indenture No. 3, dated March 22, 2012, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 10-Q for the quarter ended March 31, 2012, filed on May 9, 2012)

86

Exhibit Number	Description
4.14	Supplemental Indenture No. 4, dated April 11, 2013, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A., as trustee (incorporated herein by reference to Exhibit 4.5 to Crestwood Midstream Partners LP’s Form S-4/A filed on April 30, 2013)
4.15	Supplemental Indenture No. 5, dated October 7, 2013, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.), Crestwood Midstream Finance Corp. (f/k/a NRGM Finance Corp.), the Guarantors named therein and The Bank of New York Mellon Trust Company, N.A, (incorporated herein by reference to Exhibit 4.1 the Partnership’s Form 8-K filed on October 10, 2013)
4.16	Supplemental Indenture No. 6, dated November 8, 2013, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the Guarantors party thereto and The Bank of New York Mellon Trust Company, N.A. (incorporated herein by reference to Exhibit 4.3 to the Partnership’s Form 8-K filed on November 12, 2013)
4.17	Registration Rights Agreement, dated April 1, 2011, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, the Guarantors named therein and UBS Securities LLC, BNP Paribas Securities Corp., RBC Capital Markets, LLC and RBS Securities Inc., as the initial purchasers (incorporated by reference to Exhibit 4.3 to Crestwood Midstream Partners LP’s Form 8-K file on April 5, 2011)
4.18	Registration Rights Agreement, dated June 19, 2013, by and among Inergy Midstream, L.P., John J. Sherman, Crestwood Holdings LLC and Crestwood Gas Services Holdings LLC (incorporated herein by reference to Exhibit 4.1 to Inergy Midstream, L.P.’s Form 8-K filed on June 19, 2013)
4.19	Registration Rights Agreement, dated as of June 17, 2014, by and among Crestwood Midstream Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 4.1 to the Partnership's Form 8-K filed on June 19, 2014)
10.1	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 herein by reference to Exhibit 10.1 to Inergy Midstream, L.P.'s Form 8-K filed on December 22, 2011)
10.2	Omnibus Agreement, dated December 21, 2011, by and among Inergy GP, LLC, Inergy, L.P., NRGM GP, LLC and Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 10.2 to Inergy Midstream, L.P.'s Form 8-K filed on December 22, 2011)
*10.3	Inergy Midstream, L.P. Long-Term Incentive Plan, adopted as of December 21, 2011 (incorporated herein by reference to Exhibit 4.3 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)
*10.4	Form of Inergy Midstream, L.P. Long-Term Incentive Plan Restricted Unit Award Agreement (incorporated herein by reference to Exhibit 4.4 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)
*10.5	Form of Inergy Midstream, L.P. Long-Term Incentive Plan Amendment to Restricted Unit Award Agreements (incorporated herein by reference to Exhibit 10.3 to Inergy Midstream, L.P.’s Form 8-K filed on May 9, 2013)
*10.6	Inergy Midstream, L.P. Employee Unit Purchase Plan, adopted as of December 21, 2011 (incorporated herein by reference to Exhibit 4.5 to Inergy Midstream, L.P.'s Form S-8 filed on December 21, 2011)
10.7	Tax Sharing Agreement, dated December 21, 2011, by and among Inergy, L.P. and Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 10.6 to Inergy Midstream, L.P.'s Form 8-K filed on December 22, 2011)
10.8	Common Unit Purchase Agreement, dated November 3, 2012, between Inergy Midstream, L.P. and the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to Inergy Midstream, L.P.’s Form 8-K filed on November 5, 2012)
10.9	Registration Rights Agreement, dated December 7, 2012, by and among Inergy Midstream, L.P. and the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to Inergy Midstream, L.P.’s Form 8-K filed on December 13, 2012)

87

Exhibit Number	Description
10.10	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 10.1 to Inergy Midstream, L.P.’s Form 8-K filed on May 9, 2013)
10.11	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 10.2 to Inergy Midstream, L.P.’s Form 8-K filed on May 9, 2013)
10.12	Credit Agreement, dated October 7, 2013, by and among Crestwood Midstream Partners LP, as borrower, the lenders party thereto, and JPMorgan Chase Bank, N.A., as administrative agent (incorporated herein by reference to Exhibit 10.1 to the Partnership’s Form 8-K filed on October 10, 2013)
10.13	Amendment No. 1 dated as of June 11, 2014, to the Credit Agreement dated as of October 7, 2014, among the Partnership, Wells Fargo Bank, as Administrtive Agent, and the lender parties thereto (incorporated herein by reference to Exhibit 10.1 to the Partnership's Form 10-Q filed on August 7, 2014
10.14	Assignment and Conveyance, effective April 30, 2007, between Cowtown Pipeline Partners L.P. and Cowtown Pipeline L.P. (incorporated herein by reference to Exhibit 10.13 to Form S-1/A of Crestwood Midstream Partners LP, File No. 333-140599, filed on July 30, 2007).
10.15	Form of Assignment between Cowtown Pipeline Partners L.P. and Cowtown Pipeline L.P. (incorporated herein by reference to Exhibit 10.14(a) to Form S-1/A of Crestwood Midstream Partners LP, File No. 333-140599, filed on July 30, 2007)
10.16	Schedule of Assignments, effective April 30, 2007, between Cowtown Pipeline Partners L.P. and Cowtown Pipeline L.P. (incorporated herein by reference to Exhibit 10.14(b) to Form S-1/A of Crestwood Midstream Partners LP, File No. 333-140599, filed on July 30, 2007)
10.17	Subordinated Promissory Note, dated August 10, 2007, made by Quicksilver Gas Services LP payable to the order of Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 10.2 Crestwood Midstream Partners LP’s form 8-K filed on August 16, 2007)
10.18	Omnibus Agreement, dated August 10, 2007, among Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 10.4 to Crestwood Midstream Partners LP’s Form 8-K filed on August 16, 2007)
10.19	Omnibus Agreement, dated October 8, 2010, by and among Crestwood Midstream Partners LP, Crestwood Gas Services GP LLC and Crestwood Holdings Partners, LLC (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on October 13, 2010)
10.20	Extension Agreement, dated December 3, 2008, between Quicksilver Gas Services LP and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 10.8 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2009 filed on March 15, 2010)
10.21	Option, Right of First Refusal, and Waiver in Amendment to Omnibus Agreement and Gas Gathering and Processing Agreement, dated June 9, 2009, among Quicksilver Resources Inc., Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC, Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on June 11, 2009).
10.22	Waiver, dated November 19, 2009, by Quicksilver Gas Services GP LLC (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on November 23, 2009)
10.23	Waiver, dated November 19, 2009, by Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 10.2 to Crestwood Midstream Partners LP’s Form 8-K filed on November 23, 2009)
10.24	Contribution, Conveyance and Assumption Agreement, dated August 10, 2007, by and among Quicksilver Gas Services LP, Quicksilver Gas Services GP LLC, Cowtown Gas Processing L.P., Cowtown Pipeline L.P., Quicksilver Gas Services Holdings LLC, Quicksilver Gas Services Operating GP LLC, Quicksilver Gas Services Operating LLC and the private investors named therein (incorporated herein by reference to Exhibit 10.3 to Crestwood Midstream Partners LP’s Form 8-K filed on August 16, 2007)

88

Exhibit Number	Description
10.25	Sixth Amended and Restated Gas Gathering and Processing Agreement, dated September 1, 2008, among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 10-Q for the quarter ended September 30, 2008 filed on November 6, 2008)
10.26	Second Amendment to the Sixth Amended and Restated Gas Gathering and Processing Agreement, dated as of October 1, 2010, by and among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (incorporated herein by reference to Exhibit 10.16 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2010 filed on February 25, 2011)
10.27	Gas Gathering Agreement, effective December 1, 2009, between Cowtown Pipeline L.P. and Quicksilver Resources Inc. (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on January 8, 2010)
10.28	Amendment to Gas Gathering Agreement, dated as of October 1, 2010, by and between Quicksilver Resources Inc. and Cowtown Pipeline Partners L.P. (incorporated herein by reference to Exhibit 10.18 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2010 filed on February 25, 2011)
10.29	Addendum and Amendment to Gas Gathering and Processing Agreement Mash Unit Lateral, effective as of January 1, 2009, by and among Quicksilver Resources Inc., Cowtown Pipeline Partners L.P. and Cowtown Gas Processing Partners L.P. (incorporated herein by reference to Exhibit 10.15 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2009 filed on March 15, 2010)
10.30	Joint Operating Agreement, dated October 1, 2010, but effective as of July 1, 2010, between Quicksilver Resources Inc., Quicksilver Gas Services LP and Quicksilver Gas Services GP LLC (incorporated herein by reference to Exhibit 10.20 to Crestwood Midstream Partners LP’s Form 10-K for the year ended December 31, 2010 filed on February 25, 2011).
10.31	Guarantee, dated as of February 24, 2012, by Crestwood Holdings LLC and Crestwood Midstream Partners LP, in favor of Antero Resources Appalachian Corporation (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on February 28, 2012)
10.32	Gas Gathering and Compression Agreement, dated as of January 1, 2012, by and between Antero Resources Appalachian Corporation and Crestwood Marcellus Midstream LLC (incorporated herein by reference to Exhibit 10.23 to Crestwood Midstream Partners LP’s Form 10-K filed on February 28, 2013)
10.33	Purchase and Sale Agreement, dated June 21, 2013 by and between RKI Exploration & Production, LLC, Crestwood Niobrara LLC and Crestwood Midstream Partners LP (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed June 24, 2013)
10.34	Amended and Restated Limited Liability Company Agreement of Crestwood Niobrara LLC, dated July 19, 2013 (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on July 22, 2013)
10.35	Class A Preferred Unit Purchase Agreement, dated as of June 17, 2014, by and among Crestwood Midstream Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to the Partnership's Form 8-K filed on June 19, 2014)
10.36	Board Representation and Standstill Agreement, dated as of June 17, 2014, by and among Crestwood Midstream GP LLC, Crestwood Midstream Partners LP and the Purchasers named herein (incorporated herein by reference to Exhibit 10.2 to the Partnership's Form 8-K filed on June 19, 2014)
10.37	Equity Distribution Agreement, dated July 10, 2014, by and among the Partnership, the General Partner and the Managers named therein (incorporated herein by reference to Exhibit 1.1 to the Partnership's Form 8-K filed on July 9, 2014)
**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 the Partnership’s Form 8-K filed on October 10, 2013)
**21.1	List of subsidiaries of Crestwood Midstream Partners LP
**23.1	Consent of Ernst & Young LLP

89

Exhibit Number	Description
**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

*	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.

90

Crestwood Midstream 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	92
Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial Reporting	94
Audited Consolidated Financial Statements:
Consolidated Balance Sheets	95
Consolidated Statements of Operations	96
Consolidated Statements of Partners’ Capital	97
Consolidated Statements of Cash Flows	98
Notes to Consolidated Financial Statements	100

91

Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying consolidated balance sheets of Crestwood Midstream Partners LP (the Company) as of December 31, 2014 and 2013, and the related consolidated statements of operations, partners’ capital and cash flows for each of the years then ended. These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. 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 Midstream Partners LP at December 31, 2014 and 2013, and the consolidated results of its operations and its cash flows for each of the years then ended, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States), Crestwood Midstream 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

92

Report of Independent Registered Public Accounting Firm

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

We have audited the accompanying statements of operations, cash flows, and partners’ capital of Crestwood Midstream Partners LP and subsidiaries (the “Partnership”) for the year ended December 31, 2012. These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on these financial statements 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. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes 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 Midstream Partners LP and subsidiaries for the year ended December 31, 2012, in conformity with accounting principles generally accepted in the United States of America.

The consolidated financial statements give effect to the acquisition of Crestwood Marcellus Midstream LLC by the Partnership on January 8, 2013, which has been accounted for at historical cost as a reorganization of entities under common control as described in Note 10 to the consolidated financial statements.

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 to the consolidated financial statements 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

March 18, 2013

(February 28, 2014 as to Note 8 and Note 14)

93

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

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

We have audited Crestwood Midstream 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 Midstream 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 Midstream 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 Midstream Partners LP and our report dated February 27, 2015 expressed an unqualified opinion thereon.

/s/ Ernst & Young LLP

Houston, Texas

February 27, 2015

94

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED BALANCE SHEETS (in millions, except unit information)
	December 31,
	2014		2013
Assets
Current assets:
Cash	$	4.6	$	2.7
Accounts receivable	241.8		205.1
Inventory (Note 4)	8.0		7.0
Prepaid expenses and other current assets	18.7		10.2
Total current assets	273.1		225.0
Property, plant and equipment (Note 4)	3,883.5		3,565.7
Less: accumulated depreciation and depletion	365.4		215.6
Property, plant and equipment, net	3,518.1		3,350.1
Intangible assets (Note 4)	1,013.2		1,025.1
Less: accumulated amortization	137.0		54.3
Intangible assets, net	876.2		970.8
Goodwill	1,632.6		1,682.8
Investment in unconsolidated affiliates (Note 6)	295.1		151.4
Other assets	1.4		21.7
Total assets	$	6,596.5	$	6,401.8
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	126.1	$	154.5
Accounts payable - related party (Note 13)	6.3		8.7
Accrued expenses and other liabilities (Note 4)	122.0		148.4
Current portion of long-term debt (Note 7)	0.7		2.9
Total current liabilities	255.1		314.5
Long-term debt, less current portion (Note 7)	2,012.8		1,867.9
Other long-term liabilities	31.2		26.3
Commitments and contingencies (Note 12)
Partners’ capital (Note 10):
Class A preferred units (17,917,870 issued and outstanding at December 31, 2014)	447.7		—
Common units (187,965,105 and 187,243,989 issued and outstanding at December 31, 2014 and December 31, 2013)	3,678.0		4,092.1
Total Crestwood Midstream Partners LP partners’ capital	4,125.7		4,092.1
Interest of non-controlling partners in subsidiary	171.7		101.0
Total partners’ capital	4,297.4		4,193.1
Total liabilities and partners’ capital	$	6,596.5	$	6,401.8

See accompanying notes.

95

CRESTWOOD MIDSTREAM 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	179.1			90.1			—
NGL and crude services	2,040.3			270.1			—
Related party (Note 13)	17.6			82.1			113.7
	2,565.5			658.6			239.5
Costs of product/services sold:
Gathering and processing	29.1			24.1			23.8
Storage and transportation	14.3			8.7			—
NGL and crude services	1,851.9			230.4			—
Related party (Note 13)	42.2			32.5			15.2
	1,937.5			295.7			39.0
Expenses:
Operations and maintenance	139.0			73.3			43.1
General and administrative (Note 13)	85.4			80.7			29.6
Depreciation, amortization and accretion	221.7			121.7			51.9
	446.1			275.7			124.6
Other operating income (expense):
Gain (loss) on long-lived assets, net	(33.6		)	5.4			—
Goodwill impairment	(48.8		)	(4.1		)	—
Loss on contingent consideration (Note 12)	(8.6		)	(31.4		)	—
Operating income	90.9			57.1			75.9
Loss from unconsolidated affiliates, net	(0.7		)	(0.1		)	—
Interest and debt expense, net	(111.4		)	(71.4		)	(35.8		)
Income (loss) before income taxes	(21.2		)	(14.4		)	40.1
Provision for income taxes	0.7			0.7			1.2
Net income (loss)	(21.9		)	(15.1		)	38.9
Net (income) loss attributable to non-controlling partners	(16.8		)	(4.9		)	—
Net income (loss) attributable to Crestwood Midstream Partners LP	(38.7		)	(20.0		)	38.9
Net income attributable to Class A preferred units	(17.2		)	—			—
Net income (loss) attributable to partners	$	(55.9	)	$	(20.0	)	$	38.9
General partner's interest in net income	$	30.1		$	26.8		$	22.2
Payment to Legacy Crestwood unitholders	$	—		$	34.9		$	—
Limited partners’ interest in net income (loss)	$	(86.0	)	$	(81.7	)	$	16.7
Net income (loss) per limited partner unit:
Basic	$	(0.46	)	$	(0.82	)	$	0.26
Diluted	$	(0.46	)	$	(0.82	)	$	0.26
Weighted-average limited partners’ units outstanding (in thousands):
Basic	187,942			99,183			64,656
Diluted	187,942			99,183			64,656

See accompanying notes.

96

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (in millions)
	Crestwood Midstream Partners LP
	Class A Preferred Units		Partners			Non-controlling Partners		Total Partners’ Capital
Balance at December 31, 2011	$	—	$	455.6		$	—	$	455.6
Net proceeds from issuance of Legacy Crestwood common units	—		217.5			—		217.5
Contributions from general partner	—		249.7			—		249.7
Distributions to general partner	—		(25.8		)			(25.8		)
Distributions to limited partners	—		(77.7		)	—		(77.7		)
Unit-based compensation charges	—		1.9			—		1.9
Taxes paid for unit-based compensation vesting	—		(0.4		)	—		(0.4		)
Net income	—		38.9			—		38.9
Balance at December 31, 2012	—		859.7			—		859.7
Net proceeds from issuance of common units	—		714.0			—		714.0
Issuance of common units for Arrow acquisition	—		200.0			—		200.0
Invested capital from Legacy Inergy, net of debt (Note 3)	—		2,682.3			—		2,682.3
Contributions from general partner	—		15.5			—		15.5
Distribution to general partner	—		(26.2		)	—		(26.2		)
Distributions to limited partners	—		(214.5		)	—		(214.5		)
Distribution for additional interest in Crestwood Marcellus Midstream LLC	—		(129.0		)	—		(129.0		)
Unit-based compensation charges	—		15.8			—		15.8
Taxes paid for unit-based compensation vesting	—		(5.5		)	—		(5.5		)
Issuance of preferred equity of subsidiary	—		—			96.1		96.1
Net income (loss)	—		(20.0		)	4.9		(15.1		)
Balance at December 31, 2013	—		4,092.1			101.0		4,193.1
Change in invested capital from Legacy Inergy, net of debt (Note 3)	—		(5.0		)	—		(5.0		)
Distributions to general partner	—		(41.8		)	—		(41.8		)
Distribution to general partner for interest in Tres	—		(30.6		)	—		(30.6		)
Distributions to limited partners	—		(296.5		)	—		(296.5		)
Issuance of preferred equity of subsidiary	—		—			53.9		53.9
Issuance of Class A preferred units	430.5		—			—		430.5
Unit-based compensation charges	—		18.1			—		18.1
Taxes paid for unit-based compensation vesting	—		(1.6		)	—		(1.6		)
Other	—		(0.8		)	—		(0.8		)
Net income (loss)	17.2		(55.9		)	16.8		(21.9		)
Balance at December 31, 2014	$	447.7	$	3,678.0		$	171.7	$	4,297.4

See accompanying notes.

97

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)
	Year Ended December 31,
	2014			2013			2012
Operating activities
Net income (loss)	$	(21.9	)	$	(15.1	)	$	38.9
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, amortization and accretion	221.7			121.7			51.9
Amortization of debt-related deferred costs, discounts and premiums	7.3			9.1			5.5
Unit-based compensation charges	18.1			15.8			1.9
(Gain) loss on long-lived assets, net	33.6			(5.4		)	—
Goodwill impairment	48.8			4.1			—
Loss on contingent consideration	8.6			31.4			—
Loss from unconsolidated affiliates, net	0.7			0.1			—
Deferred income taxes	0.6			—			—
Other	—			0.1			(0.2		)
Changes in operating assets and liabilities, net of effects from acquisitions:
Accounts receivable	15.1			70.3			(3.5		)
Inventories	(1.8		)	(0.1		)	—
Prepaid expenses and other current assets	(8.6		)	3.5			0.8
Accounts payable, accrued expenses and other liabilities	(20.8		)	(49.0		)	6.8
Reimbursements of property, plant and equipment	21.5			—			—
Net cash provided by operating activities	322.9			186.5			102.1
Investing activities
Acquisitions, net of cash acquired (Note 3)	(19.5		)	(561.5		)	(564.0		)
Purchases of property, plant and equipment	(407.0		)	(334.6		)	(52.6		)
Investment in unconsolidated affiliates	(144.4		)	(151.5		)	—
Proceeds from sale of assets	—			11.1			—
Net cash used in investing activities	(570.9		)	(1,036.5		)	(616.6		)
See accompanying notes.

98

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)
	Year Ended December 31,
	2014			2013			2012
Financing activities
Proceeds from the issuance of long-term debt	$	2,089.9		$	2,072.8		$	706.7
Principal payments on long-term debt	(1,949.8		)	(1,634.3		)	(534.0		)
Payments on capital leases	(3.2		)	(4.3		)	(3.0		)
Payments for debt-related deferred costs	(0.1		)	(32.0		)	(11.4		)
Payments for deferred acquisition costs	—			—			(7.8		)
Distributions to limited partners	(296.5		)	(204.5		)	(77.7		)
Distributions to general partner	(41.8		)	(26.2		)	(25.8		)
Distribution to general partner for interest in Tres	(30.6		)	—			—
Distribution for additional interest in Crestwood Marcellus Midstream LLC	—			(129.0		)	—
Contributions from general partner	—			5.5			249.7
Net proceeds from issuance of common units	—			714.0			217.5
Net proceeds from issuance of preferred equity of subsidiary	53.9			96.1			—
Net proceeds from issuance of Class A preferred units	430.5			—			—
Taxes paid for unit-based compensation vesting	(1.6		)	(5.5		)	(0.4		)
Other	(0.8		)	—			—
Net cash provided by financing activities	249.9			852.6			513.8
Net change in cash	1.9			2.6			(0.7		)
Cash at beginning of period	2.7			0.1			0.8
Cash at end of period	$	4.6		$	2.7		$	0.1
Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	96.9		$	56.7		$	27.9
Cash paid during the period for income taxes	$	0.4		$	—		$	—
Supplemental schedule of noncash investing and financing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(40.6	)	$	(30.7	)	$	(1.7	)
Acquisitions, net of cash acquired:
Current assets	$	0.5		$	240.0		$	—
Property, plant and equipment	13.5			2,076.8			178.0
Intangible assets	9.4			519.4			384.0
Goodwill	3.6			1,583.2			4.1
Other assets	—			22.3			—
Current liabilities	(2.7		)	(243.9		)	(0.7		)
Debt	(3.5		)	(745.0		)	—
Invested capital of Crestwood Midstream Partners LP, net of debt (Note 3)	—			(2,882.3		)	—
Other liabilities	(1.3		)	(9.0		)	(1.4		)
Total acquisitions, net of cash acquired	$	19.5		$	561.5		$	564.0

See accompanying notes.

99

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Organization and Description of Business

Organization

Crestwood Midstream Partners LP (the Company or Crestwood) is a publicly-traded (NYSE: CMLP) Delaware limited partnership that provides midstream solutions to customers in the crude oil, 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.

Crestwood Equity Partners LP (CEQP) through its wholly-owned subsidiary, owns a non-economic general partnership interest in us and 100% of our incentive distribution rights (IDRs), which entitle CEQP to receive 50% of all distributions paid to our common unit holders in excess of our initial quarterly distributions of $0.37 per common unit. As of December 31, 2014, CEQP directly owns approximately 4% of our common limited partnership units. CEQP is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve), which owns approximately 11% of our common units as of December 31, 2014.

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

Business Combination

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

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 Crestwood, representing all of the Legacy Crestwood common and Class D units held by Legacy Crestwood’s general partner.

On June 18, 2013, CEQP distributed to its unitholders approximately 56.4 million Legacy Inergy common units, representing all of the Legacy Inergy common units held by CEQP.

On June 19, 2013, Crestwood Holdings acquired the owner of CEQP’s general partner and contributed to CEQP ownership of Crestwood Gas Services GP, LLC, which owned 100% of the general partnership interest and IDRs of Legacy Crestwood. Crestwood Holdings and First Reserve acquired control of CEQP as a result of these transactions. As a result of Crestwood Holding’s acquisition of control of CEQP, Crestwood Holdings acquired control of our general partner and, consequently, the Company on June 19, 2013.

On October 7, 2013, the merger of Legacy Inergy’s wholly-owned subsidiary with and into Legacy Crestwood (the Crestwood Merger) was completed, with Legacy Crestwood continuing as the surviving accounting entity. Immediately following the closing of the Crestwood Merger, on October 7, 2013, (i) Legacy Crestwood merged with and into Legacy Inergy, with Legacy Inergy continuing as the surviving legal entity, and (ii) Legacy Inergy changed its name to Crestwood Midstream Partners LP and changed its NYSE listing symbol to “CMLP”. Under the merger agreement, 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 Legacy Crestwood

100

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

common or Class D units outstanding immediately following the merger. Additionally, Legacy Crestwood unitholders (other than Crestwood Holdings) received a one-time $34.9 million cash payment at the closing of the merger, or $1.03 per unit, $24.9 million of which was paid by Legacy Inergy and $10 million of which was paid by Crestwood Holdings.

Following the closing of the Crestwood Merger on October 7, 2013, Crestwood Holdings exchanged 7,100,000 of our common units for 14,300,000 of CEQP 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, transportation services and sales of natural gas and the delivery of NGLs to producers in unconventional shale plays and tight-gas plays in West Virginia, Wyoming, Texas, Arkansas, New Mexico and Louisiana. This segment primarily includes our rich gas gathering systems and processing plants in the Marcellus, Powder River Basin (PRB) Niobrara, Barnett, and Permian Shale plays, and our dry gas gathering systems in the Barnett, Fayetteville, and Haynesville Shale plays;

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

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

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, prior to the Crestwood Merger and the merger of Legacy Crestwood with and into Legacy Inergy on October 7, 2013. Crestwood Holdings' acquisition of control of CEQP’s general partner on June 19, 2013 was accounted for as a reverse acquisition under the purchase method of accounting in accordance with accounting standards for business combinations.  CEQP's accounting for this reverse acquisition resulted in the legal acquiree (Crestwood Gas Services GP LLC) being the acquirer for accounting purposes. CEQP’s

accounting acquiree (inclusive of Legacy Inergy) was subject to the purchase method of accounting and its balance sheet was

adjusted to fair market value as of June 19, 2013. Accordingly, the merger of Legacy Crestwood and Legacy Inergy on October

7, 2013 was accounted for as a reverse merger amongst entities under common control with Legacy Crestwood continuing as the surviving entity for accounting purposes and Legacy Inergy continuing as the surviving entity for legal purposes. As the reverse merger was amongst entities under common control, the financial statements have been recasted to reflect the operations of Legacy Inergy as being acquired by Legacy Crestwood on June 19, 2013, the date in which Legacy Inergy and Legacy Crestwood came under common control.

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

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CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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.

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.

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. 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

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CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	20
Covenants not to compete	3
Trademarks	5

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.

For the year ended December 31, 2014, we recorded an impairment of goodwill of approximately $48.8 million related to four of our 10 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

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CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 the 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 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 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 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

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consolidated statements of operations when the criteria has been met and all services have been rendered. AtDecember 31, 2014and2013, we had deferred revenue of approximately$11.6 millionand$1.6 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 our partnership agreement.

Environmental Costs and Other Contingencies

We recognize liabilities for environmental and other contingencies when there is an exposure that indicates it is both probable that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end of range is accrued.

We record liabilities for environmental contingencies at their undiscounted amounts on our consolidated balance sheets as accrued expenses and other liabilities when environmental assessments indicate that remediation efforts are probable and costs can be reasonably estimated. Estimates of our liabilities are based on currently available facts and presently enacted laws and regulations, taking into consideration the likely effects of other societal and economic factors. These estimates are subject to revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and recognize a current period charge in operations and maintenance expenses when clean-up efforts do not benefit future periods.

We evaluate potential recoveries of amounts from third parties, including insurance coverage, separately from our liability. Recovery is evaluated based on the solvency of the third party, among other factors. When recovery is assured, we record and report an asset separately from the associated liability on our consolidated balance sheet.

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Price Risk Management Activities

In 2014, we began entering into daily and short-term forward crude purchase and sale agreements in our NGL and crude services segment. We utilize 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; and (ii) ensure the availability of adequate physical supply of commodity. 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 year ended December 31, 2014. Our derivative instruments did not have a material impact on our financial statements during the year ended December 31, 2014.

Unit-Based Compensation

Long-term incentive awards are granted under our incentive plan. Unit-based compensation awards consist of restricted units that are valued at the closing market price of our 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 11 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, we 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 primarily to anticipated operating synergies between the assets acquired and our existing assets. These assets are included in our NGL and crude services segment.

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LT Enterprises. On May 9, 2014, we purchased substantially all of the operating assets of LT Enterprises, Inc. (LT Enterprises) for approximately $10.7 million, comprised of $9.0 million paid at closing plus deferred payments of $1.7 million. 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, we 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 merger of Legacy Crestwood with and into Legacy Inergy was accounted for as a reverse merger amongst entities under common control. This accounting treatment requires the accounting acquiree (Legacy Inergy) to have its assets and liabilities stated at fair value as well as any other purchase accounting adjustments as of June 19, 2013, the date in which Legacy Crestwood and Legacy Inergy came under common control. The fair value of Legacy Inergy was calculated based on the consolidated enterprise fair value of Legacy Inergy as of June 19, 2013. This consolidated enterprise fair value considered Legacy Inergy's (i) discounted future cash flows based on its operations; (ii) the stock price of Legacy Inergy; (iii) the value of its outstanding senior notes based on quoted market prices for same or similar issuances; and (iv) the value of its outstanding floating rate debt.

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	$	49.1
Property, plant and equipment	1,677.8
Intangible assets	196.0
Other assets	2.9
Total identifiable assets acquired	1,925.8
Current liabilities	30.9
Long-term debt	745.0
Other long-term liabilities	5.3
Total liabilities assumed	781.2
Net identifiable assets acquired	1,144.6
Goodwill	1,532.7
Net assets acquired	$	2,677.3

Of the $1,532.7 million of goodwill, $806.4 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 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.

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During the period ended from June 19, 2013 to December 31, 2013, we recognized $148.6 million of operating revenues and $29.8 million of operating income related to this reverse acquisition. Transaction costs related to the Crestwood Merger were $2.1 million and $24.7 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, we 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 one of our wholly-owned subsidiaries with and into Arrow (the Arrow Acquisition), with Arrow continuing as the surviving entity and , as a result, our wholly-owned subsidiary. The base merger consideration consisted of $550 million in cash and 8,826,125 common units 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

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.

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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 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.

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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.

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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.

	Year Ended December 31,
	2013			2012
Revenues	$	2,083.3		$	1,184.5
Net income (loss)	$	(21.0	)	$	50.1
Net income (loss) per limited partner unit(1):
Basic	$	(0.61	)	$	0.29
Diluted	$	(0.61	)	$	0.29

(1) Basic and diluted net income per limited partner unit for the year ended December 31, 2012 were computed based on the number of Legacy Inergy common units outstanding plus the number of common units issued by Legacy Inergy to Legacy Crestwood unitholders as part of the Crestwood Merger discussed in Note 1 and the number of units issued in conjunction with the Arrow 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
Parts and supplies	$	5.9	$	4.5
Crude oil	0.9		1.4
Raw materials	0.3		0.4
Finished goods	0.9		0.7
Total inventory	$	8.0	$	7.0

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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	1,276.6		1,231.1
Facilities and equipment	1,468.8		1,041.0
Buildings, land, rights-of-way, storage contracts and easements	806.4		766.2
Vehicles	13.6		4.1
Construction in process	153.7		360.5
Base gas	37.5		36.3
Salt deposits	120.5		120.5
Office furniture and fixtures	6.4		6.0
	3,883.5		3,565.7
Less: accumulated depreciation and depletion	365.4		215.6
Total property, plant and equipment, net	$	3,518.1	$	3,350.1

Depreciation. Depreciation expense totaled $148.3 million, $87.1 million and $40.8 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 did not have depletion expense.

Capitalized Interest. During the year ended December 31, 2014, 2013 and 2012 we capitalized interest of $7.5 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 $2.8 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, we 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	$	483.2	$	476.4
Covenants not to compete	5.6		3.0
Gas gathering, compression and processing contracts	431.4		451.4
Acquired storage contracts	29.0		29.0
Trademarks	9.7		11.0
Deferred financing costs	54.3		54.3
	1,013.2		1,025.1
Less: accumulated amortization	137.0		54.3
Total intangible assets, net	$	876.2	$	970.8

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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	$	57.0	$	13.4
Covenants not to compete	2.1		0.6
Gas gathering, compression and processing contracts	47.9		27.9
Acquired storage contracts	12.7		4.0
Trademarks	0.9		0.3
Deferred financing costs	16.4		8.1
Total accumulated amortization	$	137.0	$	54.3

Amortization and interest expense for the years ended December 31, 2014, 2013 and 2012, was approximately $81.0 million, $43.1 million and $15.9 million.

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

Year Ending December 31,
2015	$	89.6
2016	76.4
2017	63.5
2018	51.5
2019	44.6

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	$	23.7	$	20.0
Accrued property taxes	2.1		7.6
Accrued product purchases payable	0.7		1.6
Tax payable	0.4		10.6
Interest payable	22.0		14.9
Accrued additions to property, plant and equipment	20.0		58.1
Commitments and contingent liabilities (Note 12)	40.0		31.4
Capital leases	1.3		2.6
Deferred revenue	11.6		1.6
Other	0.2		—
Total accrued expenses and other liabilities	$	122.0	$	148.4

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

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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	—		0.3
Net asset retirement obligation at December 31	$	22.0	$	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.

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 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 year 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.

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Tres Palacios Holdings LLC

In December 2014, CEQP sold its 100% interest in Tres Palacios Storage Company LLC (Tres Palacios) to Tres Palacios Holdings LLC (Tres Holdings), a newly formed joint venture between CMLP Tres Manager LLC, our 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 us to Crestwood Equity. As a result of this transaction, we own 50.01% of Tres Holdings and we are the operator of Tres Palacios and its assets. Brookfield owns the remaining 49.99% interest in Tres Holdings. We account for our investment in Tres Holdings under the equity method of accounting, and the investment is included in our storage and transportation segment.

The acquisition of our 50.01% interest in Tres Palacios was considered a transaction between entities under common control and, as a result, we recorded our investment in Tres Palacios at approximately $35.8 million, which represented 50.01% of Crestwood Equity's historical basis in Tres Palacios. We reflected the difference between Crestwood Equity's historical basis and the cash paid by us in excess of Crestwood Equity's historical basis of approximately $30.6 million as a distribution to general partner.

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.

Our 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 Palacios' 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 of Tres Holdings exceeded our investment balance in Tres Holdings by approximately $30.6 million based on the transaction described above. 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.

We 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 this agreement, Tres Palacios reimburses us for all costs incurred on its behalf. We did not receive any reimbursements under this agreement during the year ended December 31, 2014.

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 were 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.

115

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 7 - Financial Instruments

Fair Value

We separate the fair values of our financial instruments into three levels (Levels 1, 2 and 3) based on our assessment of the availability of observable market data and the significance of non-observable data used to determine fair value. Our assessment and classification of an instrument within a level can change over time based on the maturity or liquidity of the instruments and would be reflected at the end of the period in which the change occurs. At December 31, 2014 and 2013, there were no changes to the inputs and valuation techniques used to measure fair value, the types of instruments, or the levels in which they are classified.

In September 2014, we began entering into daily and short-term forward crude purchase and sale agreements in our NGL and crude services segment related to available capacity on our crude contracts and facilities for our operations located in the Bakken and PRB Niobrara Shale plays. As of December 31, 2014, our outstanding positions and the related impact to our consolidated statement of operations associated with our risk management activities were not material.

As of December 31, 2014 and 2013, the carrying amounts of cash, accounts receivable and accounts payable represent fair value based on the short-term nature of these instruments. The fair value of the amount outstanding under our credit facility approximates its carrying amount as of December 31, 2014 and 2013 due primarily to the variable nature of the interest rate of the instrument, which is considered a Level 2 fair value measurement. As discussed below, contemporaneously with the closing of the Crestwood Merger on October 7, 2013, we repaid and retired the credit facilities of Legacy Crestwood and CMM with borrowings under the Crestwood Midstream Revolver.

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

	December 31, 2014				December 31, 2013
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2019 Senior Notes	$	351.0	$	360.5	$	351.2	$	379.3
2020 Senior Notes	$	504.0	$	481.6	$	504.7	$	513.8
2022 Senior Notes	$	600.0	$	568.5	$	600.0	$	617.3

Debt

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

	December 31,
	2014		2013
Credit Facility	$	555.0	$	414.9
2019 Senior Notes	350.0		350.0
Premium on 2019 Senior Notes	1.0		1.2
2020 Senior Notes	500.0		500.0
Fair value adjustment of 2020 Senior Notes	4.0		4.7
2022 Senior Notes	600.0		600.0
Other	3.5		—
Total debt	2,013.5		1,870.8
Less: current portion	0.7		2.9
Total long-term debt	$	2,012.8	$	1,867.9

116

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Credit Facility

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

In June 2014, we amended the Credit Facility to clarify, among other things, (i) the methodology for calculating the value of our 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. We did not pay any fees to our bank syndicate for this amendment.

At December 31, 2014 and 2013, the balance outstanding on the Credit Facility was $555.0 million and $414.9 million and outstanding standby letters of credit were $15.1 million and $30.7 million. We had $429.9 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 Credit Facility 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 our Credit Facility (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 our 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 our 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 Credit Facility is subject to a commitment fee ranging from 0.30% to 0.50% per annum according to our 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 Credit Facility contains various covenants and restrictive provisions that limit our ability to, among other things, (i) incur additional debt; (ii) make distributions on or redeem or repurchase units; (iii) make certain investments and acquisitions; (iv) incur or permit certain liens to exist; (v) 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 Credit Facility requires maintenance of a consolidated leverage ratio (as defined in our 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, we notified the administrative agent of our election to commence an Acquisition Period (as defined in our credit agreement) effective as of December 3, 2014. We made this election following our acquisition of a 50.01% indirect interest in Tres Palacios. Our consolidation leverage ratio (as defined in our credit agreement) increases to 5.50 to 1.0 during the 270-day Acquisition Period as a result of this election.

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

117

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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 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) the Company 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 the Company and Finance Corp. under the 2020 Senior Notes described below; (iii) the Company’s subsidiary guarantors of the 2020 Senior Notes guaranteed obligations of 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 our 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, we filed a registration statement with the SEC under which we 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.  We 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 our senior notes are fully and unconditionally guaranteed, joint and severally, on a senior unsecured basis by our domestic restricted subsidiaries (other than Finance Corp.). The indentures contain customary release provisions, such as (i) disposition of all or substantially all of 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; and (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 us or any other guarantor subsidiary, provided it no longer guarantees indebtedness under the Credit Facility.

The indentures restricts our ability and the ability of our 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 us from our restricted subsidiaries; consolidate, merge or transfer all of substantially all of our assets; engage in affiliate transactions; and create unrestricted subsidiaries. These restrictions are subject to a number of important 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 our 2019 Senior Notes, we may not pay any dividend on our 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, we were in compliance with the debt covenants and restrictions in each of its credit agreements discussed above.

118

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Other Obligations

Non-interest bearing obligations due under noncompetition agreements consisted of agreement between Crestwood Midstream and sellers of certain companies acquired in 2014 with payments due through 2019 and imputed interest of 5.02%. Non-interest bearing obligations consisted of $4.0 million in total payments due under agreements, less unamortized discount based on imputed interest of $0.5 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	$	0.7
2016	0.7
2017	0.7
2018	555.8
2019	350.6
Thereafter	1,100.0
Total debt	$	2,008.5

Note 8 - Earnings Per Limited Partner Unit

Prior to the Crestwood Merger, net income attributable to Legacy Crestwood was allocated to the general partner and the limited partners in accordance with their respective ownership percentages, after giving effect to incentive distributions earned by the general partner. To the extent cash distributions exceeded net income attributable to Legacy Crestwood, the excess distributions were allocated proportionately to all participating units outstanding based on their respective ownership percentages. As a result of the Crestwood Merger, CEQP, which owns our general partner, owns a non-economic general partner interest in us and 100% of our IDRs. We allocate net income attributable to CMLP to our limited partners after giving effect to the IDRs earned by CEQP and net income attributable to the Class A preferred units.

Basic earnings per unit are calculated using the two-class method. Diluted earnings per unit are computed using the treasury stock method, which considers the impact to net income attributable to CMLP and limited partner units from the potential issuance of limited partner units as discussed below. The weighted average number of units outstanding is calculated based on the presumption that the number of common units issued by Legacy Inergy to Legacy Crestwood unitholders as part of the Crestwood Merger were outstanding for the entire period prior to Crestwood Merger.

The tables below show the (i) allocation of net income attributable to CMLP and the (ii) net income attributable to CMLP per limited partner unit based on the number of basic and diluted limited partner units outstanding for the years ended December 31, 2014, 2013 and 2012 (in millions):

Allocation of Net Income Attributable to CMLP
	Year Ended December 31,
	2014			2013			2012
Net income (loss) attributable to CMLP	$	(38.7	)	$	(20.0	)	$	38.9
Class A preferred units interest in net income attributable to CMLP	(17.2		)	—			—
General partner’s incentive distributions	(30.1		)	(26.4		)	(14.8		)
General partner’s interest in net income attributable to CMLP after incentive distributions	—			(0.4		)	(7.4		)
Payment to Legacy Crestwood unitholders	—			(34.9		)	—
Limited partners’ interest in net income (loss) attributable to CMLP after incentive distributions	$	(86.0	)	$	(81.7	)	$	16.7

119

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Earnings Per Limited Partner Unit
	Year Ended December 31,
	2014			2013			2012
Limited partners’ interest in net income (loss)	$	(86.0	)	$	(81.7	)	$	16.7
Weighted-average limited partner units - basic	187.9			99.2			64.7
Effect of diluted units	—			—			—
Weighted-average limited partner units - diluted	187.9			99.2			64.7
Basic earnings per unit:
Net income (loss) per limited partner	$	(0.46	)	$	(0.82	)	$	0.26
Diluted earnings per unit:
Net income (loss) per limited partner	$	(0.46	)	$	(0.82	)	$	0.26

We exclude potentially dilutive securities from the determination of diluted earnings per unit (as well as their related income statement impacts) when their impact on net income attributable to CMLP per limited partner unit is anti-dilutive. During the years ended December 31, 2014 and 2013, we excluded a weighted-average of 9,089,196 common units and 1,891,326 common units, representing Crestwood Niobrara's preferred units if converted to common units, from our diluted earnings per unit. During the year ended December 31, 2014, we also excluded a weighted-average of 7,441,255 common units, representing Class A preferred units if converted to common units, from our diluted earnings per unit. There were no units excluded from our dilutive earnings per share as we did not have any anti-dilutive units for the year ended December 31, 2012.

General Partner Interest and Incentive Distribution Rights

Prior to the Crestwood Merger, Legacy Crestwood’s general partner was entitled to quarterly distributions equal to its general partner interest. In addition, Legacy Crestwood’s general partner held IDRs in accordance with the Legacy Crestwood Partnership Agreement. These rights paid an increasing percentage, up to a maximum of 50% of the cash they distributed from operating surplus in excess of $0.45 per unit per quarter. The maximum distribution of 50% included distributions paid to the general partner based on its general partner interest and assumed that Legacy Crestwood’s general partner maintained its general partner interest. The maximum distribution of 50% did not include any distributions that the general partner may have received on limited partner units that it owned.

Following the Crestwood Merger, our general partner is not entitled to distributions on its non-economic general partner interest. IDRs are entitled to receive 50% of the cash distributed from operating surplus (as defined in our partnership agreement) in excess of the initial quarterly distribution of $0.37.

CEQP, as the owner of our IDRs, has the right under our partnership agreement to elect to relinquish the right to receive incentive distribution payments based on the initial quarterly distribution and to reset, at a higher level, the quarterly distribution amount (upon which the incentive distribution payments to CEQP would be set). If CEQP elects to reset the quarterly distribution, it will be entitled to receive a number of newly issued Company common units. The number of common units to be issued to CEQP will equal the number of common units that would have entitled the holder to the quarterly cash distribution in the prior quarter equal to the distribution to CEQP on the IDRs in such prior quarter. As the reset election has not been made, no additional units have been issued. For accounting purposes, diluted earnings per unit can be impacted, (even if the reset election has not been made), if the combined impact of issuing the additional units and resetting the cash target distribution is dilutive. Currently, diluted earnings per unit has not been impacted because the combined impact is anti-dilutive.

See Note 10 for a further discussion of the distributions and IDRs paid to the general partner during the three years ended December 31, 2014.

Note 9 - Income Taxes

The provision for income taxes for the years ended December 31, 2014, 2013, and 2012 consisted of current state taxes of approximately $0.7 million, $0.7 million and $1.2 million.  The effective rate differs from the statutory rate for the years ended

120

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2014 and 2013 and 2012 primarily due to the Partnership not being treated as a corporation for federal income tax purposes as discussed in Note 2.

Deferred income taxes 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. We are responsible for the Texas Margin tax computed on the Texas franchise tax return. 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. For the year ended December 31, 2014, we had a deferred tax liability of approximately $0.6 million associated with the Texas Margin Tax. For the years ended December 31, 2013, there were no deferred tax liability recognized on our consolidated balance sheet.

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.

Note 10 - Partners’ Capital

Class A Preferred Units

On June 17, 2014, we entered into definitive agreements with a group of investors, including Magnetar Financial, affiliates of GSO Capital Partners LP and GE Energy Financial Services (the Class A Purchasers). Under these agreements, we have agreed to sell to the Class A Purchasers and the Class A Purchasers have agreed to purchase from us up to $500 million of Preferred Units at a fixed price of $25.10 per unit on or before September 30, 2015. 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 to us of approximately $440.0 million (net proceeds of approximately $430.5 million after deducting transaction fees and offering expenses). 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 our 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, we 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 our common units. 

The Preferred Units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each Preferred 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 our other securities outstanding.

On July 9, 2014, we 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. We registered 26,299,076 common units under the registration statement.

121

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Common Units

Common 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, Legacy Inergy 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
Legacy Inergy	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.

Equity Distribution Agreement. On July 10, 2014, we entered into an equity distribution agreement with certain financial institutions (each, a Manager), under which we may offer and sell from time to time through one or more of the Managers, common units having an aggregate offering price of up to $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. We will pay the Managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under our ATM program. We have not issued any common units under this equity distribution program as of December 31, 2014 and through the date of this filing.

Distributions

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

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

Distributions to General Partner

During the years ended December 31, 2014, 2013 and 2012, we paid cash distributions to our general partner (representing IDRs and distributions related to common units held by the general partner) of approximately $41.8 million, $26.2 million and $25.8 million.

122

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Distributions to Class A Preferred Unit Holders

Our partnership agreement requires us to make quarterly distributions to our Class A Preferred Unit holders. The holders of our Class A Preferred Units (the Preferred Units) are entitled to receive fixed quarterly distributions of $0.5804 per unit. For the 12 quarters following the quarter ended June 30, 2014 (the Initial Distribution Period), distributions on our Preferred Units can be made in additional Preferred Units, cash, or a combination thereof, at our election. If we elect to pay the quarterly distribution through the issuance of additional Preferred Units, the number of units to be distributed will be calculated as the fixed quarterly distribution of $0.5804 per unit divided by the cash purchase price of $25.10 per unit. We accrue the fair value of such distribution at the end of the quarterly period and adjust the fair value of the distribution on the date the additional Preferred Units are distributed. Distributions on our Preferred Units following the Initial Distribution Period will be made in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to our Preferred Unit holders. If we fail to pay the full amount payable to our Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.7059 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if we fail to pay in full any Class A Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

During the year ended December 31, 2014, we issued 387,991 Class A Preferred Units to our preferred unitholders in lieu of paying quarterly cash distributions. On February 13, 2015 we issued 414,325 Class A Preferred Units to our preferred unitholders for the quarter ended December 31, 2014 in lieu of paying a cash distribution.

Distributions to Limited Partners

The following table presents quarterly cash distributions paid to our limited partners (excluding distributions paid to our general partner on its common units held) during the years ended December 31, 2014 and 2013. In addition, during the year ended December 31, 2013, we paid cash distributions of approximately $24.9 million as a result of the Crestwood Merger discussed below. During the year ended December 31, 2012, Legacy Crestwood paid cash distributions of $77.7 million to its limited partners.

Record Date	Payment Date	Per Unit Rate		Cash Distributions (in millions)
2014
February 7, 2014	February 14, 2014	$	0.41	$	74.1
May 8, 2014	May 15, 2014	$	0.41	74.2
August 7, 2014	August 14, 2014	$	0.41	74.1
November 7, 2014	November 14, 2014	$	0.41	74.1
				$	296.5
2013
January 31, 2013	February 12, 2013	$	0.510	$	21.0
April 30, 2013	May 10, 2013	$	0.510	27.4
August 1, 2013	August 9, 2013	$	0.510	27.4
August 7, 2013	August 14, 2013	$	0.400	34.3		(1)
November 7, 2013	November 14, 2013	$	0.405	69.5		(1)
				$	179.6

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

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On February 13, 2015, we paid a distribution of $0.41 per limited partner unit to unitholders of record on February 6, 2015 with respect to the fourth quarter of 2014.

Non-Controlling Partners

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. We allocated net income to the non-controlling interest based on the overall return attributable to the preferred security of approximately $16.8 million and $4.9 million during the years ended December 31, 2014 and 2013.

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.

Distributions to Non-Controlling Partners. 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.

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.

Other Partners' Capital Transactions

Crestwood Merger

As discussed in Note 1, in conjunction with the Crestwood Merger, Legacy Crestwood unitholders received 1.07 units of Legacy Inergy 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 contributions from general partner for the year ended December 31, 2013. We reflected the distribution of $34.9 million as distributions to partners on our consolidated statements of partners’ capital for the year ended December 31, 2013.

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 a contribution from 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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, we issued 8,826,125 common units as partial consideration of the Arrow Acquisition. See Note 3 for additional information regarding the Arrow Acquisition.

Other. During the year ended December 31, 2013, we received a contribution of approximately $5.5 million related to reimbursements of costs pursuant to our omnibus agreement with CEQP.

Note 11 - Equity Plans

Crestwood Midstream

Long-term incentive awards are granted under the Crestwood Midstream Partners LP Long Term Incentive Plan (Crestwood LTIP) in order to align the economic interests of key employees and directors with those of Crestwood's common unitholders and to provide an incentive for continuous employment. Long-term incentive compensation consist solely of grants of restricted common units (which represent limited partner interests of the Company) which vest based upon continued service.

During 2014, we have issued restricted unit awards, which were approved by either our 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.

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	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, which we expect will be amortized during the next three years (or sooner in certain cases, which generally represents the original vesting period of these instruments), except for grants to non-employee directors of our general partner, which vest over one year. We recognized compensation expense of approximately $11.2 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. An additional $6.9 million and $4.4 million of net compensation expense was allocated from CEQP to us during the years ended December 31, 2014 and 2013 (see Note 13). 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 LTIP.

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Employee Unit Purchase Plan. Beginning in September 2014, the board of directors of our general partner made available an employee unit purchase plan under which employees of the general partner may purchase our common units through payroll deductions up to a maximum of 10% of the employees' eligible compensation. Under the plan, we may purchase our common units on the open market for the benefit of participating employees based on their payroll deductions.  In addition, we may contribute an additional 10% of participating employees' payroll deductions to purchase additional Crestwood common units for participating employees. Unless increased by the board of directors of our general partner, the maximum 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

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:

	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.  We 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. We 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, we withheld 21,014 common units to satisfy employee tax withholding obligations. 

Note 12 - Commitments and Contingencies

Legal Proceedings

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).

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

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CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Regulatory Compliance

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

Environmental Compliance

During 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 third quarter of 2014. 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.

Commitments and Purchase Obligations

Operating Leases. We 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.

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	$	6.6
2016	5.9
2017	5.3
2018	4.8
2019	4.6
Thereafter	16.3
Total minimum lease payments	$	43.5

Rent expense for operating leases for the years ended December 31, 2014, 2013 and 2012, totaled $8.7 million, $7.6 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 approximately $2.9 million, $3.6 million and $3.1 million for the years ended December 31, 2014, 2013 and 2012.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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

Year Ending December 31,
2015	$	1.4
2016	0.8
2017	0.5
2018	0.2
Total payments	2.9
Imputed interest	(0.1		)
Present value of future payments	$	2.8

Our capital lease liabilities were $2.8 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 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 $20.0 million and our gathering and processing segment 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 13 - 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.

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, firm storage services, product purchases and various operating agreements. See Notes 6 and 10 for additional information on our related party transactions.

We do not have any employees. We share common management, general and administrative and overhead costs with CEQP. We have an omnibus agreement with CEQP that requires us to reimburse CEQP for all shared costs incurred on our behalf, except for certain unit based compensation costs which are treated as capital transactions. 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. Due to the nature of these shared costs, it is not practicable to estimate what the costs would have been on a stand-alone basis. Accordingly, the accompanying financial statements may not necessarily be indicative of the conditions that would have existed, or the results of operations that would have occurred, if we operated as a stand-alone entity.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	$	4.0	$	74.9	$	113.7
NGL and crude services revenues	$	13.6	$	7.2	$	—
Gathering and processing costs of product/services sold(2)	$	42.2	$	32.5	$	15.2
General and administrative expenses(3)	$	63.6	$	34.7	$	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.

(3) Included in general and administrative expenses is approximately $6.9 million and $4.4 million of net unit-based compensation charges allocated to us from CEQP for the years ended December 31, 2014 and 2013.

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

	December 31,
	2014		2013
Accounts receivable	$	0.3	$	1.1
Accounts payable	$	6.3	$	8.7

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

Note 14 - Segments

Financial Information

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

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

	Year Ended December 31,
	2014			2013			2012
Net income (loss)	$	(21.9	)	$	(15.1	)	$	38.9
Add:
Interest and debt expense, net	111.4			71.4			35.8
Provision for income taxes	0.7			0.7			1.2
Depreciation, amortization and accretion	221.7			121.7			51.9
EBITDA	$	311.9		$	178.7		$	127.8

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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			Corporate			Total
Revenues	$	332.5		$	179.1	$	2,053.9		$	—		$	2,565.5
Costs of product/services sold	71.3			14.3		1,851.9			—			1,937.5
Operations and maintenance expense	62.9			16.6		59.5			—			139.0
General and administrative expense	—			—		—			85.4			85.4
Gain (loss) on long-lived assets, net	(32.7		)	0.6		(1.5		)	—			(33.6		)
Goodwill impairment	(18.5		)	—		(30.3		)	—			(48.8		)
Loss on contingent consideration	(8.6		)	—		—			—			(8.6		)
Earnings (loss) from unconsolidated affiliates, net	0.5			0.2		(1.4		)	—			(0.7		)
EBITDA	$	139.0		$	149.0	$	109.3		$	(85.4	)	$	311.9
Goodwill	$	81.1		$	726.3	$	825.2		$	—		$	1,632.6
Total assets	$	1,993.0		$	1,981.2	$	2,455.5		$	166.8		$	6,596.5
Purchases of property, plant and equipment	$	245.7		$	9.1	$	147.8		$	4.4		$	407.0

	Year Ended December 31, 2013
	Gathering and Processing			Storage and Transportation		NGL and Crude Services			Corporate			Total
Revenues	$	291.2		$	90.1	$	277.3		$	—		$	658.6
Costs of product/services sold	56.6			8.7		230.4			—			295.7
Operations and maintenance expense	54.9			9.9		8.5			—			73.3
General and administrative expense	—			—		—			80.7			80.7
Gain on long-lived assets	5.4			—		—			—			5.4
Goodwill impairment	(4.1		)	—		—			—			(4.1		)
Loss on contingent consideration	(31.4		)	—		—			—			(31.4		)
Earnings (loss) from unconsolidated affiliates, net	0.1			—		(0.2		)	—			(0.1		)
EBITDA	$	149.7		$	71.5	$	38.2		$	(80.7	)	$	178.7
Goodwill	$	99.6		$	936.5	$	646.7		$	—		$	1,682.8
Total assets	$	1,836.4		$	2,190.5	$	2,217.3		$	157.6		$	6,401.8
Purchases of property, plant and equipment	$	271.2		$	10.3	$	52.1		$	1.0		$	334.6

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Year Ended December 31, 2012
	Gathering and Processing		Storage and Transportation		NGL and Crude Services		Corporate			Total
Revenues	$	239.5	$	—	$	—	$	—		$	239.5
Costs of product/services sold	39.0		—		—		—			39.0
Operation and maintenance expense	43.1		—		—		—			43.1
General and administrative expense	—		—		—		29.6			29.6
EBITDA	$	157.4	$	—	$	—	$	(29.6	)	$	127.8
Goodwill	$	95.0	$	—	$	—	$	—		$	95.0
Total assets	$	1,587.9	$	—	$	—	$	22.7		$	1,610.6
Purchases of property, plant and equipment	$	51.5	$	—	$	—	$	1.1		$	52.6

Major Customers

For the year ended December 31, 2014, revenues from Tesoro, QEP Midstream Partners (QEP) and Eighty-Eight Oil LLC were approximately $401.1 million, $285.1 million and $286.9 million, which exceeded 10% of our total consolidated revenues. Revenues from Tesoro, QEP and Eighty-Eight Oil LLC are reflected in our NGL and crude services segment. For the year ended December 31, 2013, revenues from Quicksilver were approximately $96.3 million which exceeded 10% of our total consolidated revenues. For the year ended December 31, 2012, revenues from Quicksilver and Antero were 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.

Note 15 – Condensed Consolidating Financial Information

Crestwood is a holding company and own no operating assets and has no significant operations independent of our subsidiaries. Obligations under our Senior Notes and our Credit Facility are jointly and severally guaranteed by substantially all of our restricted domestic subsidiaries, except for Crestwood Niobrara, PRBIC and CMLP Tres Manager LLC and their subsidiaries (collectively, Non-Guarantor Subsidiaries). Crestwood Midstream Finance Corp., the co-issuer of our Senior Notes, is our 100% owned subsidiary and has no material assets, operations, revenues or cash flows other than those related to its service as co-issuer of our Senior Notes. 

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Parent				Guarantor Subsidiaries					Eliminations
	As Adjusted		As Previously Reported		As Adjusted		As Previously Reported			As Adjusted			As Previously Reported
	(in millions)
Assets
Accounts receivable	$	4.4	$	466.8	$	199.4	$	197.8		$	—		$	(459.7	)
Accounts receivable - related party	1.1		—		—		—			—			—
Total accounts receivable	5.5		466.8		199.4		197.8			—			(459.7		)
Total current assets	5.6		466.9		218.2		216.6			—			(459.7		)
Goodwill and intangible assets, net	46.2		—		2,607.4		2,653.6			—			—
Investment in consolidated affiliates	6,053.0		6,385.2		—		—			(6,053.0		)	(6,385.2		)
Total assets	6,109.6		6,856.9		6,192.6		6,237.2			(6,053.0		)	(6,844.9		)
Liabilities and partners' capital
Accounts payable	$	15.1	$	782.7	$	139.4	$	(165.2	)	$	—		$	(459.7	)
Accounts payable - related party	5.4		—		3.3		—			—			—
Total accounts payable	20.5		782.7		142.7		(165.2		)	—			(459.7		)
Other current liabilities	26.4		11.5		124.7		145.0			—			—
Total current liabilities	46.9		794.2		267.4		(20.2		)	—			(459.7		)
Partners' capital	4,092.1		4,092.1		5,900.6		6,232.8			(5,952.0		)	(6,284.2		)
Total partners' capital	4,193.1		4,193.1		5,900.6		6,232.8			(6,053.0		)	(6,385.2		)
Total liabilities and partners' capital	6,109.6		6,856.9		6,192.6		6,237.2			(6,053.0		)	(6,844.9		)

133

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

	Parent						Guarantor Subsidiaries						Non-Guarantor Subsidiaries						Eliminations
	As Adjusted			As Previously Reported			As Adjusted			As Previously Reported			As Adjusted			As Previously Reported			As Adjusted			As Previously Reported
Cash flows from operating activities:	$	(46.1	)	$	3.9		$	266.4		$	216.4		$	—		$	—		$	(33.8	)	$	(33.8	)
Cash flows from investing activities:
Investment in unconsolidated affiliates, net	—			—			—			(24.4		)	(151.5		)	(127.1		)	—			—
Capital contributions from consolidated affiliates	(106.4		)	(82.0		)	—			—			—			—			106.4			82.0
Other	—			(0.4		)	11.1			11.1			—			—			—			0.4
Net cash provided by (used in) investing activities	(107.4		)	(83.4		)	(884.0		)	(908.4		)	(151.5		)	(127.1		)	106.4			82.4
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	1,930.9			382.9			141.9			1,689.9			—			—			—			—
Principal payments on long-term debt	(1,559.3		)	(202.0		)	(75.0		)	(1,432.3		)	—			—			—			—
Payments for debt-related deferred costs	(32.0		)	(0.1		)	—			(31.9		)	—			—			—			—
Distributions paid	(359.7		)	(219.3		)	(33.8		)	(174.2		)	—			—			33.8			33.8
Contributions from parent	—			—			55.5			55.5			56.4			32.0			(106.4		)	(82.0		)
Net proceeds from the issuance of common units	714.0			118.5			—			595.5			—			—			—			—
Change in intercompany balances	(539.9		)	—			539.9			0.4			—			—			—			(0.4		)
Net cash provided by (used in) financing activities	153.6			79.6			619.1			693.5			152.5			128.1			(72.6		)	(48.6		)

The tables below present condensed consolidating financial statements for us (parent) on a stand-alone, unconsolidated basis, and our combined guarantor and combined non-guarantor subsidiaries as of 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 has the subsidiaries operated as independent entities. As discussed in Note 2, the Crestwood Merger was accounted for as a reverse merger between entities under common control, and as such, changes in the composition of guarantors and non-guarantors should be reflected retrospectively based on the guarantor structure that existed as of the end of the most recent balance sheet.  Accordingly, we have not reflected condensed consolidating financial information as of and for the years ended December 31, 2012 because our unrestricted subsidiaries were not formed or were not designated as unrestricted subsidiaries as of December 31, 2012.  

134

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Balance Sheet
December 31, 2014
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	—	$	4.6	$	—	$	—		$	4.6
Accounts receivable	1.2		240.3		—		—			241.5
Accounts receivable - related party	—		—		0.3		—			0.3
Total accounts receivable	1.2		240.3		0.3		—			241.8
Inventories	—		8.0		—		—			8.0
Other current assets	—		18.7		—		—			18.7
Total current assets	1.2		271.6		0.3		—			273.1
Property, plant and equipment, net	7.9		3,510.2		—		—			3,518.1
Goodwill and intangible assets, net	38.0		2,470.8		—		—			2,508.8
Investment in consolidated affiliates	6,296.7		—		—		(6,296.7		)	—
Investment in unconsolidated affiliates	—		—		295.1		—			295.1
Other assets	—		1.4		—		—			1.4
Total assets	$	6,343.8	$	6,254.0	$	295.4	$	(6,296.7	)	$	6,596.5
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	4.8	$	121.3	$	—	$	—		$	126.1
Accounts payable - related party	4.2		1.9		0.2		—			6.3
Total accounts payable	9.0		123.2		0.2		—			132.4
Other current liabilities	23.0		99.7		—		—			122.7
Total current liabilities	32.0		222.9		0.2		—			255.1
Long-term liabilities:
Long-term debt, less current portion	2,012.8		—		—		—			2,012.8
Other long-term liabilities	1.6		29.6		—		—			31.2
Total long-term liabilities	2,014.4		29.6		—		—			2,044.0
Partners' capital	4,125.7		6,001.5		123.5		(6,125.0		)	4,125.7
Interest of non-controlling partners in subsidiaries	171.7		—		171.7		(171.7		)	171.7
Total partners' capital	4,297.4		6,001.5		295.2		(6,296.7		)	4,297.4
Total liabilities and partners' capital	$	6,343.8	$	6,254.0	$	295.4	$	(6,296.7	)	$	6,596.5

135

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Balance Sheet
December 31, 2013
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	0.1	$	1.6	$	1.0	$	—		$	2.7
Accounts receivable	4.4		199.4		0.2		—			204.0
Accounts receivable - related party	1.1		—		—		—			1.1
Total accounts receivable	5.5		199.4		0.2		—			205.1
Inventories	—		7.0		—		—			7.0
Other current assets	—		10.2		—		—			10.2
Total current assets	5.6		218.2		1.2		—			225.0
Property, plant and equipment, net	4.8		3,345.3		—		—			3,350.1
Goodwill and intangible assets, net	46.2		2,607.4		—		—			2,653.6
Investment in consolidated affiliates	6,053.0		—		—		(6,053.0		)	—
Investment in unconsolidated affiliates	—		—		151.4		—			151.4
Other assets	—		21.7		—		—			21.7
Total assets	$	6,109.6	$	6,192.6	$	152.6	$	(6,053.0	)	$	6,401.8
Liabilities and partners' capital
Current liabilities:
Accounts payable	$	15.1	$	139.4	$	—	$	—		$	154.5
Accounts payable - related party	5.4		3.3		—		—			8.7
Total accounts payable	20.5		142.7		—		—			163.2
Other current liabilities	26.4		124.7		0.2		—			151.3
Total current liabilities	46.9		267.4		0.2		—			314.5
Long-term liabilities:
Long-term debt, less current portion	1,867.9		—		—		—			1,867.9
Other long-term liabilities	1.7		24.6		—		—			26.3
Total long-term liabilities	1,869.6		24.6		—		—			1,894.2
Partners' capital	4,092.1		5,900.6		51.4		(5,952.0		)	4,092.1
Interest of non-controlling partners in subsidiaries	101.0		—		101.0		(101.0		)	101.0
Total partners' capital	4,193.1		5,900.6		152.4		(6,053.0		)	4,193.1
Total liabilities and partners' capital	$	6,109.6	$	6,192.6	$	152.6	$	(6,053.0	)	$	6,401.8

136

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	—			179.1			—			—			179.1
NGL and crude services	—			2,040.3			—			—			2,040.3
Related party	—			17.6			—			—			17.6
	—			2,565.5			—			—			2,565.5
Costs of product/services sold:
Gathering and processing	—			29.1			—			—			29.1
Storage and transportation	—			14.3			—			—			14.3
NGL and crude services	—			1,851.9			—			—			1,851.9
Related party	—			42.2			—			—			42.2
	—			1,937.5			—			—			1,937.5
Expenses:
Operations and maintenance	—			139.0			—			—			139.0
General and administrative	49.4			36.0			—			—			85.4
Depreciation, amortization and accretion	0.9			220.8			—			—			221.7
	50.3			395.8			—			—			446.1
Other operating income (expense):
Loss on long-lived assets, net	—			(33.6		)	—			—			(33.6		)
Goodwill impairment	—			(48.8		)	—			—			(48.8		)
Loss on contingent consideration	—			(8.6		)	—			—			(8.6		)
Operating income (loss)	(50.3		)	141.2			—			—			90.9
Loss from unconsolidated affiliates, net	—			—			(0.7		)	—			(0.7		)
Interest and debt expense, net	(111.4		)	—			—			—			(111.4		)
Equity in net income (loss) of subsidiary	139.8			—			—			(139.8		)	—
Income (loss) before income taxes	(21.9		)	141.2			(0.7		)	(139.8		)	(21.2		)
Provision for income taxes	—			0.7			—			—			0.7
Net income (loss)	(21.9		)	140.5			(0.7		)	(139.8		)	(21.9		)
Net (income) loss attributable to non-controlling partners	—			—			(16.8		)	—			(16.8		)
Net income (loss) attributable to Crestwood Midstream Partners LP	(21.9		)	140.5			(17.5		)	(139.8		)	(38.7		)
Net income attributable to Class A preferred units	(17.2		)	—			—			—			(17.2		)
Net income (loss) attributable to partners	$	(39.1	)	$	140.5		$	(17.5	)	$	(139.8	)	$	(55.9	)

137

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

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	—			90.1			—			—			90.1
NGL and crude services	—			270.1			—			—			270.1
Related party	—			82.1			—			—			82.1
	—			658.6			—			—			658.6
Costs of product/services sold:
Gathering and processing	—			24.1			—			—			24.1
Storage and transportation	—			8.7			—			—			8.7
NGL and crude services	—			230.4			—			—			230.4
Related party	—			32.5			—			—			32.5
	—			295.7			—			—			295.7
Expenses:
Operations and maintenance	—			73.3			—			—			73.3
General and administrative	46.5			34.2			—			—			80.7
Depreciation, amortization and accretion	1.0			120.7			—			—			121.7
	47.5			228.2			—			—			275.7
Other operating income (expense):
Gain on long-lived assets, net	—			5.4			—			—			5.4
Goodwill impairment	—			(4.1		)	—			—			(4.1		)
Loss on contingent consideration	—			(31.4		)	—			—			(31.4		)
Operating income (loss)	(47.5		)	104.6			—			—			57.1
Loss from unconsolidated affiliates, net	—			—			(0.1		)	—			(0.1		)
Interest and debt expense, net	(68.7		)	(2.7		)	—			—			(71.4		)
Equity in net income (loss) of subsidiary	101.1			—			—			(101.1		)	—
Income (loss) before income taxes	(15.1		)	101.9			(0.1		)	(101.1		)	(14.4		)
Provision for income taxes	—			0.7			—			—			0.7
Net income (loss)	(15.1		)	101.2			(0.1		)	(101.1		)	(15.1		)
Net (income) loss attributable to non-controlling partners	—			—			(4.9		)	—			(4.9		)
Net income (loss) attributable to Crestwood Midstream Partners LP	$	(15.1	)	$	101.2		$	(5.0	)	$	(101.1	)	$	(20.0	)

138

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2014
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(165.6	)	$	488.5		$	—		$	—		$	322.9
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(19.5		)	—			—			(19.5		)
Purchases of property, plant and equipment	(4.3		)	(402.7		)	—			—			(407.0		)
Investment in unconsolidated affiliates	—			—			(144.4		)	—			(144.4		)
Capital contribution from consolidated affiliates	(89.5		)	—			—			89.5			—
Net cash provided by (used in) investing activities	(93.8		)	(422.2		)	(144.4		)	89.5			(570.9		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,089.9			—			—			—			2,089.9
Principal payments on long-term debt	(1,949.8		)	—			—			—			(1,949.8		)
Payments on capital leases	(1.3		)	(1.9		)	—			—			(3.2		)
Payments for debt-related deferred costs	(0.1		)	—			—			—			(0.1		)
Distributions paid	(368.9		)	—			—			—			(368.9		)
Contributions from parent	—			—			89.5			(89.5		)	—
Net proceeds from issuance of preferred equity of subsidiary	—			—			53.9			—			53.9
Net proceeds from issuance of Class A preferred units	430.5			—			—			—			430.5
Taxes paid for unit-based compensation vesting	—			(1.6		)	—			—			(1.6		)
Change in intercompany balances	59.8			(59.8		)	—			—			—
Other	(0.8		)	—			—			—			(0.8		)
Net cash provided by (used in) financing activities	259.3			(63.3		)	143.4			(89.5		)	249.9
Net change in cash	(0.1		)	3.0			(1.0		)	—			1.9
Cash at beginning of period	0.1			1.6			1.0			—			2.7
Cash at end of period	$	—		$	4.6		$	—		$	—		$	4.6

139

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2013
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(46.1	)	$	266.4		$	—		$	(33.8	)	$	186.5
Cash flows from investing activities:
Acquisitions, net of cash acquired	—			(561.5		)	—			—			(561.5		)
Purchases of property, plant and equipment	(1.0		)	(333.6		)	—			—			(334.6		)
Investment in unconsolidated affiliates	—			—			(151.5		)	—			(151.5		)
Capital contribution from consolidated affiliates	(106.4		)	—			—			106.4			—
Other	—			11.1			—			—			11.1
Net cash provided by (used in) investing activities	(107.4		)	(884.0		)	(151.5		)	106.4			(1,036.5		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	1,930.9			141.9			—			—			2,072.8
Principal payments on long-term debt	(1,559.3		)	(75.0		)	—			—			(1,634.3		)
Payments on capital leases	(0.4		)	(3.9		)	—			—			(4.3		)
Payments for debt-related deferred costs	(32.0		)	—			—			—			(32.0		)
Distributions paid	(359.7		)	(33.8		)	—			33.8			(359.7		)
Contributions from parent	—			55.5			56.4			(106.4		)	5.5
Net proceeds from issuance of common units	714.0			—			—			—			714.0
Net proceeds from issuance of preferred equity of subsidiary	—			—			96.1			—			96.1
Taxes paid for unit-based compensation vesting	—			(5.5		)	—			—			(5.5		)
Change in intercompany balances	(539.9		)	539.9			—			—			—
Net cash provided by (used in) financing activities	153.6			619.1			152.5			(72.6		)	852.6
Net change in cash	0.1			1.5			1.0			—			2.6
Cash at beginning of period	—			0.1			—			—			0.1
Cash at end of period	$	0.1		$	1.6		$	1.0		$	—		$	2.7

140

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 16 - 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	$	537.0			$	675.7		$	738.4		$	614.4
Operating income (loss)	34.4				42.3			48.7			(34.5		)	(1)
Earnings (loss) from unconsolidated affiliates, net	(0.1		)		(1.5		)	0.3			0.6
Net income (loss)	5.5				11.7			21.3			(60.4		)
Net income (loss) attributable to partners	2.4				6.9			7.7			(72.9		)
Net income (loss) per limited partner unit:
Basic	$	(0.03	)		$	—		$	—		$	(0.43	)
Diluted	$	(0.03	)		$	—		$	—		$	(0.43	)
2013
Revenues	$	72.4			$	80.1		$	140.1		$	366.0
Operating income (loss)	20.7				19.5			31.8			(14.9		)	(2)
Earnings (loss) from unconsolidated affiliates, net	—				—			(0.4		)	0.3
Net income (loss)	8.9				6.7			11.6			(42.3		)
Net income (loss) attributable to partners	8.9				6.7			9.7			(45.3		)
Net income (loss) per limited partner unit:
Basic(4)	$	0.06		(3)	$	(0.01	)	$	0.02		$	(0.50	)
Diluted(4)	$	0.06		(3)	$	(0.01	)	$	0.02		$	(0.50	)

(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.

(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 each of the quarters ended September 30, 2013, were computed based on the number of common units issued by Legacy Inergy to Legacy Crestwood unitholders as part of the Crestwood Merger.

(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.

141

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		CRESTWOOD MIDSTREAM PARTNERS LP
		By:	Crestwood Midstream GP, LLC
			(its general partner)
Date:	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 Midstream GP, LLC, as general partner of Crestwood Midstream Partners, L.P., 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/    PHILIP D. GETTIG Philip D. Gettig, Director
February 27, 2015	/S/    WARREN H. GFELLER Warren H. Gfeller, Director
February 27, 2015	/S/    DAVID LUMPKINS David Lumpkins, Director
February 27, 2015	/S/    JOHN J. SHERMAN John J. Sherman, Director
February 27, 2015	/S/    DAVID M. WOOD David M. Wood, Director

142