10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

OR

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

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

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

(832) 519-2200

(Registrant’s telephone number, including area code)

___________________________________________

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

	Title of each class	Trading Symbol	Name of each exchange on which registered
Crestwood Equity Partners LP	Common Units representing limited partnership interests	CEQP	New York Stock Exchange
Crestwood Equity Partners LP	Preferred Units representing limited partner interests	CEQP-P	New York Stock Exchange
Crestwood Midstream Partners LP	None	None	None

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

Crestwood Equity Partners LP	None
Crestwood Midstream Partners LP	None

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

Crestwood Equity Partners LP	Yes	☒	No	☐
Crestwood Midstream Partners LP	Yes	☐	No	☒

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

Crestwood Equity Partners LP	Yes	☐	No	☒
Crestwood Midstream Partners LP	Yes	☐	No	☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

Crestwood Equity Partners LP	Yes	☒	No	☐
Crestwood Midstream Partners LP	Yes	☒	No	☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted 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 such files).

Crestwood Equity Partners LP	Yes	☒	No	☐
Crestwood Midstream Partners LP	Yes	☒	No	☐

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

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

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

Crestwood Equity Partners LP	☐
Crestwood Midstream Partners LP	☐

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

Crestwood Equity Partners LP	Yes	☐	No	☒
Crestwood Midstream Partners LP	Yes	☐	No	☒

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (June 28, 2019).

Crestwood Equity Partners LP	$1.8 billion
Crestwood Midstream Partners LP	None

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date (February 10, 2020).

Crestwood Equity Partners LP	$26.45 per common unit	72,725,966
Crestwood Midstream Partners LP	None	None

DOCUMENTS INCORPORATED BY REFERENCE

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

Crestwood Equity Partners LP	None
Crestwood Midstream Partners LP	None

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

FILING FORMAT

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

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

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CRESTWOOD EQUITY PARTNERS LP

CRESTWOOD MIDSTREAM PARTNERS LP

INDEX TO ANNUAL REPORT ON FORM 10-K

		Page
	PART I
Item 1.	Business	6
Item 1A.	Risk Factors	25
Item 1B.	Unresolved Staff Comments	47
Item 2.	Properties	47
Item 3.	Legal Proceedings	47
Item 4.	Mine Safety Disclosures	47
	PART II
Item 5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	48
Item 6.	Selected Financial Data	49
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	51
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	69
Item 8.	Financial Statements and Supplementary Data	70
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	70
Item 9A.	Controls and Procedures	71
Item 9B.	Other Information	72
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	73
Item 11.	Executive Compensation	78
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	91
Item 13.	Certain Relationships and Related Transactions, and Director Independence	92
Item 14.	Principal Accountant Fees and Services	94
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	95

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GLOSSARY

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

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

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PART I

Item 1. Business

Unless the context requires otherwise, references to (i) “we,” “us,” “our,” “ours,” “our company,” the “Company,” the “Partnership,” “Crestwood Equity,” “CEQP,” and similar terms refer to either Crestwood Equity Partners LP itself or Crestwood Equity Partners LP and its consolidated subsidiaries, as the context requires, and (ii) “Crestwood Midstream” and “CMLP” refers to Crestwood Midstream Partners LP and its consolidated subsidiaries. Unless otherwise indicated, information contained herein is reported as of December 31, 2019.

Introduction

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

Crestwood Equity is a holding company. All of our consolidated operating assets are owned by or through our wholly-owned subsidiary, Crestwood Midstream, a Delaware limited partnership. In addition, through our equity investments in joint ventures, we have ownership interests in their respective operating assets. Our operating assets, including those of our joint ventures, primarily include:

• natural gas facilities with approximately 3.3 Bcf/d of gathering capacity, 1.0 Bcf/d of processing capacity, 75.8 Bcf of certificated working storage capacity and 1.8 Bcf/d of operational transportation capacity;

• crude oil facilities with approximately 150,000 Bbls/d of gathering capacity, 1.9 MMBbls of storage capacity, 20,000 Bbls/d of transportation capacity and 180,000 Bbls/d of rail loading capacity;

• NGL facilities with approximately 2.6 MMBbls of storage capacity, as well as our portfolio of transportation assets (consisting of truck and rail terminals, truck/trailer units and rail cars) capable of transporting approximately 1.3 MMBbls/d of NGLs; and

• produced water gathering facilities with approximately 110,000 Bbls/d of gathering capacity.

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Ownership Structure

The diagram below reflects a simplified version of our ownership structure as of December 31, 2019:

Crestwood Equity. Crestwood Equity GP LLC, which is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), owns our non-economic general partnership interest. Crestwood Holdings, which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve), also owns approximately 25% of Crestwood Equity’s common units and all of its subordinated units as of December 31, 2019.

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

Our Assets

Our financial statements reflect three operating and reporting segments, including (i) gathering and processing (G&P); (ii) storage and transportation (S&T); and (iii) marketing, supply and logistics (MS&L), which are described below.

Gathering and Processing

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

The table below summarizes certain information about our G&P operations (including our equity investment and its operations) as of December 31, 2019:

Shale Play (State)	Counties	Pipeline (Miles)	Gathering Capacity	2019 Average Gathering Volumes	Compression (HP)	Number of In-Service Processing Plants	Processing Capacity (MMcf/d)	Gross Acreage Dedication
Bakken North Dakota	McKenzie and Dunn	702(1)	150 MMcf/d - natural gas gathering 150 MBbls/d - crude oil gathering 110 MBbls/d - water gathering	88 MMcf/d - natural gas gathering  104 MBbls/d - crude oil gathering  69 MBbls/d - produced water gathering	79,520	2	150	150,000
Powder River Basin Wyoming	Converse	255	199 MMcf/d	145 MMcf/d	65,335	1	145	289,000
Marcellus West Virginia	Harrison and Doddridge	74	875 MMcf/d	296 MMcf/d	131,380	—	—	140,000
Barnett Texas	Hood, Somervell, Tarrant, Johnson and Denton	507	925 MMcf/d	248 MMcf/d	153,465	1	425	140,000
Fayetteville Arkansas	Conway, Faulkner, Van Buren, and White	173	510 MMcf/d	33 MMcf/d	18,670	—	—	143,000
Delaware Permian (2)  New Mexico/Texas	Eddy (New Mexico) Loving, Reeves, Ward, Culberson (Texas)	295	650 MMcf/d	182 MMcf/d	86,410 (3)	2	255	329,000

(1) Consists of 311 miles of natural gas gathering pipeline, 195 miles of crude oil gathering pipeline, and 196 miles of produced water gathering pipeline.

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

(3) Includes 55,080 HP that is owned and operated by a third party under a compression services agreement.

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

Bakken

We own and operate an integrated crude oil, natural gas and produced water gathering system and gas processing facility (the Arrow system) in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota, some of which is located on

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the Fort Berthold Indian Reservation.  Located approximately 60 miles southeast of the COLT Hub, the Arrow system connects to our COLT Hub through the Kinder Morgan Inc.’s (Kinder Morgan) Double H Pipeline system and Tesoro High Plains Pipeline Company LLC, a subsidiary of Marathon Petroleum Corporation (Marathon), crude oil pipeline systems, as well as to Patoka, Illinois and Gulf Coast markets through the Dakota Access Pipeline (DAPL) interstate pipeline system.  The Arrow system consists of approximately 702 miles of low-pressure gathering pipelines, a 23-acre central delivery point with 266,000 Bbls of crude oil working storage capacity and multiple pipeline take-away outlets, salt water disposal wells, as well as a 150 MMcf/d natural gas processing facility (Bear Den) and associated pipelines that fulfill 100% of the processing requirements for producers on the Arrow system. Our operations are anchored by long-term gathering contracts and our underlying contracts largely provide for fixed-fee gathering services with annual escalators for crude oil, natural gas and produced water gathering services.

Powder River Basin

In April 2019, Crestwood Niobrara acquired Williams’ 50% equity interest in Jackalope, and as a result of the acquisition, Crestwood Niobrara controls and owns 100% of the equity interest in Jackalope. The Jackalope gas gathering system serves a 289,000 gross acre dedication operated by Chesapeake Energy Corporation (Chesapeake) in Converse County, Wyoming. The Jackalope system consists of approximately 255 miles of gathering pipelines, 65,335 horsepower of compression and a 145 MMcf/d processing plant (Bucking Horse). The system connects to 160 well pads and is supported by a 20-year gathering and processing agreement with Chesapeake that includes minimum revenue guarantees for a five to seven year period. We are expanding the Jackalope system and the Bucking Horse plant to include gathering, compression and a second 200 MMcf/d processing plant which will increase processing capacity to 345 MMcf/d in early 2020.

Marcellus

We own and operate natural gas gathering and compression systems in Harrison and Doddridge Counties, West Virginia. These systems consist of 74 miles of low pressure gathering lines and nine compression and dehydration stations with 131,380 horsepower. Through these systems, we provide midstream services under long-term, fixed-fee contracts across two operating areas: our eastern area of operation (East AOD), where we are the exclusive gatherer, and our western area of operation (West AOD), where we provide compression services.

In the East AOD, we provide gathering, dehydration and compression services on a fixed-fee basis. We gather and ultimately redeliver our customers’ natural gas to MarkWest Energy Partners, L.P.’s Sherwood gas processing plant and various regional pipeline systems. In the West AOD, we provide compression and dehydration services on a fixed-fee basis predominantly utilizing our West Union and Victoria compressor stations, each with a maximum capacity of 120 MMcf/d. Our agreements provide for a minimum volume commitment of approximately 50% of the throughput capacity of each compressor station through 2021.

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, Texas Basin, consists of pipelines that gather rich gas produced by customers and deliver the volumes to our Cowtown processing 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. Our Lake Arlington system, which is located in eastern Tarrant County, Texas, consists of a dry gas gathering system and related dehydration and compression facilities. Our Alliance system, which is located in northern Tarrant and southern Denton Counties, Texas, consists of a dry gas gathering system and a related dehydration, compression and amine treating facility.

Fayetteville

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

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Equity Investment

Delaware Permian

Our gathering and processing segment includes our 50% equity interest in the Crestwood Permian joint venture, which we account for under the equity method of accounting. Crestwood Infrastructure Holdings LLC (Crestwood Infrastructure), our wholly-owned subsidiary, and an affiliate of First Reserve formed the joint venture in October 2016. We operate and manage the joint venture under a long-term agreement. Crestwood Permian owns low-pressure dry gas and rich natural gas gathering systems with a primary focus on the Willow Lake system, which includes approximately 55 MMcf/d of processing capacity that serves customers in Eddy County, New Mexico. The joint venture owns a 200 MMcf/d natural gas processing facility in Orla, Texas, (the Orla plant) and the Orla Express Pipeline, a 33 mile, 20-inch high pressure line connecting the existing Willow Lake system with the Orla plant.

Crestwood Permian also owns an undivided interest in 80,000 Bbls/d of capacity in a segment of the Epic Y-Grade Pipeline, LP (EPIC) pipeline from Orla, Texas to Benedum, Texas, where the pipeline interconnects with Chevron Phillips Chemical Company, LP’s (Chevron Phillips) pipeline. This capacity is supported by a purchase and sale agreement with Chevron Phillips to sell a dedicated volume of barrels to be delivered off the EPIC pipeline to Chevron Phillips’ pipeline. Crestwood Permian’s ownership in the EPIC pipeline provides a competitive NGL takeaway solution to allow Crestwood Permian to grow its footprint in the Delaware Basin. Crestwood Permian is well positioned to securely and economically move Orla NGL products into Gulf Coast markets, which provides its customers optionality and flow assurance that creates a unique competitive advantage for us. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in Crestwood Permian.

The Crestwood Permian joint venture owns a 50% equity interest in Crestwood Permian Basin and Shell Midstream Partners L.P. (Shell Midstream), a subsidiary of Royal Dutch Shell plc, owns the remaining 50% equity interest in Crestwood Permian Basin. Crestwood Permian Basin has a long-term agreement with SWEPI LP (SWEPI), a subsidiary of Royal Dutch Shell plc, to own and operate the Nautilus gathering system in SWEPI’s operated position in the Delaware Permian. Crestwood Permian Basin provides gathering, dehydration and treating services to SWEPI under a long-term fixed-fee gathering agreement. SWEPI has dedicated to Crestwood Permian Basin the gathering rights for SWEPI’s gas production across a large acreage position in Loving, Reeves and Ward Counties, Texas. The Nautilus gathering system includes 83 receipt point meters, 154 miles of pipeline, a 41-mile high pressure header system, 55,080 horsepower of compression and seven high pressure delivery points. The Nautilus gathering system will be expanded over time, as production increases, to include additional gathering lines and centralized compression facilities which will ultimately provide over 250 MMcf/d of gas gathering capacity.

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The table below summarizes certain contract information of our G&P operations (including our equity investment and its operations) as of December 31, 2019:

Shale Play	Type of Services	Type of Contracts(1)	Gross Acreage Dedication	Major Customers	Weighted Average Remaining Contract Terms (in years)
Bakken	Gathering - crude oil, natural gas and water	Mixed	150,000	WPX Energy (WPX), Bruin E&P Partners, LLC (Bruin), Rimrock Oil & Gas, LP (Rimrock), XTO Energy Inc. (XTO)	10
	Processing - natural gas	Mixed	—	WPX, Bruin, Rimrock, XTO	10
Powder River Basin	Gathering	Fixed-fee	289,000	Chesapeake	17
	Processing	Fixed-fee	—	Chesapeake	17
Marcellus	Gathering	Fixed-fee	140,000	Antero Resources Corporation (Antero)	12
	Compression	Fixed-fee	—	Antero	1
Barnett	Gathering	Mixed	140,000	Blackbeard Operating, LLC (Blackbeard), Newark Acquisition I L.P. (Newark), Tokyo Gas America Ltd. (Tokyo Gas)	6
	Processing	Mixed	—	Blackbeard, Newark, Tokyo Gas	6
Fayetteville	Gathering	Fixed-fee	143,000	Merit Energy Company (Merit)	5
	Treating	Fixed-fee	—	Merit	5
Delaware Permian	Gathering	Fixed-fee	329,000	Mewbourne Oil Company (Mewbourne), Concho Resources (Concho), Marathon, SWEPI	15
	Processing	Mixed	—	Mewbourne, Concho, Marathon, SWEPI	1

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

We provide gathering, processing, compression, storage and transportation services under a variety of contracts. Although the cash flows from our G&P operations are predominantly fee-based under contracts with original terms ranging from 5-20 years, the results of our G&P operations are significantly influenced by the volumes gathered and processed through our systems. The cash flows from our G&P operations can also be impacted in the short term by changing commodity prices, seasonality, weather fluctuations and the financial condition of our customers. Our election to enter primarily into fixed-fee contracts subject to acreage dedication helps minimize our G&P segment’s long-term exposure to commodity prices and its impact on the financial condition of our customers, and provides us more stable operating performance and cash flows. In November 2019, Chesapeake, our major customer in the Powder River Basin, announced that continued low commodity prices could negatively impact their cash flows and financial condition, and raised substantial doubt about its ability to continue as a going concern given the financial covenants contained in their debt agreements. Subsequent to that announcement, Chesapeake announced that it had refinanced certain amounts of its debt and amended its debt covenants to alleviate certain of its liquidity concerns. We continue to gather and process natural gas volumes under our contracts with Chesapeake, and currently do not anticipate any material short-term negative impacts to our financial results related to their financial condition.

Storage and Transportation

Our S&T segment includes our COLT Hub, one of the largest crude-by-rail terminals serving Bakken crude oil production, and our equity investments in three joint ventures that own five high-performance natural gas storage facilities with an aggregate certificated working gas storage capacity of approximately 75.8 Bcf, three natural gas pipeline systems with an aggregate operational transportation capacity of 1.8 Bcf/d, and crude oil facilities with approximately 380,000 Bbls of working storage capacity and 20,000 Bbls/d of rail loading capacity.

COLT Hub

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

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pipeline systems at Dry Fork. The pipelines connected to the COLT Hub can deliver up to approximately 290,000 Bbls/d of crude oil to our terminal.

Equity Investments

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

Northeast Storage Facilities. Our storage and transportation segment includes our 50% equity interest in Stagecoach Gas Services LLC (Stagecoach Gas), which we account for under the equity method of accounting. Our wholly-owned subsidiary, Crestwood Pipeline and Storage Northeast LLC (Crestwood Northeast) and Con Edison Gas Pipeline and Storage Northeast, LLC (CEGP), a wholly-owned subsidiary of Consolidated Edison, Inc. (Consolidated Edison), formed Stagecoach Gas to own and further develop our natural gas storage and transportation business located in the Northeast (the NE S&T assets). We manage the joint venture’s operations under a long-term management agreement. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in Stagecoach Gas.

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

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

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

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

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

Tres Palacios Storage Facility. Our storage and transportation segment includes our 50.01% equity interest in Tres Palacios Holdings LLC (Tres Holdings), which we account for under the equity method of accounting. Brookfield Infrastructure Group owns the remaining 49.99% equity interest in Tres Holdings. We manage the joint venture’s operations under a long-term management agreement.

Tres Palacios Gas Storage LLC (Tres Palacios), a wholly-owned subsidiary of Tres Holdings, owns a FERC-certificated 34.9 Bcf multi-cycle salt dome natural gas storage facility located in Markham, Texas. The Tres Palacios natural gas storage facility’s 63-mile, dual 24-inch diameter header system (including a 52-mile north pipeline lateral and an approximate 11-mile south pipeline lateral) interconnects with 11 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan’s Houston central processing plant. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment interest in Tres Holdings.

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The table below provides additional information about our S&T equity investments’ natural gas storage facilities as of December 31, 2019:

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

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

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

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

• North-South Facilities - bi-directional interstate facilities which include compression and appurtenant facilities installed to expand transportation capacity on the Stagecoach north and south pipeline laterals. 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, bi-directional interstate natural gas pipeline that connects the North-South Facilities and TGP’s 300 Line in Bradford County, Pennsylvania, with UGI’s Sunbury Pipeline and Transco’s Leidy Line, both in Lycoming County, Pennsylvania. The MARC I Pipeline generates fee-based revenues under a negotiated rate structure authorized by the FERC.

• Twin Tier Pipeline (formerly East Pipeline) - a 37.5 mile, 12-inch diameter intrastate natural gas pipeline located in New York, which transports natural gas from Dominion to the Binghamton, New York city gate. The pipeline runs within three miles of the North-South Facilities’ point of interconnection with Millennium. The Twin Tier Pipeline generates fee-based revenues under a negotiated rate structure authorized by the New York State Public Service Commission.

Rail Loading Facility. Our storage and transportation segment includes our 50.01% equity interest in Powder River Basin Industrial Complex, LLC (PRBIC), which we account for under the equity method of accounting. PRBIC owns an integrated crude oil loading, storage and pipeline terminal located in Douglas County, Wyoming. PRBIC, which is operated by our joint venture partner, Twin Eagle Resource Management, LLC (Twin Eagle), sources crude oil production from Chesapeake and other Powder River Basin producers. PRBIC includes 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of crude oil working storage capacity. The pipeline terminal includes connections to Kinder Morgan’s Double H Pipeline system and Plains All American Pipeline’s Rocky Mountain Pipeline system. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for a further discussion of our investment in PRBIC.

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The table below summarizes certain contract information about our S&T operations (including our equity investments) as of December 31, 2019:

Facility	Type of Services	Type of Contracts(1)(2)	Contract Volumes	Major Customers	Weighted Average Remaining Contract Terms (in years)
COLT	Rail Loading and Transportation	Mixed	41 MBbl/d	British Petroleum (BP), Flint Hills Resources, Sunoco Logistics	1
NE S&T Joint Venture:
North-South Facilities	Transportation	Firm	530 MMcf/d	Southwestern Energy, Consolidated Edison	2
MARC I Pipeline	Transportation	Firm	1,064 MMcf/d	Chesapeake, Chief Oil and Gas, Alta Energy Marketing, Equinor Natural Gas LLC	2
Twin Tier Pipeline	Transportation	Firm	30 MMcf/d	NY State Electric & Gas Corp	1
Stagecoach	Storage	Firm	21.4 Bcf	Consolidated Edison, New Jersey Natural Gas, Morgan Stanley Capital Group, Sequent Energy Management (Sequent)	3
Thomas Corners	Storage	Firm	6.7 Bcf	Tenaska Gas Storage, LLC (Tenaska), Engie Energy Marketing, Green Plains Trade Group, Citadel LLC, Castleton Commodities International, LLC	1
Seneca Lake	Storage	Firm	1.5 Bcf	NY State Electric & Gas Corp, DTE Energy Trading, Texla Energy Management	1
Steuben	Storage	Firm	5.2 Bcf	Sequent, Tenaska	1
Tres Palacios Joint Venture	Storage	Firm	28.5 Bcf	Brookfield Infrastructure Group, Trafigura Trading LLC, Hartree Partners, LP, EDF Energy, Sequent, BP	1
PRBIC Joint Venture	Rail Loading and Transportation	Fixed-fee	—	Chesapeake, Twin Eagle	Month-to-month

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

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

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

Marketing, Supply and Logistics

Our MS&L segment consists of our NGL, crude oil and natural gas marketing and logistics operations. We utilize our trucking and rail fleet, processing and storage facilities, and contracted storage and pipeline capacity on a portfolio basis to provide integrated supply and logistics solutions to producers, refiners and other customers.

Our NGL marketing and logistics operations primarily include:

• A fleet of rail and rolling stock with 1,155,000 Bbls/d of NGL transportation capacity, which also includes our rail-to-truck terminals located in Florida, New Jersey, New York, Rhode Island, North Carolina and Connecticut.

• A fleet of owned and leased trucks with 20,000 Bbls/d of crude oil transportation capacity and 100,000 Bbls/d of NGL transportation capacity. We provide hauling services to customers in over 30 states from New Mexico to Maine.

• Our Bath and Seymour storage facilities. The Bath storage facility is located in Bath, New York and has approximately 2.1 MMBbls of underground NGL storage capacity and is supported by rail and truck terminal facilities capable of loading and unloading 23 rail cars per day and approximately 100 truck transports per day. The Seymour storage facility is located in Seymour, Indiana, and has 500,000 Bbls of underground NGL storage capacity and 29,000 Bbls of aboveground “bullet” storage capacity. The Seymour facility’s receipts and deliveries are supported by Enterprise’s TEPPCO pipeline, allowing pipeline and truck access.

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• NGL pipeline and storage capacity leased from third parties, including more than 750,000 Bbls of NGL working storage capacity at major hubs in Mt. Belvieu, Texas and Conway, Kansas.

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

Customers

For the year ended December 31, 2019, British Petroleum and its affiliates accounted for approximately 10% of our total consolidated revenues. For the years ended December 31, 2018 and 2017, no customer accounted for more than 10% of our total consolidated revenues.

Industry Background

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

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

Crude Oil

Pipelines typically provide a cost-effective and safe 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.

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Natural Gas

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

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

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

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

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

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

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

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

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pentanes and heavier hydrocarbons in the NGL stream, and (iv) butane splitter (or deisobutanizer), which separates isobutanes and normal butanes.

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

Competition

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

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

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

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

Regulation

Our operations and investments are subject to extensive regulation by federal, state and local authorities. The regulatory burden on our operations increases our cost of doing business and, in turn, impacts our profitability. In general, midstream companies have experienced increased regulatory oversight over the past few years.

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Pipeline and Underground Storage Safety

We are subject to pipeline safety regulations imposed by the U.S. Department of Transportation Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA regulates safety requirements in the design, construction, operation and maintenance of jurisdictional natural gas and hazardous liquid pipeline and storage facilities. All of our natural gas pipelines used in gathering, storage and transportation activities are subject to regulation by PHMSA under the Natural Gas Pipeline Safety Act of 1968, as amended (NGPSA), and all of our NGL and crude oil pipelines used in gathering, storage and transportation activities are subject to regulation by PHMSA as hazardous liquids pipelines under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (HLPSA).

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

We plan to continue testing under our pipeline integrity management programs to assess and maintain the integrity of our pipelines in accordance with PHMSA regulations. Notwithstanding our preventive and investigatory maintenance efforts, we may incur significant expenses if anomalous pipeline conditions are discovered or due to the implementation of more stringent pipeline safety standards resulting from new or amended legislation. For example, the NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act), which requires increased safety measures for gas and hazardous liquids transportation pipelines. Among other things, the 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. More recently, in June 2016, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Pipeline Safety Act) was passed, extending PHMSA’s statutory mandate through September 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and developing new safety standards for natural gas storage facilities by June 2018. Following adoption of the 2016 Pipeline Safety Act, PHMSA published an interim rule in December 2016 that imposed new safety-related requirements on downhole facilities (including wells, wellbore tubing and casing) of new and existing underground natural gas storage facilities. However, in June 2017, PHMSA temporarily suspended specific enforcement actions pertaining to provisions that had previously been non-mandatory provisions prior to incorporation into the December 2016 interim final rule, as PHMSA announced it would reconsider the interim final rule. PHMSA re-opened the rule to public comment in October 2017. The Unified Agenda issued by the federal government published a July 2019 date for issuance of a final rule in replacement of this interim rule but no final rule has yet been issued. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA issued interim regulations in October 2016, to implement the agency's expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment. Because the 2016 Pipeline Safety Act reauthorized PHMSA’s hazardous liquid and gas pipeline programs only through September 2019, we anticipate that Congress will issue an updated pipeline safety law in 2020 that will reauthorized those programs through 2023. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act, and any new Congressional pipeline safety legislation that is anticipated to be introduced to reauthorize PHMSA pipeline safety programs, as well as any implementation of PHMSA regulations thereunder, or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

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

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Future environmental regulatory developments, such as more strict environmental laws or regulations, or more stringent enforcement of the existing regulatory requirements could also directly affect our operations and investments. For example, in June 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage facilities. These standards will require the use of certain specific emissions control practices, thereby requiring additional controls for pneumatic controllers and pumps, as well as compressors, and imposing leak detection and repair requirements for natural gas compressor and booster stations. However, in September 2019, the EPA published a proposed rulemaking amending the June 2016 regulations that, among other things, would remove sources in the transmission and storage segment from the oil and natural gas source category and rescind the methane-specific requirements applicable to sources in the production and processing segments of the industry. As an alternative, the EPA is also proposing to rescind the methane-specific requirements that apply to all sources in the oil and natural gas industry, without removing the transmission and storage sources from the current source category. Under either alternative, the EPA plans to retain emissions limits for volatile organic compounds. The EPA proposed rulemaking indicates that the controls to reduce volatile organic compound emissions also reduce methane at the same time, so separate methane limitations for these segments of the industry are redundant. Public comments on the proposed rulemaking were due to be submitted by November 25, 2019. Whether these proposed standards may become implemented, on what date and exactly what they will require is unknown at this time.

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

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

Natural Gas Gathering

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

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

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

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

NGL Storage

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

Crude Oil Transportation

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

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, the NDIC approved additional requirements relating to site construction, underground gathering pipelines, spill containment, bonding for underground gathering pipelines, and construction of berms around facilities. Additionally, the NDIC issued an order wherein the agency adopted legally enforceable “gas capture percentage goals” requiring our customers to capture certain percentages of natural gas produced by specified dates (Gas Capture Order). The Gas Capture Order was subsequently modified in 2018. Exploration and production operators in the state may be required to install new equipment to satisfy these goals, and any failure by operators to meet these gas capture percentage goals would subject those operators to production restrictions, which could reduce the amount of commodities we gather on the Arrow system from our customers, and have a corresponding adverse impact on our business and results of operations.

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

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

In recent years, PHMSA and other federal agencies have reviewed the adequacy of transporting Bakken crude oil by rail transport and, as necessary have pursued rules to better assure the safe transport of Bakken crude oil by rail. For example, PHMSA adopted a final rule that includes, among other things, providing new sampling and testing requirements to improve classification of Bakken crude oil transported.  Additionally in 2016, PHMSA published a final rule mandating a phase-out schedule for all DOT-111 tank cars used to transport Class 3 flammable liquids, including crude oil and ethanol, between 2018 and 2029 and, and more recently in February 2019, PHMSA published a final rule requiring railroads to develop and submit comprehensive oil spill response plans for specific route segments traveled by a single train carrying 20 or more loaded tanks of liquid petroleum oil in a continuous block or a single train carrying 35 or more loaded tank cars of liquid petroleum oil throughout the train. Additionally, that February 2019 final rule requires railroads to establish geographic response zones along various rail routes, ensure that both personnel and equipment are staged and prepared to respond in the event of an accident, and share information about high-hazard flammable train operations with state and tribal emergency response commissions. We, as the owner of a Bakken crude loading terminal, may be adversely affected to the extent more stringent rail transport rules result in more significant operating costs in the shipment of Bakken crude oil by rail or as a result of delays or limitations of such shipments. 

Natural Gas Storage and Transportation

Our equity investments’ natural gas pipelines used in gathering, storage and transportation activities are subject to regulation under NGPSA. On December 14, 2016, PHMSA issued final interim rules that impose new safety related requirements on downhole facilities (including wells, wellbore tubing and casing) of new and existing underground natural gas storage facilities. The final interim rules adopt and make mandatory two American Petroleum Institute Recommend Practices that, among other things, address construction, maintenance, risk-management and integrity-management procedures. PHMSA indicated when it issued the interim final rule that the adoption of these safety standards for natural gas storage facilities represent a first step in a multi-phase process to enhance the safety of underground natural gas storage, with more standards likely forthcoming. However, in June 2017, PHMSA temporarily suspended specific enforcement actions pertaining to provisions that had previously been non-mandatory provisions prior to incorporation into the December 2016 interim final rule, as PHMSA announced it would reconsider the interim final rule. PHMSA re-opened the rule to public comment in October 2017. The Unified Agenda issued by the federal government published a July 2019 date for issuance of a final rule in replacement of this interim final rule but no final rule has yet been issued. At this time, we cannot predict the impact of any future regulatory actions in this area. To the extent we operate or manage natural gas storage facilities owned by our equity investments, we have evaluated the final interim rules and do not anticipate any significant impact on our equity investments or any significant increase in the costs of operating and maintaining natural gas storage facilities.

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

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

In addition, the Energy Policy Act of 2005 amended the Natural Gas Act to (i) prohibit market manipulation by any entity; (ii) direct the FERC to facilitate market transparency in the market for sale or transportation of physical natural gas in interstate commerce; and (iii) significantly increase the penalties for violations of the Natural Gas Act, the Natural Gas Policy Act of 1978, and FERC rules, regulations or orders thereunder. As a result of the Energy Policy Act of 2005, the FERC has the authority to impose civil penalties for violations of these statutes and FERC rules, regulations and orders, up to approximately $1.3 million per day, per violation.

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

Marketing, Supply and Logistics

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

Environmental and Occupational Safety and Health Matters

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

During September 2019, we experienced two produced water releases totaling approximately 5,000 barrels on our Arrow system located on the Fort Berthold Indian Reservation in North Dakota. We immediately notified the National Response Center, the State of North Dakota, the Three Affiliated Tribes, affected landowners and numerous other regulatory authorities. We have substantially completed the remediation efforts for both spills and we believe our remediation efforts are insurable events under our insurance policies.

Employees

As of February 10, 2020, we had 894 full-time employees, 352 of which were general and administrative employees and 542 of which were operational employees. We believe that our relationship with our employees is satisfactory.

Available Information

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

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

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Item 1A. Risk Factors

Risks Inherent in Our Business

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

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

• changes in general domestic and global economic and political conditions;

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

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

• competition from imported supplies and alternate fuels;

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

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

• impact of interest rates on economic activity;

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

• operational hazards, including terrorism, cyber-attacks or domestic vandalism;

• 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 increase, because of increased production capacity or otherwise, the demand for our services and the prices that we will be able to charge for those services may decline. In addition to volatility and seasonality, an extended period of low commodity prices, as the industry is currently experiencing, could adversely impact storage and transportation values for some period of time until market conditions adjust. With West Texas Intermediate crude oil prices ranging from $46.31 to $66.24 per barrel in 2019, the sustainability of recent price improvements and longer-term oil prices cannot be predicted. These commodity price impacts could have a negative impact on our business, financial condition, and results of operations.

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

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

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

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

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

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

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

The significant volatility in energy commodity prices in recent years has led to an increased concern by energy investors regarding the future outlook for the industry. This has resulted in historic increased trading volatility. Our growth strategy depends on our ability to identify, develop and contract for new growth projects and raise the investment capital, at a reasonable cost of capital, required to generate accretive returns from the growth project. This trend may continue and could negatively impact our ability to grow for any of the following reasons:

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

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

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

The growth projects we complete may not perform as anticipated.

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

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

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

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

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

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

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

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

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

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

Certain of our operations and investments depend on assets owned and controlled by third parties to operate effectively. For example, (i) certain of our “rich gas” gathering systems depend on interconnections, compression facilities and processing plants owned by third parties for us to move gas off our systems; (ii) our crude oil gathering systems depend on third-party pipelines to move crude to demand markets or rail terminals and our crude oil rail terminals depend on railroad companies to move our customers’ crude oil to market; and (iii) our natural gas storage facilities rely on third-party interconnections and

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pipelines to receive and deliver natural gas. Since we do not own or operate these third-party facilities, their continuing operation is outside of our control. If third-party facilities become unavailable or constrained, or other downstream facilities utilized to move our customers’ product to their end destination become unavailable, it could have a material adverse effect on our business, financial condition, results of operations, and ability to make distributions.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value of our assets based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. This differs from our evaluation of goodwill, which is evaluated for impairment annually on December 31, and whenever events indicate that it is more likely than not that the fair value of a reporting unit could be less than the carrying amount. This evaluation requires us to compare the fair value of each of our reporting units primarily utilizing discounted cash flows, to its carrying value (including goodwill). If the fair value exceeds the carrying value amount, goodwill of the reporting unit is not considered impaired.

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Under GAAP, during the year ended December 31, 2017, we were required to record $121.0 million of long-lived asset and goodwill impairments related to certain of our reporting units because changes in circumstances or events indicated that the carrying values of such assets exceeded their fair value and were not recoverable.

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

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

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

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

We had approximately $2.4 billion of long-term debt outstanding as of December 31, 2019. If we are unable to generate sufficient cash flow to satisfy debt obligations or to obtain alternative financing, that 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 investments, or cause us to make non-strategic divestitures;

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

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

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

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

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

• incur additional debt;

• make distributions on or redeem or repurchase units;

• make investments and acquisitions;

• incur or permit certain liens to exist;

• enter into certain types of transactions with affiliates;

• merge, consolidate or amalgamate with another company; and

• transfer or otherwise dispose of assets.

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

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

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

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

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

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

Historically, we have used cash flow from operations, borrowings under our revolving credit facilities and issuances of debt or equity to fund our capital programs, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our operations to fund growth. If our cash flow from operations decreases or distributions from our equity investments decrease as a result of lower throughput volumes on their systems or otherwise, our ability to expend the capital necessary to expand our business or increase our future cash distributions may be limited. If our cash flow from operations and the distributions we receive from subsidiaries are insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition or general economic conditions at the time of any such financing or offering. Even if we are successful in obtaining the necessary

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funds, the terms of such financings could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Further, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the cash distribution rate which could materially decrease our ability to pay distributions. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis.

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

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

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

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

We operate joint ventures that may limit our operational flexibility.

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

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

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

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

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

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

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

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

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

Our primary exposure to market risk occurs at the time contracts expire and are subject to renegotiation and renewal. As of December 31, 2019, the weighted average remaining term of our consolidated portfolio of natural gas gathering contracts is

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approximately 11 years, and our consolidated portfolio of crude oil gathering contracts is approximately 10 years. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:

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

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

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

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

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

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

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

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

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

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

•rates, operating terms and conditions of service;

• the form of tariffs governing service;

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

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

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

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

• creditworthiness and credit support requirements;

• the maintenance of accounts and records;

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

• the initiation and discontinuation of services; and

• various other matters.

Natural gas companies may not charge rates that, upon review by the FERC, are found to be unjust and unreasonable or unduly discriminatory. Existing interstate transportation and storage rates may be challenged by complaint and are subject to prospective change by the FERC. Additionally, rate increases proposed by a regulated pipeline or storage provider may be challenged and such increases may ultimately be rejected by the FERC. Stagecoach Gas has authority from the FERC to charge and collect (i) market-based rates for interstate storage services provided at the Stagecoach, Thomas Corners, Seneca Lake and Steuben facilities and (ii) negotiated rates for interstate transportation services provided by the North-South Facilities and MARC I Pipeline. The FERC has authorized Tres Palacios to charge and collect market-based rates for interstate storage services provided by its natural gas facilities. The FERC’s “market-based rate” policy allows regulated entities to charge rates different from, and in some cases, less than, those which would be permitted under traditional cost-of-service regulation. Among the sorts of changes in circumstances that could raise market power concerns would be an expansion of capacity, acquisitions or other changes in market dynamics. There can be no guarantee that our joint ventures will be allowed to continue to operate under such rate structures for the remainder of their assets’ operating lives. Any successful challenge against rates charged for their storage and transportation services, or their loss of market-based rate authority or negotiated rate authority, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

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On March 15, 2018, the FERC issued a Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. Also on March 15, 2018, the FERC issued a Notice of Proposed Rulemaking (NOPR) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to pipeline rates. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement because it is a non-binding policy and parties will have the opportunity to address the policy as applied in future cases. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from providing support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. Also on July 18, 2018, the FERC issued a final rule adopting procedures that are generally the same as proposed in the NOPR with a few clarifications and modifications. With limited exceptions, the final rule requires all FERC-regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to select one of four options: (i) file a limited NGA Section 4 filing reducing its rates only as required related to the Tax Cuts and Jobs Act and the Revised Policy Statement; (ii) commit to filing a general NGA Section 4 rate case in the near future; (iii) file a statement explaining why an adjustment to rates is not needed; or (iv) take no other action. Stagecoach Gas submitted its Form No. 501-G on December 6, 2018. In December 2019, the FERC approved Stagecoach Gas’s offer of settlement filed in August 2019, which resolved all issues in the Section 5 rate proceeding, the results of which did not have a material impact on our financial condition or results of operations.

The FERC also issued a Notice of Inquiry (NOI) requesting comments about whether, and if so how, the FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Any actions the FERC will take related to the NOI are unknown at this time, but could impact the rates midstream companies are permitted to charge its customers for transportation services in the future. At this time, we cannot predict the outcome of the implementation of the Revised Policy Statement, the final rule or NOI, but the rates that our equity investments with FERC-regulated operations are permitted to charge its customers for transportation services after the expiration of the existing negotiated rates could be impacted if they file a limited or general NGA Section 4 rate filing or if the FERC or customers challenge the cost-of-service rates our equity investments are authorized to charge.

The FERC issued a NOI on April 19, 2018 (Certificate Policy Statement NOI), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. Comments on the Certificate Policy Statement NOI were due on July 25, 2018, and we are unable to predict what, if any, changes may be proposed as a result of the NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective.

There can be no assurance that the FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. Failure to comply with applicable regulations under the Natural Gas Act, the Natural Gas Policy Act of 1978, the NGPSA and certain other laws, and with implementing regulations associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to approximately $1.3 million per day, per violation.

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

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

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

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

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

It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us as well as the industry in general or otherwise adversely affect demand for our services. For example, in 2015, the EPA issued a final rule under the federal Clean Air Act lowering the United States National Ambient Air Quality Standards (NAAQS) for ground-level ozone to 70 parts per billion for the 8-hour primary and secondary ozone standards. In 2017 and 2018, the EPA issued area designations with respect to ground-level ozone either “attainment/unclassifiable” or “unclassifiable” or “non-attainment.” Additionally, in November 2018, the EPA issued final requirements that apply to state, local and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone. In another example, the EPA and U.S. Army of Corps of Engineers (Corps) published a final rule in 2015 that attempted to clarify federal jurisdiction under the Clean Water Act over waters of the United States. In July 2017, the EPA and the Corps agreed to reconsider the 2015 rule and, thereafter, in October 2019, the agencies published a final rule to rescind the 2015 rule and recodify the regulatory text that govern waters of the United States prior to promulgation of the 2015 rule. This final rule became effective on December 23, 2019. The recodified regulatory text will govern waters of the United States until such time as the EPA and Corps issue a final rule re-defining the Clean Water Act’s jurisdiction over waters of the United States in replacement of the 2015 rule but, to date, the two agencies have only published a proposed rulemaking on re-defining such jurisdiction in February 2019. The 2015 final rule is being challenged by various factors in federal district court with the 2015 rule currently being in force in 22 states; however, with the December 2019 effectiveness of the rule rescinding the 2015 rule, those challenges may become moot unless additional legal actions challenging the September 2019 rule arise. To the extent any rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays or cancellations with respect to obtaining permits for dredge and fill activities in wetland areas. Our compliance with these or other new or amended legal requirements could result in our incurring significant additional expense and operating delays, restrictions or cancellations with respect to our operations, which may not be fully recoverable from customers and, thus, could reduce net income. Our customers may similarly incur increased costs or restrictions that may limit or decrease those customers’ operations and have an indirect material adverse effect on our business.

Our and our customers’ operations are subject to various risk, including regulatory risks that could result in increased operating and capital costs, limit the areas in which oil and natural gas production may cocur and reduced demand for our services.

Climate change continues to attract considerable public, political and scientific attention. As a result, numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and

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limit emissions of GHGs. These efforts have included consideration of cap-and-trade programs, carbon taxes, GHG reporting and tracking programs, and regulations that directly limit GHG emissions from certain sources.

At the federal level, no comprehensive climate change legislation has been implemented to date. However, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act that, among other things, establish Prevention of Significant Deterioration (PSD) construction and Title V operating permit reviews for GHGs from certain large stationary sources that are already potential major sources of principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions also will be required to meet best available control technology standards that typically will be established by the states. The EPA has also adopted regulations requiring the annual reporting of GHG emissions from specified large GHG emission sources in the United States including certain oil and natural gas production, processing, transmission, storage and distribution facilities as well as certain onshore gathering and boosting systems consisting primarily of gathering pipelines, compressors and process equipment used to perform natural gas compression, dehydration and acid gas removal.

Federal agencies also have begun directly regulating emissions of methane, a GHG, from oil and natural gas operations. In 2016, the EPA published a final rule establishing new emissions standards for methane and additional standards for volatile organic compounds from certain new, modified, and reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage facilities. These standards require the use of certain equipment specific emissions control practices, require additional controls for pneumatic controllers and pumps as well as compressors, and impose leak detection and repair requirements for natural gas compressor and booster stations. However, in September 2019, the EPA published a proposed rulemaking amending the June 2016 regulations that, among other things, would remove sources in the transmission and storage segment from the oil and natural gas source category and rescind the methane-specific requirements applicable to sources in the production and processing segments of the industry. As an alternative, the EPA is also proposing to rescind the methane-specific requirements that apply to all sources in the oil and natural gas industry, without removing the transmission and storage sources from the current source category. Under either alternative, the EPA plans to retain emissions limits for volatile organic compounds. The EPA proposed rulemaking indicates that the controls to reduce volatile organic compound emissions also reduce methane at the same time, so separate methane limitations for these segments of the industry are redundant. Public comments on the proposed rulemaking were due to be submitted by November 25, 2019. Whether these proposed standards may become implemented, on what date and exactly what they will require is unknown at this time. These rules and any other new methane emission standards imposed on the oil and gas sector could result in increased costs to our and our customers’ operations and could delay or curtail our customers’ activities, which could adversely affect our business. On an international level, in April 2016, the United States joined other countries in entering into a United Nations-sponsored non-binding agreement negotiated in Paris, France (Paris Agreement) for nations to limit their GHG emissions through individually-determined reduction goals every five years beginning in 2020, although the United States has announced its withdrawal from such agreement, effective November 4, 2020.

Governmental, scientific, and public concern over the threat of climate change arising from GHG emissions has resulted in federal political risks in the United States in the form of pledges made by certain candidates seeking the office of the President of the United States in 2020. Critical declarations made by one or more presidential candidates include proposals to ban hydraulic fracturing of oil and natural gas wells and ban new leases for production of minerals on federal properties, including onshore lands and offshore waters. Other actions related to oil and natural gas production activities that could be pursued by presidential candidates may include more restrictive requirements for the establishment of pipeline infrastructure or the permitting of liquefied natural gas export facilities, as well as the rescission of the United States’ withdrawal from the Paris Agreement in November 2020. Litigation risks are also increasing as a number of cities, local governments and other plaintiffs have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages as a result, or alleging that the companies have been aware of the adverse effects of climate change for some time but defrauded their investors by failing to adequately disclose those impacts.

There are also increasing financial risks for fossil fuel producers as shareholders and bondholders currently invested in fossil-fuel energy companies concerned about the potential effects of climate change may elect in the future to shift some or all of their investments into non-fossil fuel energy related sectors. Institutional lenders who provide financing to fossil-fuel energy companies also have become more attentive to sustainable lending practices and some of them may elect not to provide funding for fossil fuel energy companies. Additionally, the lending practices of institutional lenders have been the subject of intensive lobbying efforts in recent years, oftentimes public in nature, by environmental activists, proponents of the international Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers. Limitation of investments in and financings for fossil fuel energy companies could result in the restriction, delay or cancellation of drilling programs or development or production activities.

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The adoption of legislation or regulatory programs to reduce emissions of GHGs in areas where we or our customers conduct operations could require us and our customers to incur increased compliance and operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas that is produced, which may decrease demand for our midstream services. Moreover, any such future laws and regulations that limit emissions of GHGs or that otherwise promote the use of renewable fuels could adversely affect demand for the natural gas our customers produce, which could thereby reduce demand for our services and adversely affect our business. Additionally, political, financial and litigation risks may result in our oil and natural gas customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes, or impairing the ability to continue to operate in an economic manner, which also could reduce demand for our services and products. One or more of these developments 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 has established rules requiring pipeline operators to develop and implement integrity management programs for certain natural gas and hazardous liquid pipelines located where a leak or rupture could harm “high consequence areas,” which are areas where a release could have the most significant adverse consequences, including high population areas, certain drinking water sources and unusually sensitive ecological areas. Among other things, these regulations require operators of covered pipelines 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.

Additionally, certain states, including Arkansas, New Mexico, North Dakota, Texas, West Virginia and Wyoming, where we conduct operations, have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas pipelines, and New Mexico, Texas and West Virginia have also adopted regulations similar to existing PHMSA regulations for certain intrastate hazardous liquid pipelines. We estimate that the total future costs to complete the testing required by existing PHMSA or any applicable state 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, which costs could be substantial. The results of this testing could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines

Moreover, federal legislation or implementing regulations adopted in recent years may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital costs, operational delays and costs of operations. For example, the 2011 Pipeline Safety Act increased the penalties for safety violations, established additional safety requirements for newly constructed pipelines and required studies of safety issues that could result in the adoption of new regulatory requirements by PHMSA for existing pipelines. Additionally, pursuant to one of the requirements under the 2011 Pipeline Safety Act, PHMSA published a proposed rulemaking in 2016 that would expand integrity management requirements and impose new pressure testing requirements on currently regulated natural gas pipelines. The proposal would also significantly expand the regulation of gathering lines, subjecting previously unregulated pipelines to requirements regarding damage prevention, corrosion control, public education programs, maximum allowable operating pressure limits and other requirements. However, PHMSA has since decided to split its 2016 proposed rule, which has become known as the gas mega rule, into three separate rulemakings to facilitate completion. The first of these three rulemakings, relating to onshore gas transmission pipelines, was published as a final rule on October 1, 2019, becomes effective on July 1, 2020, and imposes numerous requirements on such pipelines, including maximum allowable operating pressure reconfirmation, the periodic assessment of these pipelines in populated areas not designated as high consequence areas, the reporting of exceedances of maximum allowable operating pressures, and the consideration of seismicity as a risk factor in integrity management. The remaining rulemakings comprising the gas mega rule are expected to be issued in 2020.

More recently, in 2016, the 2016 Pipeline Safety Act was passed, extending PHMSA’s statutory mandate through September 2019 and, among other things, requiring PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act. The 2016 Pipeline Safety Act also empowers PHMSA to address imminent hazards by imposing emergency restrictions, prohibitions and safety measures on owners and operators of gas or hazardous liquid pipeline facilities without prior notice or an opportunity for a hearing. PHMSA published a final rule on October 1, 2019 to implement the agency’s

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expanded authority to address unsafe pipeline conditions or practices that pose an imminent hazard to life, property, or the environment.

With regard to natural gas storage facilities, following the detection of a natural gas leak from a third party at a natural gas storage facility in California in 2015, PHMSA issued an advisory bulletin in 2016 for natural gas storage facility operators, recommending that they review operations to identify the potential leaks and failures caused by corrosion, chemical or mechanical damage, or other material deficiencies in equipment; review storage facility locations and operations of shut-off and isolation systems, and comply with state regulations governing the permitting, drilling, completion, and operation of storage wells, and recommending the voluntary implementation of certain industry recognized recommended practices for natural gas storage facilities. Additionally, the 2016 Pipeline Safety Act required PHMSA to develop new safety standards for such storage facilities by June 2018. In response, PHMSA issued final interim rules in December 2016 that imposed new safety-related requirements on downhole facilities (including wells, wellbore tubing and casing) of new and existing underground natural gas storage facilities. The final interim rules adopted and made mandatory two American Petroleum Institute Recommended Practices (API RP 1170 and 1171) that, among other things, address construction, maintenance, risk-management and integrity-management procedures. However, in June 2017, PHMSA temporarily suspended specified enforcement actions pertaining to provisions that had previously been non-mandatory provisions under those API recommended practices prior to incorporation into the December 2016 interim final rule, as PHMSA announced it would reconsider the interim final rule, and subsequently re-opened the rule to public comment in October 2017. The Unified Agenda issued by the federal government published a July 2019 date for issuance of a final rule but no rule has yet been finalized. At this time, we cannot predict the impact of any future regulatory actions in this area.

Furthermore, on October 1, 2019, PHMSA published a final rule that significantly extends and expands the reach of certain PHMSA integrity management requirements for hazardous liquid pipelines, including, for example, performance of periodic assessments and expanded use of leak detection systems, regardless of the pipeline’s proximity to a high consequence area. The final rule was initially issued by PHMSA under the Obama Administration in late 2016 but publication and effectiveness of the final rule was subsequently delayed following the election of President Trump and change in Presidential administrations in January 2017. The October 1, 2019 final rule becomes effective on July 1, 2020 and, in addition to the stated integrity management requirements, requires all hazardous liquid pipelines in or affecting a high consequence area to be capable of accommodating in line inspection tools within the next 20 years. Also, this final rule extends annual, accident, and safety-related conditional reporting requirements to hazardous liquid gravity lines and certain gathering lines and also imposes inspection requirements on hazardous liquid pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes or other similar events that are likely to damage infrastructure.

We are evaluating PHMSA’s new rules, and we cannot predict the precise impact that compliance with the new rules will have on our business.  The new rules may, among other things, require us or our joint ventures to install new or modified safety controls, undertake additional capital projects or conduct maintenance programs on an expedited basis.  Also, because the 2016 Pipeline Safety Act reauthorized PHMSA’s hazardous liquid and gas pipeline programs only through September 30, 2019, we anticipate that Congress will issue an updated pipeline safety law in 2020 that will reauthorize those programs through 2023 and, thus, we will have to comply with applicable safety enhancement requirements and other provisions of any such new law. Additionally, while states are largely preempted by federal law from regulating pipeline safety for interstate pipelines, most states are certified by the U.S. 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. The costs of complying with the new PHMSA rules, as well as other rules under consideration by PHMSA or other agencies, could have a material adverse effect on our cash flows and results of operations.

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

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

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

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

• operator error;

• inadvertent damage from construction, farm and utility equipment;

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

• fires and explosions;

• cyber intrusions; and

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

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

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

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

We do not own all of the land on which our pipelines and facilities (particularly our G&P facilities) have been constructed, which subjects us to the possibility of more onerous terms or increased costs to obtain and maintain valid easements and rights-of-way. We obtain standard easement rights to construct and operate pipelines on land owned by third parties, and our rights frequently revert back to the landowner after we stop using the easement for its specified purpose. With regard to easements and rights-of-way on tribal lands, following a court decision issued in May 2017 by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land (that is, tribal land owned or at one time owned by an individual Indian landowner) bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted tribal lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannot guarantee that we will always be able to renew existing rights-of-way or obtain new rights-of-way without experiencing significant costs.

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 results of operations and ability to make distributions.

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

The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets for 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 or utilize our customer service systems. Also, destructive forms of protests and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural gas development and production or midstream processing or transportation activities could potentially result in damage or injury to persons, property or the environment or lead to extended interruptions of our or our customers’ operations. Additionally, the oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing and operational activities. At the same time, companies in our industry have been the targets of cyber-attacks, and it is possible that the attacks in our industry will continue and grow in number. In addition, to assist in conducting our business, we rely on information technology systems and data hosting facilities, including systems and facilities that are hosted by third parties and with respect to which we have limited visibility and control. These systems and facilities may be vulnerable to a variety of evolving cyber security risks or information security breaches, including unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions. These cyber security risks could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary, personal data, and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as advanced persistent threats, may remain undetected for an extended period. The occurrence of any of these events, including any attack

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or threat targeted at our pipelines and other assets, could cause a substantial decrease in revenues, increased costs or other financial losses, exposure or loss of customer information, damage to our reputation or business relationships, increased regulation or litigation, disruption of our operations 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. Although we have adopted controls and systems, including procuring limited insurance for certain cyber-related losses, that are designed to protect information and mitigate the risk of data loss and other cyber security events, such measures cannot entirely eliminate cyber security threats, particularly as these threats continue to evolve and grow. Furthermore the controls and systems we have installed may be breached or be inadequate to address a risk that arises. We are not aware of any cyber security events that impacted our company that have or could have resulted in a material loss; however there is no assurance that we will not suffer such a loss in the future.

We are or may become subject to cyber security and data privacy laws, regulations, litigation and directives relating to our processing of personal data.

Several jurisdictions in which we operate throughout the United States may have laws governing how we must respond to a cyber incident that results in the unauthorized access, disclosure, or loss of personal data. Additionally, new laws and regulations governing data privacy and unauthorized disclosure of confidential information, including international comprehensive data privacy regulations and recent California legislation (which, among other things, provides for a private right of action), pose increasingly complex compliance challenges and could potentially elevate our costs over time. Our business involves collection, uses, and other processing of personal data of our employees, contractors, suppliers, and service providers. As legislation continues to develop and cyber incidents continue to evolve, we will likely be required to expend significant resources to continue to modify or enhance our protective measures to comply with such legislation and to detect, investigate and remediate vulnerabilities to cyber incidents. Any failure by us, or a company we acquire, to comply with such laws and regulations could result in reputational harm, loss of goodwill, penalties, liabilities, and/or mandated changes in our business practices.

Risks Inherent in an Investment in Us

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

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

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

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

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

• prevailing economic and market conditions;

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

• changes in tax laws;

• the level of competition from other midstream companies;

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

• the level of capital expenditures we make;

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

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

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

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

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

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

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

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

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

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

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

• the ratio of taxable income to distributions may increase; 

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

• the market price of the common units may decline.

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

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

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

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

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

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

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

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

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

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

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

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

As of December 31, 2019, Crestwood Holdings and its affiliates beneficially held an aggregate of 17,908,700 limited partner units. The sale of any or all of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market on which the common units are traded. Additionally, Crestwood Holdings may pledge or hypothecate its common units or its interest in Holdings LP, the sole member of our general partner, or its subsidiaries. Such pledge or hypothecation may include terms and conditions that might result in an adverse impact on the trading price of our common units.

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

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

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partnership agreement, increases or decreases the authorized number of preferred units; or (iii) otherwise adversely affects the preferred units, including without limitation the creation (by reclassification or otherwise) of any class of senior securities (or amending the provisions of any existing class of partnership interests to make such class of partnership interests a class of senior securities). In addition, our partnership agreement provides certain rights to the preferred 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 unit holders.

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

If at any time our general partner and its affiliates own more than 80% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2019, the directors and executive officers of our general partner owned approximately 6% of our common units.

Tax Risks to Common and Preferred Unitholders

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

The anticipated after-tax economic benefit of an investment in our 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 and current Treasury Regulations, we believe we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.

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

The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. From time to time, members of Congress have proposed and considered substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including a prior legislative proposal that would have eliminated the qualifying income exception to the treatment of publicly-traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. For example, the Clean Energy for America Act, which is similar to legislation that was commonly proposed during the Obama Administration, was introduced in the Senate on May 2, 2019. If enacted, this proposal would, among other things, repeal the qualifying income exception within Section 7704(d)(1)(E) of the Code upon which we rely for our status as a partnership for U.S. federal income tax purposes.

In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws

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or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impair our ability to qualify as a publicly traded partnership in the future.

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 changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our units. You are urged to consult with your own tax advisor with respect to the status of regulatory or administrative developments and proposals and their potential effect on your investment in our units.

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

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

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

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

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

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

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

If you sell your units, you will recognize a gain or loss equal to the difference between your amount realized and your tax basis in those 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 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 units, even if the price you receive is less than your original cost. In addition, because the amount realized includes a unitholder’s share of our

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nonrecourse liabilities, if you sell your units you may incur a tax liability in excess of the amount of cash you receive from the sale.

Furthermore, a substantial portion of the amount realized from the sale of our units, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions. Thus, you may recognize both ordinary income and capital loss from the sale of your units if the amount realized on a sale of your units is less than your adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which you sell your units, you may recognize ordinary income from our allocations of income and gain to you prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.

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

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for business interest is limited to the sum of our business interest income and 30% of our adjusted taxable income. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income, and in the case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion to the extent such depreciation, amortization, or depletion is not capitalized into cost of goods sold with respect to inventory. If our business interest is subject to limitation under these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.

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

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

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

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

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a foreign person, and we are required to deduct and withhold from the transferee amounts that should have been withheld by the transferees but were not withheld. Because the amount realized includes a partner’s share of the partnership’s liabilities, 10% of the amount realized could exceed the total cash purchase price for the units. However, pending the issuance of final regulations, the IRS has suspended the application of this withholding rule to transfers of publicly traded interests in publicly traded partnerships. If recently promulgated regulations are finalized as proposed, such regulations would provide, with respect to transfers of publicly traded interests in publicly traded partnerships effected through a broker, that the obligation to withhold is imposed on the transferor’s broker and that a partner’s amount realized does not include a partner’s share of a publicly traded partnership’s liabilities for purposes of determining the amount subject to withholding. However, it is not clear when such regulations will be finalized and if they will be finalized in their current form.

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

Because we cannot match transferors and transferees of units and because of other reasons, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods 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 any sale of our units and could have a negative impact on the value of our units or result in audit adjustments to your tax returns.

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 IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.

We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the Allocation Date), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

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

Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, he may no longer be treated for tax purposes as a partner with respect to those 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 units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

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

In addition to federal income taxes, our unitholders may 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 conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. 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 and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.

The tax treatment of distributions on our preferred units is uncertain and the IRS may determine that preferred distributions are guaranteed payments, which may result in less favorable tax treatment to the holder of such preferred units.

The tax treatment of distributions on our preferred units is uncertain. We will treat each of the holders of the preferred units as partners for tax purposes and will not treat preferred distributions as guaranteed payments for the use of capital. However, if the IRS were to determine that such preferred distributions were guaranteed payments, the preferred distributions would generally be taxable to each of the holders of preferred units as ordinary income and the holders of preferred units would recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution). Although we expect that much of our income will be eligible for the 20% deduction for qualified publicly traded partnership income, recently issued final treasury regulations provide that income attributable to a guaranteed payment for the use of capital is not eligible for the 20% deduction for qualified business income. As a result, if the IRS treated the preferred distributions as guaranteed payments, income attributable to a guaranteed payment for use of capital recognized by holders of

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our preferred units would not eligible for the 20% deduction for qualified business income. In addition, if the preferred units were treated as indebtedness for tax purposes, preferred distributions likely would be treated as payments of interest by us to each of the holders of preferred units. All holders of our preferred units are urged to consult a tax advisor with respect to the consequences of owning our preferred units.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

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

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

Item 3. Legal Proceedings

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

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

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

Crestwood Equity. Crestwood Equity’s common units representing limited partner interests are traded on the NYSE under the symbol “CEQP.”

The last reported sale price of Crestwood Equity’s common units on the NYSE on February 10, 2020, was $26.45. As of that date, Crestwood Equity had 72,725,966 common units issued and outstanding, which were held by 249 unitholders of record.

Issuer Purchases of Equity Securities

For the year ended December 31, 2019, we relinquished 336,548 common units to cover payroll taxes upon the vesting of restricted units. 

Equity Compensation Plan Information

The following table sets forth in tabular format, a summary of CEQP’s equity compensation plan information as of December 31, 2019: 

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	—	$	—	3,799,119
Total	—	$	—	3,799,119

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Item 6. Selected Financial Data

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

Crestwood Equity. The income statement and cash flow data for each of the three years ended December 31, 2019 and balance sheet data as of December 31, 2019 and 2018 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, 2016 and the balance sheet data as of December 31, 2017, 2016 and 2015 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, Financial Statement Schedules included elsewhere in this report.

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

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	Crestwood Equity Partners LP
	Year Ended December 31,
	2019			2018			2017			2016			2015
	(in millions, except per unit data)
Statement of Income Data:
Revenues	$	3,181.9		$	3,654.1		$	3,880.9		$	2,520.5		$	2,632.8
Operating income (loss)	402.2			113.5			(79.4		)	(108.7		)	(2,084.8		)
Income (loss) before income taxes	320.2			67.1			(167.4		)	(191.8		)	(2,305.1		)
Net income (loss)	319.9			67.0			(166.6		)	(192.1		)	(2,303.7		)
Net income (loss) attributable to Crestwood Equity Partners LP	285.1			50.8			(191.9		)	(216.3		)	(1,666.9		)
Performance Measures:
Diluted net income (loss) per limited partner unit:	$	2.93		$	(0.13	)	$	(3.64	)	$	(3.55	)	$	(54.00	)
Distributions declared per limited partner unit(1)	$	2.425		$	2.40		$	2.40		$	3.175		$	5.50
Other Financial Data:
EBITDA (unaudited)	$	631.4		$	335.9		$	161.4		$	152.9		$	(1,844.9	)
Adjusted EBITDA (unaudited)	526.5			420.1			395.4			455.6			527.4
Net cash provided by operating activities	420.4			253.6			255.9			346.1			440.7
Net cash provided by (used in) investing activities	(943.7		)	(241.2		)	38.7			867.2			(212.7		)
Net cash provided by (used in) financing activities	531.8			3.5			(294.9		)	(1,212.2		)	(236.3		)
Balance Sheet Data:
Property, plant and equipment, net	$	2,909.1		$	2,029.7		$	1,820.8		$	2,097.6		$	3,310.8
Total assets	5,349.3			4,294.5			4,284.9			4,448.9			5,762.8
Total debt, including current portion	2,328.5			1,753.3			1,492.2			1,523.7			2,502.9
Other long-term liabilities(2)	301.6			173.6			104.7			44.6			47.5
Partners’ capital	1,932.8			2,033.8			2,180.5			2,539.0			2,946.9

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

(2) Other long-term liabilities primarily include our contract liabilities, operating and finance leases, asset retirement obligations and contingent consideration liability.

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

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

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

• statements that are not historical in nature, including, but not limited to: (i) our belief that anticipated cash from operations, cash distributions from entities that we control, and borrowing capacity under our credit facility will be sufficient to meet our anticipated liquidity needs for the foreseeable future; (ii) our belief that we do not have material potential liability in connection with legal proceedings that would have a significant financial impact on our consolidated financial condition, results of operations or cash flows; and (iii) our belief that our assets will continue to benefit from the development of unconventional shale plays as significant supply basins; and

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

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

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

• governmental legislation and regulations;

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

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

• weather conditions;

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

• economic conditions;

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

• environmental claims;

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

• interest rates;

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

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

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

Overview

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

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Our Company

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

• natural gas facilities with approximately 3.3 Bcf/d of gathering capacity, 1.0 Bcf/d of processing capacity, 75.8 Bcf of certificated working storage capacity and 1.8 Bcf/d of operational transportation capacity;

• crude oil facilities with approximately 150,000 Bbls/d of gathering capacity, 1.9 MMBbls of storage capacity, 20,000 Bbls/d of transportation capacity and 180,000 Bbls/d of rail loading capacity;

• NGL facilities with approximately 2.6 MMBbls of storage capacity, as well as our portfolio of transportation assets (consisting of truck and rail terminals, truck/trailer units and rail cars) capable of transporting approximately 1.3 MMBbls/d of NGLs; and

• produced water gathering facilities with approximately 110,000 Bbls/d of gathering capacity.

Our financial statements reflect three operating and reporting segments: (i) gathering and processing, which includes our natural gas, crude oil and produced water G&P operations; (ii) storage and transportation, which includes our crude oil and natural gas storage and transportation operations; and (iii) marketing, supply and logistics, which includes our NGL, crude oil and natural gas marketing and logistics operations and NGL storage and rail loading facilities and fleet. For a description of the assets included in our operating and reporting segments, see Part I, Item 1. Business.

Gathering and Processing

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

Storage and Transportation

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

Marketing, Supply and Logistics

Our MS&L segment consists of our NGL, crude oil and natural gas marketing and logistics operations, including our rail-to-truck terminals located in Florida, New Jersey, New York, Rhode Island, North Carolina and Connecticut. We utilize our trucking and rail fleet, processing and storage facilities, and contracted storage and pipeline capacity on a portfolio basis to provide integrated supply and logistics solutions to producers, refiners and other customers in over 30 states from New Mexico to Maine.

Outlook and Trends

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

We have taken a number of strategic steps to better position the Company as a stronger, better capitalized company that can over time accretively grow cash flows and sustainably resume growing our distributions. Those strategic steps included (i) simplifying our corporate structure to eliminate our incentive distribution rights (IDRs) and create better alignment of interests with our unitholders; (ii) divesting assets to reduce long-term debt to ensure long-term balance sheet strength; (iii) realigning

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our operating structure to significantly reduce operating and administrative expenses; (iv) forming strategic joint ventures to enhance our competitive position around certain operating assets; and (v) focusing our acquisitions and growth capital expenditures on our highest return organic projects around our core growth assets in the Bakken Shale, Powder River Basin and Delaware Permian. We will remain focused on efficiently allocating capital expenditures by investing in accretive, organic growth projects, maintaining low-cost operations (through increased operating efficiencies and cost discipline) and maintaining our balance sheet strength through continued financial discipline. We expect to focus on expansion and greenfield opportunities to provide midstream services for crude oil, natural gas, NGLs and produced water, including gathering, storage and terminalling, condensate stabilization, truck loading/unloading options and connections to third party pipelines and produced water gathering, disposal and recycling in the Bakken Shale, Powder River Basin and Delaware Permian in the near term, while closely monitoring longer-term expansion opportunities in the northeast Marcellus. As a result, the Company is well positioned to execute its business plan and capitalize on the current market conditions around many of our core assets.

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

Business Highlights

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

Bakken. In the Bakken, we are expanding and upgrading our Arrow system water handling facilities and increasing natural gas capacity on the system, which should allow for substantial growth in volumetric throughput across all of our crude oil, produced water and natural gas gathering systems to better serve our customer demands. During 2019, we placed in service a 120 MMcf/d cryogenic plant that will fulfill 100% of the processing requirements for producers on the Arrow system. This expansion increases our gas processing capacity to 150 MMcf/d. We believe the expansion of our gas processing capacity on the Arrow system will, among other things, spur greater development activity around the Arrow system, allow us to provide greater flow assurance to our producer customers and reduce flaring of natural gas, and reduce the downstream constraints currently experienced by producers on the Fort Berthold Indian Reservation.

In response to the water releases on our Arrow system, we removed approximately 30 miles of water gathering pipeline from service and incurred a $4.3 million impairment charge during the three months ended December 31, 2019 related to idling those facilities. In addition, we are currently in the process of replacing approximately 12 miles of water gathering pipeline with pipeline composed of higher capacity material that is more suitable for the environment and climate conditions in the Bakken, which will increase water gathering capacity on the Arrow system and further our commitment to sustainability and environmental stewardship in the areas where we live and operate.

Powder River Basin. On April 9, 2019, Crestwood Niobrara acquired Williams’ 50% equity interest in Jackalope for approximately $484.6 million. The acquisition of the remaining 50% equity interest in Jackalope was financed through a combination of borrowings under the Crestwood Midstream credit facility and the issuance of $235 million in new Series A-3 preferred units to Jackalope Holdings. For a further discussion of the acquisition of the remaining 50% equity interest in Jackalope, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 3 and 12.

In the Powder River Basin, we are expanding the Jackalope gathering system and Bucking Horse processing plant to increase processing capacity to 345 MMcf/d in early 2020. The Phase 2 Jackalope expansion also includes gathering, compression and a second processing plant which will add an additional 200 MMcf/d of processing capacity to the Jackalope system. In addition, we are also commissioning two compressor stations with 18,750 horsepower. These expansions will allow us to attract incremental third party volumes in the growing Powder River Basin.

Delaware Permian. In the Delaware Permian, we have identified gathering and processing and transportation opportunities in and around our existing assets, including our Crestwood Permian joint venture. In the Delaware Permian, we are expanding

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our systems to include a produced water gathering and salt water disposal system. We entered into a produced water gathering and disposal agreement with a large integrated producer in the Delaware Permian in Culberson and Reeves Counties, Texas for initial system capacity of 60 MBbls/d with long-term plans to expand system capacity up to 120 MBbls/d based on producer activity. We have begun construction on the required infrastructure and expect to handle first volumes in the early second quarter 2020.

Crestwood Permian Basin, a 50% equity investment of Crestwood Permian, owns and operates the Nautilus system in SWEPI's operated position in the Delaware Permian. Crestwood Permian Basin provides gathering, dehydration and treating services to SWEPI under a long-term fixed-fee gathering agreement. SWEPI has dedicated to Crestwood Permian Basin the gathering rights for SWEPI's gas production across a large acreage position in Loving, Reeves, Ward and Culberson Counties, Texas. The Nautilus gathering system will be expanded over time, as production increases, to include additional gathering lines and centralized compression facilities which will ultimately provide over 250 MMcf/d of gas gathering capacity.

Regulatory Matters

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

On March 15, 2018, the FERC issued a Revised Policy Statement on Treatment of Income Taxes (Revised Policy Statement) stating that it will no longer permit master limited partnerships to recover an income tax allowance in their cost-of-service rates. Also on March 15, 2018, the FERC issued a Notice of Proposed Rulemaking (NOPR) proposing rules for implementation of the Revised Policy Statement and the corporate income tax rate reduction with respect to pipeline rates. On July 18, 2018, the FERC issued an order denying requests for rehearing and clarification of its Revised Policy Statement because it is a non-binding policy and parties will have the opportunity to address the policy as applied in future cases. In the rehearing order, the FERC clarified that a pipeline organized as a master limited partnership will not be precluded in a future proceeding from providing support that it is entitled to an income tax allowance and demonstrating that its recovery of an income tax allowance does not result in a double-recovery of investors’ income tax costs. Also on July 18, 2018, the FERC issued a final rule adopting procedures that are generally the same as proposed in the NOPR with a few clarifications and modifications. With limited exceptions, the final rule requires all FERC-regulated natural gas pipelines that have cost-based rates for service to make a one-time Form No. 501-G filing providing certain financial information and to select one of four options: (i) file a limited NGA Section 4 filing reducing its rates only as required related to the Tax Cuts and Jobs Act and the Revised Policy Statement; (ii) commit to filing a general NGA Section 4 rate case in the near future; (iii) file a statement explaining why an adjustment to rates is not needed; or (iv) take no other action. Stagecoach Gas submitted its Form No. 501-G on December 6, 2018. In December 2019, Stagecoach Gas reached a final settlement related to its NGA Section 5 rate proceeding, the results of which is not anticipated to have a material impact on our current or future results of operations.

On March 15, 2018, the FERC also issued a Notice of Inquiry (NOI) requesting comments about whether, and if so how, the FERC should address changes relating to accumulated deferred income taxes and bonus depreciation. Comments on the NOI were filed by May 21, 2018, and any actions the FERC may take following receipt of these responses to the NOI are unknown at this time, but could impact the rates midstream companies are permitted to charge its customers for transportation services in the future.

In addition, the FERC issued a NOI on April 19, 2018 (Certificate Policy Statement NOI), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. Comments on the Certificate Policy Statement NOI were due on July 25, 2018, and we are unable to predict what, if any, changes may be proposed as a result of the NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective. We do not expect that any change in this policy would affect us in a materially different manner than any other similarly sized natural gas pipeline company operating in the United States.

Although we do not have any consolidated operations that have FERC-regulated pipelines, two of our equity investments (Stagecoach Gas and Tres Holdings) have FERC-regulated operations. These equity investments receive revenues from contracts that primarily have market-based rates or negotiated rates that are not tied to cost-of-service rates, and we currently do not expect rates subject to negotiated rates or market-based rates to be affected by the Revised Policy Statement, the Final Rule or any final regulations that may result from the NOI. As a result, we currently do not believe that the Revised Policy Statement, the Final Rule or NOI will have a material impact on our results of operations, but we continue to monitor developments at the FERC related to these matters to assess whether the final regulations could have an impact on the future results of our equity investments.

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Critical Accounting Estimates and Policies

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

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

Goodwill

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

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

Upon acquisition, we are required to record the assets, liabilities and goodwill of a reporting unit at its fair value on the date of acquisition. As a result, any level of decrease in the forecasted cash flows of these businesses or increases in the discount rates utilized to value those businesses from their respective acquisition dates would likely result in the fair value of the reporting unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill is impaired.

Current commodity prices are significantly lower compared to commodity prices during 2014, and that decrease has adversely impacted forecasted cash flows, discount rates and stock/unit prices for most companies in the midstream industry, including us. In light of these circumstances, we evaluated the carrying value of our reporting units and determined it was more likely than not that the goodwill associated with several of our reporting units was impaired in 2017, and as a result, we recorded goodwill impairments on those reporting units during 2017. We did not record any goodwill impairments during 2019 and 2018.

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The following table summarizes the goodwill impairments of our reporting units during 2017 and our goodwill at December 31, 2019 (in millions):

	Goodwill Impairments during the Year Ended December 31, 2017		Goodwill at December 31, 2019
G&P
Arrow	$	—	$	45.9
Powder River Basin	—		80.3
MS&L
NGL Marketing and Logistics	—		92.7
West Coast	2.4		—
Storage and Terminals	36.4		—
Total	$	38.8	$	218.9

We continue to monitor our remaining goodwill, and we could experience additional impairments of the remaining goodwill in the future if we experience a significant sustained decrease in the market value of our common or preferred units or if we receive additional negative information about market conditions or the intent of our customers on our remaining operations with goodwill, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value of those businesses. A 5% decrease in the forecasted cash flows or a 1% increase in the discount rates utilized to determine the fair value of our Arrow and NGL Marketing and Logistics reporting units would not have resulted in a goodwill impairment of either of those reporting units. Because our Powder River Basin reporting unit was acquired as a part of the Jackalope acquisition and its assets and liabilities were recorded at fair value in 2019, its fair value approximates its book value at December 31, 2019. For a further discussion of the Jackalope acquisition, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.

Long-Lived Assets

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

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

To estimate the useful life of our finite lived intangible assets we utilize assumptions of the period over which the assets are expected to contribute directly or indirectly to our future cash flows. Generally this requires us to amortize our intangible assets based on the expected future cash flows (to the extent they are readily determinable) or on a straight-line basis (if they are not readily determinable) of the acquired contracts or customer relationships. Due to the imprecise nature of the projections and assumptions utilized 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 assessment of the recoverability of goodwill utilizing fair value estimates that primarily utilize discounted cash flows in the estimation process (as described above), and accordingly a reporting unit that has experienced a goodwill impairment may not experience a similar impairment of the underlying long-lived assets included in that reporting unit. During 2019, we recorded $4.3 million of impairments of our property, plant and equipment related to

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certain of our water gathering facilities in our Arrow operations, which is further discussed in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 15. During 2018, we did not record any material impairments of our intangible assets and property, plant and equipment. During 2017, we incurred $82.2 million of impairments of our property, plant and equipment and intangible assets related to our MS&L West Coast operations, which resulted from decreasing forecasted cash flows to be generated by those operations. During 2018, we sold our MS&L West Coast operations for net proceeds of approximately $70.5 million, and recorded a $26.9 million of loss on long-lived assets associated with the sale. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3 for a further discussion of the sale of these assets.

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

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

Equity Method Investments

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

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

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

Our equity method investments have long-lived assets, intangible assets, goodwill and equity method investments in their underlying financial statements, and our equity investees apply similar accounting policies and have similar critical accounting estimates in assessing those assets for impairment as we do. Our Stagecoach Gas equity method investment has approximately $656.5 million of goodwill in its financial statements, which it assesses for impairment annually on December 31 or whenever events indicate that it is more likely than not that its fair value could be less than its carrying amount. This assessment requires Stagecoach Gas to make certain assumptions about its future operating performance (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions, in addition to current and changing economic conditions, the commodity price environment and discount rates). A significant decrease in the assumptions utilized by Stagecoach Gas could result in impairments being recorded by Stagecoach Gas, which could result in a significant reduction in our equity earnings from Stagecoach Gas. Our investment in Stagecoach Gas was approximately $814.4 million at December 31, 2019.

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Variable Interest Entities

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

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

As a result of our VIE analysis, we concluded that our investment in Crestwood Permian is a VIE that we are not the primary beneficiary of, and as a result, we account for our investment in Crestwood Permian as an equity method investment. Our other equity investments are not considered to be VIEs. In addition, Crestwood Niobrara and Jackalope (after the acquisition of the remaining 50% equity interest) are consolidated subsidiaries that are not considered to be VIEs. However, any future changes in the design or nature of the activities of these entities may require us to reconsider our conclusions associated with these entities. Such reconsideration would require the identification of the variable interests in the entity and a determination of which party is the entity’s primary beneficiary. If an equity investment were considered a VIE and we were determined to be the primary beneficiary, the change could cause us to consolidate the entity. The consolidation of an entity that is currently accounted for under the equity method could have a significant impact on our financial statements. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6 for more information on our equity method investments.

Revenue Recognition

We recognize revenues for services and products under our revenue contracts as our obligations to perform services or deliver/sell products under the contracts are satisfied. A contract’s transaction price is allocated to each performance obligation in the contract and recognized as revenue when, or as, the performance obligation is satisfied. Under certain contracts, we may be entitled to receive payments in advance of satisfying our performance obligations under the contract. We recognize a liability for these payments in excess of revenue recognized and present it as deferred revenue or contract liabilities on our consolidated balance sheets. At December 31, 2019 and 2018, we had deferred revenues of approximately $153.5 million and $77.4 million. Our deferred revenues primarily relate to:

• Capital Reimbursements. Certain contracts in our G&P segment require that our customers reimburse us for capital expenditures related to the construction of long-lived assets utilized to provide services to them under the revenue contracts. Because we consider these amounts as consideration from customers associated with ongoing services to be provided to customers, we defer these upfront payments in deferred revenue and recognize the amounts in revenue over the life of the associated revenue contract as the performance obligations are satisfied under the contract.

• Contracts with Increasing (Decreasing) Rates per Unit. Certain contracts in our G&P, S&T and MS&L segments have fixed rates per volume that increase and/or decrease over the life of the contract once certain time periods or thresholds are met. We record revenues on these contracts ratably per unit over the life of the contract based on the remaining performance obligations to be performed, which can result in the deferral of revenue for the difference between the consideration received and the ratable revenue recognized.

The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our performance obligations requires significant judgments and assumptions, including our evaluation of the timing of when control of the underlying good or service has transferred to our customers, estimating the revenue to be generated per unit over the life of the contracts, and determining the relative standalone selling price of goods and services provided to customers under contracts with multiple performance obligations. Actual results can significantly vary from those judgments and assumptions.

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How We Evaluate Our Operations

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

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

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

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Results of Operations

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

	Crestwood Equity									Crestwood Midstream
	Year Ended December 31,									Year Ended December 31,
	2019			2018			2017			2019			2018
Revenues	$	3,181.9		$	3,654.1		$	3,880.9		$	3,181.9		$	3,654.1
Costs of product/services sold	2,544.9			3,129.4			3,374.7			2,544.9			3,129.4
Operations and maintenance expense	138.8			125.8			136.0			138.8			125.8
General and administrative expense	103.4			88.1			96.5			98.2			83.5
Depreciation, amortization and accretion	195.8			168.7			191.7			209.9			181.4
Loss on long-lived assets, net	6.2			28.6			65.6			6.2			28.6
Gain on acquisition	(209.4		)	—			—			(209.4		)	—
Goodwill impairment	—			—			38.8			—			—
Loss on contingent consideration	—			—			57.0			—			—
Operating income (loss)	402.2			113.5			(79.4		)	393.3			105.4
Earnings from unconsolidated affiliates, net	32.8			53.3			47.8			32.8			53.3
Interest and debt expense, net	(115.4		)	(99.2		)	(99.4		)	(115.4		)	(99.2		)
Loss on modification/extinguishment of debt	—			(0.9		)	(37.7		)	—			(0.9		)
Other income, net	0.6			0.4			1.3			0.2			—
(Provision) benefit for income taxes	(0.3		)	(0.1		)	0.8			(0.3		)	—
Net income (loss)	319.9			67.0			(166.6		)	310.6			58.6
Add:
Interest and debt expense, net	115.4			99.2			99.4			115.4			99.2
Loss on modification/extinguishment of debt	—			0.9			37.7			—			0.9
Provision (benefit) for income taxes	0.3			0.1			(0.8		)	0.3			—
Depreciation, amortization and accretion	195.8			168.7			191.7			209.9			181.4
EBITDA	631.4			335.9			161.4			636.2			340.1
Unit-based compensation charges	47.0			28.5			25.5			47.0			28.5
Loss on long-lived assets, net	6.2			28.6			65.6			6.2			28.6
Gain on acquisition	(209.4		)	—			—			(209.4		)	—
Goodwill impairment	—			—			38.8			—			—
Loss on contingent consideration	—			—			57.0			—			—
Earnings from unconsolidated affiliates, net	(32.8		)	(53.3		)	(47.8		)	(32.8		)	(53.3		)
Adjusted EBITDA from unconsolidated affiliates, net	74.9			95.6			80.3			74.9			95.6
Change in fair value of commodity inventory-related derivative contracts	2.7			(18.3		)	2.2			2.7			(18.3		)
Significant transaction and environmental related costs and other items	6.5			3.1			12.4			6.5			3.1
Adjusted EBITDA	$	526.5		$	420.1		$	395.4		$	531.3		$	424.3

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	Crestwood Equity									Crestwood Midstream
	Year Ended December 31,									Year Ended December 31,
	2019			2018			2017			2019			2018
Net cash provided by operating activities	$	420.4		$	253.6		$	255.9		$	424.1		$	260.5
Net changes in operating assets and liabilities	(47.8		)	46.9			(0.3		)	(46.5		)	44.9
Amortization of debt-related deferred costs	(6.2		)	(6.8		)	(7.2		)	(6.2		)	(6.8		)
Interest and debt expense, net	115.4			99.2			99.4			115.4			99.2
Unit-based compensation charges	(47.0		)	(28.5		)	(25.5		)	(47.0		)	(28.5		)
Loss on long-lived assets, net	(6.2		)	(28.6		)	(65.6		)	(6.2		)	(28.6		)
Gain on acquisition	209.4			—			—			209.4			—
Goodwill impairment	—			—			(38.8		)	—			—
Loss on contingent consideration	—			—			(57.0		)	—			—
Earnings from unconsolidated affiliates, net, adjusted for cash distributions received	(6.9		)	(0.5		)	0.1			(6.9		)	(0.5		)
Deferred income taxes	—			0.7			2.1			(0.2		)	0.1
Provision (benefit) for income taxes	0.3			0.1			(0.8		)	0.3			—
Other non-cash income	—			(0.2		)	(0.9		)	—			(0.2		)
EBITDA	631.4			335.9			161.4			636.2			340.1
Unit-based compensation charges	47.0			28.5			25.5			47.0			28.5
Loss on long-lived assets, net	6.2			28.6			65.6			6.2			28.6
Gain on acquisition	(209.4		)	—			—			(209.4		)	—
Goodwill impairment	—			—			38.8			—			—
Loss on contingent consideration	—			—			57.0			—			—
Earnings from unconsolidated affiliates, net	(32.8		)	(53.3		)	(47.8		)	(32.8		)	(53.3		)
Adjusted EBITDA from unconsolidated affiliates, net	74.9			95.6			80.3			74.9			95.6
Change in fair value of commodity inventory-related derivative contracts	2.7			(18.3		)	2.2			2.7			(18.3		)
Significant transaction and environmental related costs and other items	6.5			3.1			12.4			6.5			3.1
Adjusted EBITDA	$	526.5		$	420.1		$	395.4		$	531.3		$	424.3

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Segment Results

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

Crestwood Equity and Crestwood Midstream	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics
Revenues	$	835.8		$	20.4		$	2,325.7
Intersegment revenues	175.0			14.2			(189.2		)
Costs of product/services sold	526.1			0.2			2,018.6
Operations and maintenance expense	98.7			4.0			36.1
Loss on long-lived assets, net	(6.2		)	—			(0.2		)
Gain on acquisition	209.4			—			—
Earnings (loss) from unconsolidated affiliates, net	(2.1		)	34.9			—
EBITDA for the year ended December 31, 2019	$	587.1		$	65.3		$	81.6
Revenues	$	946.7		$	17.1		$	2,690.3
Intersegment revenues	192.4			10.5			(202.9		)
Costs of product/services sold	767.0			0.2			2,362.2
Operations and maintenance expense	71.7			3.3			50.8
Loss on long-lived assets, net	(3.0		)	—			(27.3		)
Earnings from unconsolidated affiliates, net	22.5			30.8			—
EBITDA for the year ended December 31, 2018	$	319.9		$	54.9		$	47.1
Crestwood Equity
Revenues	$	1,688.2		$	37.2		$	2,155.5
Intersegment revenues	134.5			6.7			(141.2		)
Costs of product/services sold	1,480.8			0.3			1,893.6
Operations and maintenance expense	68.4			4.2			63.4
Loss on long-lived assets, net	(14.4		)	—			(48.2		)
Goodwill impairments	—			—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—
Earnings from unconsolidated affiliates, net	18.9			28.9			—
Other income, net	0.8			—			—
EBITDA for the year ended December 31, 2017	$	278.8		$	11.3		$	(29.7	)

Segment Results

Below is a discussion of the factors that impacted EBITDA by segment for the years ended December 31, 2019, 2018 and 2017.

Gathering and Processing

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

EBITDA for our gathering and processing segment increased by approximately $267.2 million during the year ended December 31, 2019 compared to 2018. The comparability of our gathering and processing segment’s EBITDA during the year December 31, 2019 compared to 2018 was impacted by a $209.4 million gain related to our acquisition of the remaining 50% equity interest in Jackalope discussed below.

Our gathering and processing segment’s costs of products/services sold decreased by $240.9 million during the year ended December 31, 2019 compared to 2018, while our revenues decreased by approximately $128.3 million during 2019 compared to 2018. These variances were driven primarily by our Arrow operations which experienced lower average prices on its agreements under which it purchases and sells crude oil as a result of the decrease in crude oil prices during the year ended December 31, 2019 compared to 2018. Our costs of product/services sold decreased faster than our revenues year over year due to the offsetting impact of increasing volumes, which during the year ended December 31, 2019, natural gas, crude oil and water volumes gathered by our Arrow system increased by 33%, 32%, and 48%, respectively, compared to 2018. In August 2019, Arrow placed into service a 120 MMcf/d cryogenic plant at its natural gas processing facility which increased its

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processing capacity to 150 MMcf/d and, as a result, Arrow experienced a 124% increase in its processing volumes during the year ended December 31, 2019 compared to 2018.

Partially offsetting the decrease in our gathering and processing segment’s revenues related to our Arrow operations were operating revenues of approximately $70.1 million recognized during the year ended December 31, 2019 related to our Jackalope operations. In April 2019, we acquired Williams’ 50% equity interest in Jackalope and, as a result, we began consolidating Jackalope’s operating results from the date of acquisition.

Our gathering and processing segment’s operations and maintenance expenses increased by approximately $27 million during the year ended December 31, 2019 compared to 2018, primarily due to the acquisition of the remaining 50% equity interest in Jackalope. Also contributing to the increase in our gathering processing segment’s operations and maintenance expenses were environmental costs related to water releases on our Arrow system, which are further described in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 15.

Our gathering and processing segment’s EBITDA for the year ended December 31, 2019 was also impacted by a loss on long-lived assets of approximately $6.2 million, primarily related to the retirement of certain water gathering lines on our Arrow system and the retirement and disposal of certain of our Granite Wash gathering and processing assets.

Our gathering and processing segment’s EBITDA was also impacted by a decrease in earnings from unconsolidated affiliates of approximately $24.6 million during the year ended December 31, 2019 compared to 2018. Equity earnings from our Jackalope equity investment decreased by approximately $14.4 million during the year ended December 31, 2019 compared to 2018, due to the acquisition of the remaining 50% equity interest in Jackalope from Williams in April 2019. Our gathering and processing segment also experienced lower equity earnings from our Crestwood Permian equity investment of approximately $10.2 million during the year ended December 31, 2019 compared to 2018, primarily due to lower average margin generated on certain of its gathering contracts resulting from higher transportation and fractionation fees during 2019 compared to 2018, and lower gathering and processing volumes due to producer well shut-ins that resulted from declining natural gas prices. Also impacting the decrease in equity earnings from Crestwood Permian was our proportionate share of a $2.3 million loss recorded by Crestwood Permian on the retirement of certain of its gathering and processing assets in 2019 and an increase in its depreciation and accretion expense due to placing the Orla processing plant into service in mid-2018.

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

EBITDA for our gathering and processing segment increased by approximately $41.1 million for the year ended December 31, 2018 compared to 2017. Our gathering and processing segment’s costs of product/services sold decreased by approximately $713.8 million during the year ended December 31, 2018 compared to 2017, while our revenues only decreased by $683.6 million year over year.

Our gathering and processing segment’s revenues and product costs were impacted by the modified retrospective adoption of ASU 2014-09, Revenue from Contracts with Customers, during the year ended December 31, 2018, which decreased its revenues and product costs by approximately $1,015.4 million and $1,026.8 million, respectively. Also impacting our gathering and processing segment’s EBITDA during the year ended December 31, 2018 compared to 2017, were lower revenues and product costs of approximately $30.2 million and $21.8 million, respectively, as a result of the deconsolidation of Crestwood New Mexico Pipeline LLC (Crestwood New Mexico) in 2017.

The remaining increase in our gathering and processing segment’s revenues and costs of product/services sold of approximately $362.0 million and $334.8 million, respectively, during the year ended December 31, 2018 compared to 2017, was primarily driven by our Arrow operations. Natural gas volumes and water volumes gathered by our Arrow system increased by 40% and 30%, respectively, during the year ended December 31, 2018 compared to 2017. These favorable variances were driven by increased producer activity and expanded capacity on our Arrow system. In addition, the Bear Den processing plant was placed into service in late 2017, which increased natural gas volumes gathered and processed by the Arrow system. Arrow also experienced higher average prices on its agreements under which it purchases and sells crude oil as a result of the increase in crude oil prices in 2018 compared to 2017.

Our gathering and processing segment’s operations and maintenance expenses increased by approximately $3.3 million during the year ended December 31, 2018 compared to 2017, primarily due to the increase in volumes related to our Arrow operations described above.

Our gathering and processing segment’s EBITDA for the year ended December 31, 2018 includes a loss on long-lived assets of approximately $3.0 million, primarily related to the retirement and/or disposal of certain of our Arrow and Granite Wash

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gathering and processing assets.

Our gathering and processing segment’s EBITDA was favorably impacted by a net increase in earnings from unconsolidated affiliates of approximately $3.6 million during the year ended December 31, 2018 compared to 2017. Equity earnings from our Jackalope equity investment increased by approximately $7.6 million primarily due to a 73% and 57% increase in its gathering and processing volumes during 2018 compared to 2017 resulting from increased producer activity on its system. Our equity earnings from our Crestwood Permian equity investment decreased by approximately $4.0 million during 2018 compared to 2017. Pursuant to the Crestwood Permian limited liability company agreement, we were allocated 100% of the equity earnings from Crestwood New Mexico through June 30, 2018. Subsequent to June 30, 2018, our equity earnings from Crestwood New Mexico were allocated based on our ownership percentage in Crestwood Permian, which is currently 50%.

Storage and Transportation

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

EBITDA for our storage and transportation segment increased by approximately $10.4 million during the year ended December 31, 2019 compared to 2018. Revenues from our COLT Hub operations increased by approximately $7 million during the year ended December 31, 2019 compared to 2018, primarily due to a 19% increase in COLT’s rail loading volumes due to higher demand for rail loading services resulting from higher basis differentials between the Bakken and U.S. western and eastern markets. The increase in demand also resulted in an increase in our storage and transportations segment’s operations and maintenance expense of $0.7 million during the year ended December 31, 2019 compared to 2018. Our storage and transportation segment’s costs of product/services sold related to our COLT Hub operations were flat during the year ended December 31, 2019 compared to 2018.

Our storage and transportation segment’s EBITDA was also impacted by a net increase of approximately $4.1 million in earnings from unconsolidated affiliates (primarily from our Stagecoach Gas equity investment) during the year ended December 31, 2019 compared to 2018. Earnings from our Stagecoach Gas equity investment increased by approximately $4.9 million during the year ended December 31, 2019 compared to 2018 due to our share of its equity earnings increasing from 40% to 50% effective July 1, 2019. Aside from this change in earnings percentage, our earnings from our Stagecoach Gas equity investment were relatively flat. This was due to demand for the natural gas storage and transportation services provided by Stagecoach Gas being relatively flat given that the Northeast market for natural gas in which Stagecoach Gas operates is experiencing declining natural gas prices and basis differentials, offset by an increase in producer activity and lack of new infrastructure being built, which is keeping the demand for Stagecoach Gas’s storage and transportation services relatively stable. In addition, in December 2019, Stagecoach Gas reached a final settlement related to its NGA Section 5 rate proceeding, the results of which is not anticipated to have a material impact on our current or future results of operations. We believe the Stagecoach Gas assets are well-positioned over the long-term to benefit from increased producer activity and access to key markets in the Northeast despite the current stable environment.

During the year ended December 31, 2019, earnings from our Tres Holdings equity investment increased by approximately $0.9 million compared to 2018. During 2018, we recorded our proportionate share of a $0.8 million loss recorded by Tres Holdings related to the disposition of certain of its assets. Earnings from our PRBIC equity investment decreased by approximately $1.7 million during the year ended December 31, 2019 compared to 2018, due to the expiration of a rail loading contract with one of its customers in mid-2018.

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

EBITDA for our storage and transportation segment increased by approximately $43.6 million during the year ended December 31, 2018 compared to 2017. The comparability of our storage and transportation segment’s EBITDA year over year was impacted by a $57 million loss on contingent consideration recorded during 2017 related to our Stagecoach Gas joint venture as further described below.

During 2017 and early 2018, several of COLT’s firm rail loading agreements expired that provided COLT with take-or-pay revenues at rates that were higher than spot market rates. As a result, COLT’s revenues decreased by approximately $16.3 million during the year ended December 31, 2018 compared to 2017 despite its rail loading volumes increasing by 28% year-over-year. The increase in volumes was due to higher demand for rail loading services resulting from higher Bakken crude oil production and higher basis differentials between Bakken and the U.S. western and eastern markets.

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Our storage and transportation segment’s EBITDA was also impacted by a net increase in earnings from unconsolidated affiliates during the year ended December 31, 2018 compared to 2017. Earnings from our Stagecoach Gas equity investment increased by approximately $4.0 million during 2018 compared to 2017, primarily due to our share of Stagecoach Gas’ equity earnings increasing from 35% to 40% effective July 1, 2018. Partially offsetting this increase were lower equity earnings from our Tres Holdings equity investment of approximately $2.2 million due to higher repair and maintenance costs at the joint venture.

Marketing, Supply and Logistics

Year Ended December 31, 2019 Compared to Year Ended December 31, 2018

EBITDA for our marketing, supply and logistics segment increased by approximately $34.5 million during the year ended December 31, 2019 compared to 2018. The comparability of our marketing, supply and logistics segment’s EBITDA was impacted by a $26.9 million loss on sale of long-lived assets recorded during the year ended December 31, 2018 related to the sale of our West Coast assets.

The sale of our West Coast assets in late 2018 resulted in lower revenues of approximately $196.2 million and lower costs of product/services sold of approximately $184.5 million compared to 2018. In addition, the sale of our West Coast assets and a related $2.9 million property tax refund received during 2019 were the primary drivers for lower operations and maintenance expenses of approximately $14.7 million during the year ended December 31, 2019 compared to 2018.

Our NGL marketing and logistics operations (other than West Coast) experienced a reduction in its revenues and costs of products/services sold of approximately $439.1 million and $439.7 million, respectively, during the year ended December 31, 2019 compared to 2018, primarily as a result of decreasing NGL prices. NGL prices decreased due to a combination of high NGL production and constrained NGL infrastructure. During both 2019 and 2018, our NGL marketing and logistics operations were able to take advantage of market disruptions, low NGL prices and unusual weather and crop drying conditions to utilize its trucking, rail and storage assets to economically source seasonal inventory and create strong margin for delivery into forward markets. Included in our costs of product/services sold was a gain of $19.5 million and $29.6 million during the years ended December 31, 2019 and 2018, respectively, related to the change in fair value of our derivative instruments which were also driven by the decreasing NGL prices described above.

Our crude and natural gas marketing operations experienced an increase in its revenues and costs of products/services sold of approximately $284.4 million and $280.6 million, respectively, during the year ended December 31, 2019 compared to 2018. These increases were driven by higher crude marketing volumes, as our crude marketing operations were able to utilize excess storage capacity and transportation assets to capitalize on opportunities created by widening WTI to Bakken basis differentials.

Year Ended December 31, 2018 Compared to Year Ended December 31, 2017

EBITDA for our marketing, supply and logistics segment increased by approximately $76.8 million during the year ended December 31, 2018 compared to 2017. The comparability of our marketing, supply and logistics segment’s results was impacted by the sale of certain of our assets during 2018 and 2017 and approximately $121.0 million of goodwill, intangible assets and property, plant and equipment impairments recorded during 2017, all of which are further described below.

During the year ended December 31, 2018, we recorded a $26.9 million loss on long-lived assets related to the sale of our West Coast facilities in October 2018, which also resulted in lower revenues and costs of product/services sold of approximately $81.4 million and $71.4 million in 2018 compared to 2017. During the year ended December 31, 2017, we recorded a $33.6 million gain related to the sale of US Salt, which also resulted in lower revenues and costs of product/services sold of approximately $59.8 million and $34.9 million during the year ended December 31, 2018 compared to 2017.

EBITDA for our marketing, supply and logistics segment (excluding the impacts from the sale of our West Coast and US Salt assets described above) was also impacted by an increase in its revenues and costs of product/services sold of approximately $614.3 million and $574.9 million during the year ended December 31, 2018 compared to 2017.

Our crude and natural gas marketing operations experienced an increase in its revenues and product costs of approximately $564.5 million and $557.6 million. These increases were driven by higher crude marketing volumes due to increased marketing activity surrounding our crude-related operations.

The remaining $32.6 million increase in our revenues (net of costs of product/services sold) during the year ended December 31, 2018 compared to 2017 was driven by our NGL marketing and logistics operations. Included in our costs of product/

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services sold was a gain of $29.6 million and a loss of $31.2 million during the years ended December 31, 2018 and 2017, respectively. Of the $29.6 million gain in 2018, approximately $18.3 million related to the change in fair value of commodity inventory-related derivative contracts that had not yet settled in cash at December 31, 2018. The remaining increase in our revenues and costs of product/services sold of our NGL marketing and logistics operations was primarily the result of our ability to capture more marketing opportunities to purchase and sell NGLs given the unusually cold weather during 2018. In addition, we experienced increased demand for trucking, rail, storage and terminal services as a result of an expanded US NGL supply base and market dislocations caused by increased NGL supplies from various high growth regions and regional pipeline outages.

During the year ended December 31, 2018, our marketing, supply and logistics segment’s operations and maintenance expenses decreased by approximately $12.6 million compared to 2017, primarily due to the sale of our West Coast and US Salt assets described above, in addition to efforts to realign certain of its operations.

Other EBITDA Results

General and Administrative Expenses. During the year ended December 31, 2019, our general and administrative expenses increased compared to 2018, while we experienced a decrease in these expenses during 2018 compared to 2017. Our unit-based compensation charges increased by approximately $18.5 million during the year ended December 31, 2019 compared to 2018 and increased by approximately $3.0 million during 2018 compared to 2017. These increases were driven by the acceleration of certain awards due to the Corporate restructuring that occurred in early 2019 and higher average awards outstanding under our long-term incentive plans during both years. In addition, during the year ended December 31, 2019, we incurred higher transaction-related costs primarily associated with our Jackalope acquisition, while during the year ended December 31, 2017, we incurred higher costs associated with the realignment of our Marketing, Supply and Logistics operations.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense. During the year ended December 31, 2019, our depreciation, amortization and accretion expense increased compared to 2018, while we experienced a decrease in our depreciation, amortization and accretion expense during 2018 compared to 2017. These changes were primarily due to the Jackalope Acquisition in April 2019, partially offset by the sale of our West Coast assets and US Salt operations during 2018 and 2017, respectively, and the deconsolidation of our Crestwood New Mexico operations in 2017. For a further discussion of these transactions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 3 and 6.

Interest and Debt Expense, Net. During the year ended December 31, 2019, interest and debt expense, net increased by approximately $16.2 million compared to 2018, primarily due to the issuance of $600 million unsecured senior notes due 2027 in April 2019 and higher average outstanding balances on our credit facility that were primarily utilized to fund growth capital expenditures during 2019. During the year ended December 31, 2018, interest and debt expense, net was relatively flat compared to 2017.

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

	Year Ended December 31,
	2019		2018		2017
Credit facilities	$	26.4	$	24.6	$	18.6
Senior notes	96.6		72.5		76.4
Other debt-related costs	6.8		7.1		7.3
Gross interest and debt expense	129.8		104.2		102.3
Less: capitalized interest	14.4		5.0		2.9
Interest and debt expense, net	$	115.4	$	99.2	$	99.4

Loss on Modification/Extinguishment of Debt. During the year ended December 31, 2018, we recognized a loss on modification of debt of approximately $0.9 million in conjunction with amending and restating Crestwood Midstream’s senior secured revolving credit facility. During the year ended December 31, 2017, we recognized a loss on extinguishment of debt of approximately $37.7 million in conjunction with the tender of the principal amounts previously outstanding under Crestwood Midstream's senior notes due in 2020 and 2022.

Liquidity and Sources of Capital

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

We make cash quarterly distributions to our common unitholders within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to our available cash for such quarter. In February 2020, we paid a quarterly distribution of $0.625 per limited partner unit, an increase of approximately 4% compared to the quarterly distributions declared throughout 2019, and we expect to maintain this quarterly distribution through 2020, subject to the board of directors’ quarterly approval. We also pay cash quarterly distributions of approximately $15 million to our preferred unitholders and quarterly cash distributions of approximately $9 million to Crestwood Niobrara’s non-controlling partner. We believe our operating cash flows will well exceed cash distributions to our partners, preferred unitholders and non-controlling partner at current levels, and as a result, we will have substantial operating cash flows as a source of liquidity for our growth capital expenditures.

As of December 31, 2019, we had $661.3 million of available capacity under our revolving credit facility considering the most restrictive debt covenants in the credit agreement. As of December 31, 2019, we were in compliance with all of our debt covenants applicable to the credit facility and our senior notes. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 9 for a more detailed description of the covenants related to our credit facility and senior notes.

Cash Flows

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

	Year Ended December 31,
	2019			2018			2017
Net cash provided by operating activities	$	420.4		$	253.6		$	255.9
Net cash provided by (used in) investing activities	(943.7		)	(241.2		)	38.7
Net cash provided by (used in) financing activities	531.8			3.5			(294.9		)

Operating Activities

Our operating cash flows increased by approximately $166.8 million during the year ended December 31, 2019 compared to 2018. The increase was primarily driven by lower costs of product/services sold of approximately $584.5 million primarily from our marketing, supply and logistics segment’s and gathering and processing segment’s operations, partially offset by lower revenues of approximately $472.2 million primarily from these segments as discussed above in Results of Operations above. In addition, we had a net cash inflow from working capital requirements of approximately $47.8 million.

Our operating cash flows decreased by $2.3 million during the year ended December 31, 2018 compared to 2017. We experienced higher revenues and costs primarily from our gathering and processing segment’s Arrow operations of $362.0 million and $334.8 million, respectively, and higher revenues (net of costs of product/services sold) from our marketing, supply and logistics segment’s NGL marketing and logistics operations of approximately $32.6 million. Offsetting these higher revenues and costs was a $16.3 million decrease in operating revenues from our COLT Hub operations and a net cash outflow from working capital requirements of approximately $47.2 million.

Investing Activities

Capital Expenditures. 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

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

During 2020, we anticipate growth capital expenditures of approximately $150 million to $200 million, which includes contributions to our equity investments related to their capital projects. In addition, we expect to spend between approximately $20 million to $25 million on maintenance capital expenditures and approximately $30 million to $40 million on capital expenditures that are directly reimbursable by our customers. We anticipate that our growth and reimbursable capital expenditures in 2020 will increase the services we can provide to our customers and the operating efficiencies of our systems. We expect to finance our capital expenditures with a combination of cash generated by our operating subsidiaries, distributions received from our equity investments and borrowings under our credit facility.

We have identified growth capital project opportunities for our reporting segments. Additional commitments or expenditures will be made at our discretion, and any discontinuation of the construction of these projects will likely result in less future cash flows and earnings. The following table summarizes our capital expenditures for the year ended December 31, 2019 (in millions):

Growth capital	$	384.2
Maintenance capital	19.1
Other(1)	52.2
Purchases of property, plant and equipment	$	455.5

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

Investments in Unconsolidated Affiliates. During the year ended December 31, 2019, we contributed approximately $28.3 million to our Crestwood Permian equity investment primarily to fund its expansion projects and contributed $8.6 million to our Stagecoach Gas, Tres Holdings and PRBIC equity investments for other operating purposes. We also contributed $24.4 million to our Jackalope equity investment prior to our acquisition of the remaining 50% equity interest in Jackalope from Williams, and this contribution was primarily utilized by us after Jackalope’s consolidation to fund its growth capital expenditures. During 2018 and 2017, we contributed approximately $64.4 million and $58.0 million to our equity investments to fund their expansion projects and other operating activities.

Acquisition and Divestitures. Below is a summary of the acquisition and divestitures which impacted our investing activities during the years ended December 31, 2019, 2018 and 2017.

• In April 2019, Crestwood Niobrara acquired Williams’ 50% equity interest in Jackalope for approximately $462.1 million, net of cash acquired of approximately $22.5 million;

• In October 2018, we sold our West Coast facilities to a third party for net proceeds of approximately $70.5 million; and

• In December 2017, we sold 100% of our equity interests in US Salt to an affiliate of Kissner Group Holdings LP for net proceeds of approximately $223.6 million.

Financing Activities

Significant items impacting our financing activities during the years ended December 31, 2019, 2018 and 2017 included the following:

Equity Transactions

• In April 2019, Crestwood Niobrara issued $235 million in new Series A-3 preferred units to Jackalope Holdings in conjunction with Crestwood Niobrara’s acquisition of the remaining 50% equity interest in Jackalope from Williams. For a further discussion of this transaction, See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 12;

• In December 2017, Crestwood Niobrara redeemed 100% of the outstanding Series A preferred units issued to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE) for an aggregate purchase price of $202.7 million and issued $175 million of new Series A-2 preferred units to Jackalope Holdings. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 12. We began making distributions to Jackalope Holdings on its Series A-2 preferred units in April 2018.

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• During the years ended December 31, 2019, 2018 and 2017, Crestwood Niobrara paid cash distributions of approximately $25.0 million, $9.9 million and $15.2 million to its non-controlling partner;

• During the years ended December 31, 2019, 2018 and 2017, we made cash distributions of approximately $60.1 million, $60.1 million and $15 million to our preferred unitholders. Prior to September 30, 2017, we paid quarterly distributions to our preferred unitholders by issuing additional preferred units;

• During the year ended December 31, 2019, our distributions to partners increased by approximately $1.6 million compared to 2018 and approximately $3.2 million during 2018 compared to 2017. These increases were due to an increase in our common units outstanding;

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

• During the year ended December 31, 2019, our taxes paid for unit-based compensation vesting increased by approximately $3.6 million compared to 2018 and by approximately $1.9 million during 2018 compared to 2017, primarily due to higher vesting of unit-based compensation awards.

Debt Transactions

• During the year ended December 31, 2019, our debt-related transactions resulted in net proceeds of approximately $568.8 million compared to net proceeds of approximately $253.4 million in 2018 and net repayments of approximately $76.3 million in 2017. During 2019, we issued $600 million unsecured senior notes due 2027 and during 2017, we issued $500 million of senior unsecured notes due in 2025. During 2017, we redeemed all amounts previously outstanding under Crestwood Midstream’s senior notes due in 2020 and 2022. For a further discussion of these and other debt-related transactions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 9.

Contractual Obligations

We are party to various contractual obligations. A portion of these obligations are reflected in our consolidated financial statements, such as long-term debt, leases and other accrued liabilities, while other obligations, such as capital and other commitments and contractual interest amounts are not reflected on our consolidated balance sheets. The following table and discussion summarizes our contractual cash obligations as of December 31, 2019 (in millions):

	Less than 1 Year		1-3 Years		3-5 Years		Thereafter		Total
Long-term debt:
Principal	$	0.2	$	0.4	$	1,257.0	$	1,100.0	$	2,357.6
Interest(1)	128.6		257.1		158.2		85.9		629.8
Standby letters of credit	31.7		—		—		—		31.7
Future minimum payments under leases(2)	24.5		32.9		12.8		7.5		77.7
Asset retirement obligations	1.5		—		—		33.3		34.8
Fixed price commodity purchase commitments(3)	712.3		80.1		—		—		792.4
Purchase commitments and other contractual obligations(4)	133.3		—		—		—		133.3
Total contractual obligations	$	1,032.1	$	370.5	$	1,428.0	$	1,226.7	$	4,057.3

(1) $557.0 million of our long-term debt is variable interest rate debt at the Alternate Base rate or Eurodollar rate plus an applicable spread. These rates plus their applicable spreads were between 3.96% and 6.00% at December 31, 2019. These rates have been applied for each period presented in the table.

(2) Includes our operating and finance leases. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 15 for a further discussion of these obligations.

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

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

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Off-Balance Sheet Arrangements

As of December 31, 2019, we have not entered into any transactions, agreements or other arrangements that would result in off-balance sheet liabilities.

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

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, 2019, both the carrying value and fair value of our fixed rate debt instruments was approximately $1.8 billion. As of December 31, 2018, the carrying value and fair value of our fixed rate debt instruments was approximately $1.2 billion and $1.1 billion. For a further discussion of our fixed rate debt, see Part IV, Item 15. Exhibits and Financial Statement Schedules, Note 9.

We are subject to the risk of loss associated with changes in interest rates on our credit facility. At December 31, 2019, we had obligations totaling $557.0 million outstanding under the credit facility. These obligations expose us to the risk of increased interest payments in the event of increases in short-term interest rates. Floating rate obligations expose us to the risk of increased interest expense in the event of increases in short-term interest rates. If the interest rate on our credit facility were to fluctuate by 1% from the rate as of December 31, 2019, our annual interest expense would have changed by approximately $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) the NGLs and crude oil marketed or supplied by our NGL and crude oil supply and logistics operations (MS&L segment); (ii) NGLs under certain of our percentage-of-proceeds contracts (G&P segment); and (iii) crude oil and natural gas purchased from our Arrow producer customers (G&P segment).  Our current business model is designed to minimize our exposure to fluctuations in commodity prices, although we are willing to assume commodity price risk in certain processing and marketing activities.  We remain subject to volumetric risk under contracts without minimal volume commitments or take-or-pay pricing terms, but absent other market factors that could adversely impact our operations (i.e., market conditions that negatively influence our producer customers’ decisions to develop or produce hydrocarbons), changes in the price of natural gas, NGLs or crude oil should not materially impact our operations. 

In our marketing, supply and logistics operations, we consider market risk to be the risk that the value of our NGL and crude services portfolio will change, either favorably or unfavorably, in response to changing market conditions. We take an active role in managing and controlling market risk and have established control procedures, which are reviewed on an ongoing basis. We monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with assets from price risk management activities as of December 31, 2019, were energy marketers, propane retailers, resellers, and dealers.

We engage in hedging and risk management transactions, including various types of forward contracts, options, swaps and futures contracts, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions and to help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by

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purchasing volumes only when we have a matching purchase commitment from our marketing customers. However, we may experience net unbalanced positions from time to time, which we believe to be immaterial in amount. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio. These derivatives are not designated as hedges for accounting purposes.

The fair value of the derivatives contracts related to price risk management activities as of December 31, 2019 were assets of $43.2 million and liabilities of $6.7 million. We use observable market values for determining the fair value of our trading instruments. In cases where actively quoted prices are not available, other external sources are used that incorporate information about commodity prices in actively quoted markets, quoted prices in less active markets and other market fundamental analysis. Our risk management function regularly compares valuations to independent sources and models on a quarterly basis. The following table represents the net unbalanced position of our commodity-based derivatives at December 31, 2019, the change in market value of our commodity-based derivatives based upon a theoretical change of 10% in the underlying value of the respective derivatives, and the inventory positions that would substantially offset this theoretical change:

	December 31, 2019
	Net Unbalanced Position (MMBbls)	Market Value Change (in millions)		Inventory Position (MMBbls)
Natural gas	0.5	$	1.1	—
NGLs	2.4	4.4		1.9
Crude oil	0.7	3.9		0.5
Total	3.6	$	9.4	2.4

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 November 2019, Chesapeake, our major customer in the Powder River Basin, announced that continued low commodity prices could negatively impact their cash flows and financial condition, and raised substantial doubt about its ability to continue as a going concern given the financial covenants contained in their debt agreements. Subsequent to their announcement, Chesapeake announced that it had refinanced certain amounts of its debt and amended its debt covenants to alleviate certain of its liquidity concerns. Although Chesapeake is current on all amounts due to us, we are closely monitoring our exposure to Chesapeake to ensure they continue to promptly pay amounts invoiced to them.

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

Item 8. Financial Statements and Supplementary Data

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

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

None.

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Item 9A. Controls and Procedures

Disclosure Controls and Procedures

As of December 31, 2019, Crestwood Equity and Crestwood Midstream carried out an evaluation under the supervision and with the participation of their respective management, including the Chief Executive Officers and Chief Financial Officers of their General Partners, as to the effectiveness, design and operation of our disclosure controls and procedures (as defined in the Securities Exchange Act of 1934, as amended (Exchange Act) Rules 13a-15(e) and 15d-15(e)). Crestwood Equity and Crestwood Midstream maintain controls and procedures designed to provide reasonable assurance that information required to be disclosed in their respective reports that are filed or submitted under the Exchange Act of 1934, as amended, are recorded, processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information is accumulated and communicated to their respective management, including the Chief Executive Officers and Chief Financial Officers of their General Partners, as appropriate, to allow timely decisions regarding required disclosure. Such management, including the Chief Executive Officers and Chief Financial Officers of their General Partners, does not expect that the disclosure controls and procedures or the internal controls will prevent and/or detect all errors and all fraud. A control system, no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the benefits of controls must be considered relative to their costs. Crestwood Equity’s and Crestwood Midstream’s disclosure controls and procedures are designed to provide reasonable assurance of achieving their objectives and the Chief Executive Officers and Chief Financial Officers of their General Partners concluded that such disclosure controls and procedures were effective at the reasonable assurance level as of December 31, 2019.

Changes in Internal Control over Financial Reporting

There have been no changes in Crestwood Equity’s or Crestwood Midstream’s internal control over financial reporting during the fourth quarter of 2019 that have materially affected, or are reasonably likely to materially affect Crestwood Equity’s and Crestwood Midstream’s internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

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

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

On April 9, 2019, we acquired the remaining 50% equity interest in Jackalope from Williams. Management’s assessment of and conclusion on the effectiveness of internal control over financial reporting as of December 31, 2019 excluded Jackalope. The financial reporting systems of Jackalope were not fully integrated into our financial reporting systems throughout 2019. Therefore, we did not have the practical ability to perform an assessment of their internal controls in time for this current year-end. We fully expect to include Jackalope in next year’s assessment. Jackalope constituted $1,147.3 million, $70.1 million and $20.9 million in total assets, revenues and net income, respectively, in our consolidated financial statements.

Under the supervision and with the participation of Crestwood Equity’s and Crestwood Midstream’s management, including the Chief Executive Officers and Chief Financial Officers of their General Partners, Crestwood Equity and Crestwood Midstream assessed the effectiveness of their respective internal control over financial reporting as of December 31, 2019. In making this assessment, Crestwood Equity and Crestwood Midstream used the criteria set forth in the Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based upon such assessment, Crestwood Equity and Crestwood Midstream concluded that, as of December 31, 2019, their respective internal control over financial reporting is effective, based upon those criteria.

Crestwood Equity’s independent registered public accounting firm, Ernst & Young LLP, issued an attestation report dated February 21, 2020, on the effectiveness of our internal control over financial reporting, which is included herein.

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Item 9B. Other Information

On February 20, 2020, John W. Somerhalder, II provided notice of his resignation from the board of directors (the Board) of Crestwood Equity GP LLC, a Delaware limited liability company (CEQP GP) and the general partner of Crestwood Equity Partners LP, a Delaware limited partnership (the Partnership), effective immediately. The resignation of Mr. Somerhalder is not as a result of any disagreement with CEQP GP or the Partnership regarding any matter related to the operations, policies or practices of CEQP GP or the Partnership. Mr. Somerhalder resigned from the Board due to his appointment as the interim President and Chief Executive Officer of CenterPoint Energy, Inc.

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PART III

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

Item 10. Directors, Executive Officers and Corporate Governance

Our General Partner Manages Crestwood Equity Partners LP

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

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

Directors and Executive Officers

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

Executive Officers and Directors	Age	Position with our General Partner
Robert G. Phillips	65	President, Chief Executive Officer and Director
Robert T. Halpin	36	Executive Vice President, Chief Financial Officer
Steven M. Dougherty	47	Executive Vice President, Chief Accounting Officer
Joel C. Lambert	51	Executive Vice President, Chief Legal, Compliance and Safety Officer
William H. Moore	40	Executive Vice President, Corporate Strategy
Alvin Bledsoe	71	Director
William Brown	38	Director
Warren H. Gfeller	67	Director
Janeen S. Judah	60	Director
David Lumpkins	65	Director
Gary D. Reaves	40	Director
John J. Sherman	64	Director

Robert G. Phillips was elected Chairman, President and Chief Executive Officer of our general partner in June 2013 and has served on the Management Committee of Crestwood Holdings since May 2010. He served as Chairman, President and CEO of Legacy Crestwood from November 2007 until October 2013. Previously, Mr. Phillips served as President and Chief Executive Officer and a Director of Enterprise Products Partners L.P. from February 2005 until June 2007 and Chief Operating Officer and a Director of Enterprise Products Partners L.P. from September 2004 until February 2005. Mr. Phillips also served on the Board of Directors of Enterprise GP Holdings L.P., the general partner of Enterprise Products Partners L.P., from February 2006 until April 2007. He previously served as Chairman of the Board and CEO of GulfTerra Energy Partners, L.P. (GTM) from 1999 to 2004 prior to GTM’s merger with Enterprise Product Partners, LP, and held senior executive management positions with El Paso Corporation, including President of El Paso Field Services from 1996 to 2004. Prior to that he was Chairman, President and CEO of Eastex Energy, Inc. from 1981 to1995. Mr. Phillips previously served as a Director of Pride International, Inc. from October 2007 to May 31, 2011, one of the world’s largest offshore drilling contractors, and was a member of its audit committee. Mr. Phillips has served as a Director of Bonavista Energy Corporation, a Canadian independent oil and gas producer, since May 2015. Mr. Phillips holds a B.B.A. from The University of Texas at Austin and a Juris

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

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

Steven M. Dougherty was appointed Executive Vice President and Chief Accounting Officer of our general partner in January 2020. He served as Senior Vice President and Chief Accounting Officer of our general partner from October 2013 to January 2020. He served as Senior Vice President, Interim Chief Financial Officer and Chief Accounting Officer of Legacy Crestwood from January 2013 to October 2013. Mr. Dougherty had served as Vice President and Chief Accounting Officer of Legacy Crestwood since June 2012. Prior to joining Legacy Crestwood, Mr. Dougherty was Director of Corporate Accounting at El Paso Corporation (El Paso) 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 Executive Vice President, Chief Legal, Compliance and Safety Officer in January 2020. He served as Senior Vice President, General Counsel and Chief Compliance Officer of our general partner from August 2017 to January 2020. He served as Senior Vice President, General Counsel and Corporate Secretary of our general partner from October 2013 to August 2017. He served as a director of Legacy Crestwood from October 2010 to October 2013. From 2007 until October 2013, Mr. Lambert served as Vice President, Legal of First Reserve Corporation, a private equity company which invests exclusively in the energy industry. From 1998 to 2006, Mr. Lambert was an attorney in the Business and International Section of Vinson & Elkins LLP. In 1997, he was an Intern at the Texas Supreme Court, and has served as a Military Intelligence Specialist for the United States Army. Mr. Lambert holds a Bachelor of Environmental Design from Texas A&M University and a Juris Doctorate from The University of Texas School of Law.

William H. Moore was appointed Executive Vice President, Corporate Strategy of our general partner in January 2020. He served as Senior Vice President, Strategy and Corporate Development of our general partner from October 2013 to January 2020. He joined Legacy Inergy in 2005 as a legal analyst and has held various positions in corporate and business development, including Vice President, Corporate Development. Mr. Moore holds an M.B.A from Fort Hays State University, and a Juris Doctorate from the University of Kansas School of Law.

Alvin Bledsoe was appointed a director of our general partner in October 2013. He served as a director of Crestwood Midstream GP LLC (CMLP GP) from October 2013 to October 2015 and as a director of Legacy Crestwood from July 2007 until October 2013. Mr. Bledsoe currently serves as a director and audit committee chair of SunCoke Energy, Inc. and as a director of Gulfport Energy Corporation. Prior to his retirement in 2005, Mr. Bledsoe served as a certified public accountant and served in 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.

William Brown was appointed a director of our general partner in May 2019. Mr. Brown is a Managing Director at First Reserve, a leading global private equity investment firm exclusively focused on energy, which he joined in 2006. Prior to joining First Reserve as an Associate, he was an Investment Banking Analyst at Banc of America Securities LLC. Mr. Brown was appointed to serve as a director of our general partner due to his years of experience in investment origination and structuring, due diligence, execution and monitoring, with an emphasis on the equipment, manufacturing and midstream energy sectors. Mr. Brown holds a B.S. from Duke University and a M.B.A. from Columbia Business School.

Warren H. Gfeller has been a member of our general partner’s board of directors since March 2001. He served as a director of CMLP GP from December 2011 to October 2015. He has engaged in private investments since 1991. From 1984 to 1991, Mr.

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

Janeen S. Judah was appointed as a director of our general partner in November 2018. She currently serves as a Director at Patterson-UTI Energy, Inc. and Jagged Peak Energy Inc. Ms. Judah previously held numerous leadership positions at Chevron Corporation (Chevron), including general manager for Chevron’s Southern Africa business unit, president of Chevron Environmental Management Company and general manager of Reservoir and Production Engineering for Chevron Energy Technology Company. Ms. Judah was appointed to the board due to her more than 35 years of operational and managerial experience within the energy industry. Ms. Judah holds Bachelor of Science and Masters of Science degrees in petroleum engineering from Texas A&M University, a Masters of Business Administration from The University of Texas of the Permian Basin and a Juris Doctorate from the University of Houston Law Center. Ms. Judah’s diverse energy experience as well as her environmental expertise adds significant value to our board of directors.

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

Gary D. Reaves was appointed to the board of our general partner in January 2019. Mr. Reaves is a Managing Director at First Reserve, a leading global private equity investment firm exclusively focused on energy, which he joined in 2006. Prior to joining First Reserve, he held roles in the Global Energy Group at UBS Investment Bank and Howard Frazier Barker Elliott, Inc. Mr. Reaves 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. Mr. Reaves holds a B.B.A from The University of Texas.

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

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, Janeen Judah 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.

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Board Committees

Audit Committee

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

Compensation Committee

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

Conflicts Committee

Our general partner has established a conflicts committee to review specific matters which the board of directors believes may involve conflicts of interest. The 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

The members of the finance committee are David Lumpkins (Chairman) and Warren Gfeller. 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.

Sustainability Committee

The member of the sustainability committee is Janeen Judah (Chairman). Our general partner has established a sustainability committee to provide oversight of our sustainability initiatives and to ensure that environmental, social and governance risks are incorporated into our long-term business strategy. The sustainability committee will also oversee the development of our sustainability strategy, as well as review and recommend to the board for approval any sustainability reporting and disclosure.

Board Leadership Structure

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

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Risk Oversight

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

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

Meetings of Non-Management Directors

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

Communication with the Board of Directors

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

Code of Ethics/Governance Guidelines

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

Section 16(a) Beneficial Ownership Reporting Compliance

Section 16(a) of the Securities Exchange Act of 1934 requires our company’s directors and executive officers, and persons who own more than 10% of any class of equity securities of our company registered under Section 12 of the Exchange Act, to file with the Securities and Exchange Commission initial reports of ownership and report of changes in ownership in such securities and other equity securities of our company. Securities and Exchange Commission regulations require directors, executive officers and greater than 10% unitholders to furnish our company with copies of all Section 16(a) reports they file. To our knowledge, based solely on review of the reports furnished to us and written representations that no other reports were required, during the fiscal year ended December 31, 2019, all section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% unitholders, were met.

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Item 11. Executive Compensation

Compensation Discussion and Analysis

Introduction

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

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

For purposes of this Compensation Discussion and Analysis our NEOs for Fiscal 2019 were comprised of:

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

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

•William H. Moore, our Executive Vice President, Corporate Strategy;

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

• Joel C. Lambert, our Executive Vice President, Chief Legal, Compliance and Safety Officer; and

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

Compensation Philosophy and Objectives

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

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

• balancing short and long-term performance;

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

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

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

Compensation Setting Process

Role of Management

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

Chief Executive Officer’s Role in the Compensation Setting Process

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

• assisting in establishing business performance goals and objectives;

• evaluating executive officer and company performance;

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

• implementing the approved compensation plans.

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Our CEO makes recommendations to the compensation committee with respect to financial metrics to be used and determination of performance for performance-based awards as well as other recommendations regarding non-CEO executive compensation, which may be based on our performance, individual performance and the peer group compensation market analysis. The compensation committee considers this information when establishing the total compensation packages of our executive officers. The CEO’s performance and compensation is reviewed, evaluated and established separately by the compensation committee and the full board based on criteria similar to those used for non-CEO executive compensation. The board of directors reviews and ratifies all aspects of executive compensation based on the reports and recommendations from the compensation committee.

Role of the Compensation Committee

For all NEOs, except the CEO, the compensation committee reviews the CEO’s recommendations, supporting market data, and individual performance assessments. In addition, the compensation committee reviews the reasonableness of the CEO’s pay recommendations based on a competitive market study that includes proxy and annual report data from the approved comparator peer group and published compensation survey data. For the CEO, in fiscal 2019 the board of directors met in executive session without management present to review the CEO’s performance. In this session, the board of directors reviewed:

• Evaluations of the CEO completed by the board members;

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

• Business performance of the Company relative to established targets.

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

Role of the Compensation Consultant

Willis Towers Watson is our third-party compensation consultant. Our compensation committee and management believe it is beneficial to have an independent third-party analysis to assist in evaluating and setting executive compensation. Management, in consultation with the compensation committee, chose Willis Towers Watson based on its extensive experience in providing executive compensation advice, including specific experience in the oil and gas industry. For fiscal 2019, Willis Towers Watson provided management and the compensation committee with an analysis of our executive compensation programs, including total direct compensation comprised of base salary, annual incentive and long-term incentive compensation, in order to assess the competitiveness of our programs and to provide conclusions and recommendation. Our compensation committee has taken and will take into consideration the discussions, guidance and compensation studies produced by our compensation consultant in order to make compensation decisions. The compensation committee has assessed the independence of the compensation consultant and has concluded that the compensation consultant’s work for the compensation committee does not raise any conflict of interest.

Competitive Benchmarking and Peer Group

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

After discussion with Willis Towers Watson and reviewing its recommendation of a peer group based on companies with annual revenues, assets and net income similar to ours and taking into account geographic footprint and employee count, our compensation committee determined that the peer group listed below was the most appropriate for purposes of the 2019 executive compensation analyses.

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Buckeye Partners, L.P.	NuStar Energy, L.P.
DCP Midstream Partners, LP	SemGroup Corporation
Enable Midstream Partners, LP	Summit Midstream Partners, LP
EnLink Midstream Partners, LP	Sprague Resources LP
EQM Midstream Partners, LP	Tallgrass Energy Partners, LP
Genesis Energy LP	Targa Resources Corp.
Magellan Midstream Partners, L.P.	Western Gas Partners, LP
MPLX, LP

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

The compensation committee strives to maintain average total compensation for our executive officers between the 50th and 75th percentile of the peer group with target base and short-term incentives at the 50th percentile and target long-term incentives at the 75th percentile.

Elements of Compensation

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

• base salary;

• incentive awards;

• long-term incentive plan awards; and

• retirement and health benefits.

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

Base Salary

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

Base salaries for our NEOs are reviewed on an annual basis and at the time of promotion or other change in responsibilities. In determining the amount of any adjustments, the compensation committee uses market data as a tool for assessing the reasonableness of the base salary amounts of the NEOs as compared to the compensation of executives in similar positions with similar responsibility levels in our industry. However, the final determination of base salary amounts was within the compensation committee’s discretion. Based on our objective to maintain target average base compensation at the 50^th percentile of the market data, the compensation committee approved increases for our NEOs effective January 1, 2018. Accordingly, the annual base salaries were increased as follows: Mr. Phillips ($775,000), Mr. Halpin ($465,000), Mr. Dougherty ($422,000), Mr. Lambert ($435,000) and Mr. Moore ($385,000).

Annual Incentive Awards

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

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Annual incentive target payouts were initially established for each of our NEOs pursuant to their Employment Agreements. For a more detailed description of the Executive Employment Agreements, see “Narrative Disclosure to Summary Compensation and Grants of Plan Based Awards Tables-Executive Employment Agreements.” The annual target bonus amounts of our NEOs are reviewed on an annual basis and at the time of promotion or other change in responsibilities. In determining the amount of any adjustments, the compensation committee uses market data as a tool for assessing the reasonableness of the annual incentive targets of the NEOs as compared to executives in similar positions with similar responsibility levels in our industry. However, the final determination of annual target bonus amounts is within the compensation committee’s discretion.

Actual bonuses for 2019 were determined based on our achievement of compensation committee approved key performance indicators (KPIs) and a board discretionary component. The KPIs for fiscal 2019 were Distributable Cash Flow Per Common Unit, Adjusted EBITDA, Total Shareholder Return Relative to Peers, Safety and Optimization and Sustainability. Each KPI is then weighted based on the relative impact to our overall compensation philosophy and objectives. Actual results between the minimum and maximum target thresholds are pro-rated based on the percentage of target reached. Actual results above the maximum threshold are capped at 140% and results below 40% achievement result in 0% achievement for that KPI, excluding total shareholder return relative to peers. The board discretionary component allows our board of directors the ability to increase the total recommended bonus pool as much as 25% or decrease the bonus pool by as much as 20% based on qualitative factors deemed relevant by the board.

2019 Annual Incentive Awards KPIs	Weighting		2019 Target			2019 Actual			% Achievement
Distributable Cash Flow Per Common Unit	30	%	$	3.86		$	4.17		108	%
Adjusted EBITDA	30	%	$	511.6		$	526.5		103	%
Relative Total Shareholder Return	10	%	100		%	140		%	140	%
Total Recordable Incident Rate	4	%	1.6			0.7			140	%
Preventable Vehicle Incident Rate	4	%	1.6			1.1			131	%
Lost Time Injury Rate	4	%	0.8			0.6			125	%
Contractor TRIR on Growth/Maintenance Capital	2	%	1.6			1.0			138	%
Safety and Compliance Leading Indicators (1)	6	%	*			*			109	%
Optimization and Sustainability Achievements (2)	10	%	*			*			90	%

(1) Safety and compliance leading indicators consist of near miss/unsafe act reporting, on-time completion of compliance tasks, positive inspection reports and training completion.

(2) Optimization and sustainability achievements consist of achieving cost savings goals, on-time sustainability report issuance, implementing new system/process improvements, on-time HR initiative execution and completion of certain projects on-time and on-budget.

Based on the company’s KPI achievement, the actual annual incentive bonus pool for fiscal 2019 was established at 115% of target amount. The actual bonus amount paid to the individual NEO is then adjusted based on the individual performance review for such NEO. For 2019, four of our NEOs received the highest performance rating of “1” which increased the actual percentage for such individuals to 140% of target, which is equivalent to the company-wide target payout for “1” performance ratings. One NEO received a “2” performance rating, which increase the actual percentage for such individual to 125% of target.

The 2019 bonus payouts were as follows:

Name	2019 Base Salary ($)	Target Bonus ($)	Percentage of Target Bonus	Total ($)
Robert G. Phillips	775,000	775,000	140%	1,085,000
Robert T. Halpin	465,000	465,000	140%	651,000
William H. Moore	385,000	385,000	140%	539,000
Steven M. Dougherty	422,000	337,600	140%	472,640
Joel C. Lambert	435,000	348,000	125%	435,000

In addition to annual incentive awards, from time to time the compensation committee may award one-time project completion bonuses. The amount of these awards is recommended by management to the compensation committee based on the size of the

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project, the strategic importance of the project to the company and the respective individual’s efforts in sourcing and completing the project. There were no project completion bonus awards in 2019.

Long-Term Incentive Plan Awards

Long-term incentive awards for the NEOs are granted under the Crestwood Equity Partners LP Long Term Incentive Plan in order to promote achievement of our primary long-term strategic business objective of increasing distributable cash flow and increasing unitholder value. This plan was designed to align the economic interests of key employees and directors with those of our common unitholders and to provide an incentive to management for continuous employment with the general partner and its affiliates. Long-term incentive compensation is based upon the common units representing limited partnership interests in us. For fiscal 2019, awards consisted of grants of restricted common units which vest based upon continued service. Long-term incentive plan awards are designed to attract and retain executive talent and to align their economic interests with those of common unitholders.

The initial annual long-term equity incentive targets for our NEOs were established in their Employment Agreements. For a more detailed description of the Executive Employment Agreements, see “Narrative Disclosure to Summary Compensation and Grants of Plan Based Awards Tables-Employment Agreements.” The annual target long-term equity incentives for our NEOs are reviewed on an annual basis and at the time of promotion or other changes in responsibilities. In determining the amount of any adjustments, the compensation committee uses market data as a tool for assessing the reasonableness of long-term incentive targets of the NEOs as compared to executives in similar positions with similar responsibility levels in our industry. However, the final determination of long-term equity awards is within the compensation committee’s discretion. Based on our objective of setting long-term incentive equity awards at the 75^th percentile of market data, the annual target long-term incentive awards were increased in 2019 as follows: Mr. Phillips (400%), Messrs. Halpin and Deneke (275%), Mr. Lambert (250%) and Messrs. Moore and Dougherty (225%). Accordingly, the following annual restricted unit awards were made to our NEOs in 2019:

Name	Target Equity Percentage	2019 Restricted Units Awarded (#)	Value at Grant Date ($)
Robert G. Phillips	400%	111,071	3,476,522
Robert T. Halpin	275%	45,817	1,434,072
William H. Moore	225%	31,037	971,458
Steven M. Dougherty	225%	34,020	1,064,826
Joel C. Lambert	250%	38,965	1,219,605
J. Heath Deneke	275%	53,207	1,665,379

The annual restricted unit grants pay partnership distributions in cash in the same amount that would be payable to the holder as if he/she were the holder of common units.

In addition to the annual restricted unit grants, our NEOs are eligible to receive performance phantom unit awards. In fiscal 2019, each of our NEOs received a grant of performance phantom units. These performance phantom units vest over a three-year performance period and are paid out based on a performance multiplier ranging between 50% and 200%, determined based on the actual performance in the third year of the performance period compared to pre-established performance goals. The performance goals were based on achieving a specified level of distributable cash flow per unit, Adjusted EBITDA, return on capital invested, and three-year relative total shareholder return, based on the Partnership’s percentile ranking as compared with companies that are contained in the Alerian MLP Index at the time the goals were set. The compensation committee selected these metrics because we believe these are the key value indicators for our unitholders and will most closely align the interests of our NEOs with those of our unitholders. The compensation committee then weighted the four performance measures as follows:

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

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For all performance unit grants, the last year of the respective performance period is used to measure whether the performance goal is achieved. The payout multiplier for performance equal or greater than threshold is determined on a linear scale between performance levels.

In making the 2019 performance unit grants to our NEOs, the compensation committee considered:

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

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

Based on this analysis, the compensation committee approved the following grants of performance units to our named executive officers on February 12, 2019:

	Performance Units
Name	Minimum (#)	Target (#)	Maximum (#)	Value at Grant Date ($)
Robert G. Phillips	53,744	107,488	214,976	3,677,599
Robert T. Halpin	14,332	28,663	57,326	980,668
William H. Moore	10,749	21,497	42,994	735,506
Steven M. Dougherty	10,749	21,497	42,994	735,506
Joel C. Lambert	13,436	26,872	53,744	919,393
Heath Deneke	16,123	32,246	64,492	1,103,263

The performance phantom units are entitled to partnership distributions in the same amount that would be payable to the holder of common units. However, distributions paid on performance phantom units are paid in additional performance units in lieu of cash and such additional performance units are subject to the same performance, vesting and forfeiture provisions as the original performance phantom units.

Risk Assessment Related to our Compensation Structure

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

Severance and Change of Control Benefits

Our NEOs are entitled to certain severance and change in control benefits as provided in their respective Executive Employment Agreements. For a detailed description of the Executive Employment Agreements for our NEOs, see “Potential Payments upon a Change in Control or Termination during Fiscal 2019.”

Other Compensation Related Matters

Retirement and Health Benefits

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

Perquisites and Other Compensation

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

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Tax Deductibility of Compensation

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

Compensation Committee Report

We have reviewed and discussed the foregoing Compensation Discussion and Analysis with management. Based on our review and discussion with management, we have recommended that the Compensation Discussion and Analysis be included in this Annual Report on Form 10-K for the year ended December 31, 2019.

Members of the Compensation Committee

Warren Gfeller

Alvin Bledsoe

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Summary Compensation Table for Fiscal 2019

The following table sets forth the cash and non-cash compensation earned by our NEOs for the fiscal years ended December 31, 2019, 2018, and 2017.

Name and Principal Position	Fiscal Year	Salary ($)	Bonus ($)	Unit Awards ($)(2)	Non-Equity Incentive Plan Compensation ($)	All Other Compensation ($)(3)	Total ($)
Robert G. Phillips President, Chief Executive Officer and Director	2019	774,038	—	7,154,121	1,085,000	52,138	9,065,297
	2018	747,102	—	4,120,109	1,125,000	17,388	6,009,599
	2017	674,650	1,000	4,702,856	961,875	44,439	6,384,820
Robert T. Halpin Executive Vice President, Chief Financial Officer	2019	464,423	—	2,414,740	651,000	21,705	3,551,868
	2018	448,538	—	3,123,311	675,000	16,344	4,263,193
	2017	412,000	1,000	2,091,101	554,040	16,344	3,074,485
William H. Moore Executive Vice President, Corporate Strategy	2019	385,000	—	1,706,964	539,000	20,379	2,651,343
	2018	384,058	—	2,319,731	577,500	16,254	3,297,543
	2017	360,500	201,000	1,385,905	503,550	16,254	2,467,209
Steven M. Dougherty Executive Vice President, Chief Accounting Officer	2019	421,538	—	1,800,332	472,640	21,654	2,716,164
	2018	409,087	—	2,178,202	492,000	16,470	3,095,759
	2017	386,250	1,000	1,412,505	429,840	16,470	2,246,065
Joel C. Lambert Executive Vice President, Chief Legal, Compliance and Safety Officer	2019	434,038	—	2,138,998	435,000	22,839	3,030,875
	2018	409,087	—	2,178,202	492,000	16,614	3,095,903
J. Heath Deneke(1) Former Executive Vice President and Chief Operating Officer	2019	192,421	—	2,768,642	—	1,097,728	4,058,791
	2018	525,000	10,000	1,421,359	984,375	16,470	2,957,204
	2017	504,375	11,000	4,434,069	740,036	16,387	5,705,867

(1) On March 25, 2019, Crestwood Operations LLC entered into a Separation Agreement and Release (Separation Agreement) with J. Heath Deneke, the Company’s former Executive Vice President and Chief Operating Officer. Under the Separation Agreement, Mr. Deneke’s employment terminated effective April 15, 2019. Mr. Deneke received (i) $1,078,620 of severance payments, (ii) reimbursement for the employer contribution portion of elected COBRA coverage for a period of up to 12 months and (iii) accelerated vesting of all his unvested restricted units.

(2) The material terms of our outstanding LTIP awards are described in “Compensation Discussion and Analysis - Long-Term Incentive Plan Awards.” Unit award amounts reflect the aggregate grant date fair value of unit awards granted during the periods presented calculated in accordance with Accounting Standards Codification Topic 718, Compensation - Stock Compensation (ASC 718), disregarding forfeitures. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13 for a discussion of the assumptions used to determine the FASB ASC 718 value of the awards.

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(3) All Other Compensation for Fiscal Year 2019 consisted of the following:

Name	401(k) Matching Contributions ($)	Group Term Life Insurance ($)	Other ($)	Total ($)
Robert G. Phillips	16,800	9,017	26,321 (1)	52,138
Robert T. Halpin	16,800	4,905	—	21,705
William H. Moore	16,800	3,579	—	20,379
Steven M. Dougherty	16,800	4,854	—	21,654
Joel C. Lambert	16,800	6,039	—	22,839
J. Heath Deneke	16,800	2,308	1,078,620 (2)	1,097,728

(1) Represents the incremental cost to the Company of the personal use of the Company aircraft.

(2) Represents severance payments made to Mr. Deneke pursuant to the Separation Agreement.

Grants of Plan-Based Awards Table for Fiscal 2019

The following table provides information concerning each grant of an award made to our NEOs during fiscal 2019.

		Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1)			Estimated Future Payout Under Equity Incentive Plan Awards(2)
Name	Grant Date	Threshold ($)	Target ($)	Maximum ($)	Threshold (#)	Target (#)	Maximum (#)	All Other Unit Awards (#)(3)	Grant Date Fair Value of Unit and Option Awards ($)(4)
Robert G. Phillips	01/10/19							111,071	3,476,522
	02/12/19				53,744	107,488	214,976		3,677,599
		310,000	775,000	1,162,500
Robert T. Halpin	01/10/19							45,817	1,434,072
	02/12/19				14,332	28,663	57,326		980,668
		186,000	465,000	697,500
William H. Moore	01/10/19							31,037	971,458
	02/12/19				10,729	21,497	42,994		735,506
		154,000	385,000	577,500
Steven M. Dougherty	01/10/19							34,020	1,064,826
	02/12/19				10,729	21,497	42,994		735,506
		135,040	337,600	506,400
Joel C. Lambert	01/10/19							38,965	1,219,605
	02/12/19				13,436	26,872	53,774		919,393
		139,200	348,000	522,000
J. Heath Deneke(5)	01/10/19							53,207	1,665,379
	02/12/19				16,123	32,246	64,492		1,103,263

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

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

(3) Represents grants of restricted units granted under the Long-Term Incentive Plan. The restricted units vest ratably (33.33%) over a three year period beginning on the first anniversary of the grant date.

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(4) Unit award amounts reflect the aggregate grant date fair value of unit awards granted during 2019 calculated in accordance with ASC 718, disregarding forfeitures. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13 for a discussion of the assumptions used to determine the value of the awards.

(5) The vesting date of Mr. Deneke’s outstanding restricted units and his 2019 performance phantom units was accelerated to April 15, 2019 pursuant to the terms of the Separation Agreement.

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

Employment Agreements

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

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

On February 22, 2018, Crestwood Operations entered into an Omnibus Amendment to each Executive Employment Agreement (“Omnibus Amendment”). Pursuant to the Omnibus Amendment, if the employment of Messrs. Halpin, Moore, Dougherty or Lambert is terminated during the period beginning three months prior to a Change in Control and ending twelve months after a Change in Control, then the severance amount payable shall be increased to three (3) times base salary and average annual bonus for the prior two years.

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

Outstanding Equity Awards at 2019 Fiscal Year-End

The following table summarizes the outstanding equity awards as of the end of Fiscal 2019 for the each of our NEOs. The table includes restricted units and phantom performance units granted under the Crestwood Equity Partners LP Long Term Incentive Plan.

	UNIT AWARDS
Name	Number of Units That Have Not Vested (#)(1)(2)	Market Value of Units That Have Not Vested ($)(3)
Robert G. Phillips	466,376	17,008,182
Robert T. Halpin	225,032	7,746,086
William H. Moore	160,419	5,552,072
Steven M. Dougherty	160,031	5,540,115
Joel C. Lambert	170,351	5,858,178
J. Heath Deneke	33,268 (4)	1,024,320

(1) Mr. Phillips' restricted units vest as follows: 25,636 units vest on January 5, 2020, 29,070 units vest on January 8, 2020, 37,023 units vest on January 10, 2020, 104,070 units vest on January 8, 2021, 37,024 units vest on January 8, 2021 and 37,024 units vest on January 8, 2021. Mr. Phillips' phantom performance units vests as follows: 89,041 units vest on February 15, 2020 and 107,488 units vest on February 12, 2022. Mr. Halpin's restricted units vest as follows: 16,178 units vest on January 5, 2020, 15,988 units vest on January 8, 2020, 15,272 units vest on January 10, 2020, 90,989 units vest on January 8, 2021, 15,272 units vest on January 10, 2021 and 15,273 units vest on January 10, 2022. Mr. Halpin's phantom performance units vests as

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follows: 27,397 units vest on February 15, 2020 and 28,663 units vest on February 12, 2022. Mr. Moore's restricted units vest as follows: 9,785 units vest on January 5, 2020, 13,776 units vest on January 8, 2020, 10,345 units vest on January 10, 2021, 63,776 units vest on January 8, 2021, 10,346 units vest on January 10, 2021 and 10,346 units vest on January 10, 2022. Mr. Moore's phantom performance units vests as follows: 20,548 units vest on February 15, 2020 and 21,497 units vest on February 12, 2022. Mr. Dougherty's restricted units vest as follows: 10,128 units vest on January 5, 2020, 11,919 units vest on January 8, 2020, 11,340 units vest on January 10, 2020, 61,919 units vest on January 8, 2021, 11,340 units vest on January 10, 2021 and 11,340 units vest on January 10, 2022. Mr. Dougherty's phantom units vests as follows: 20,548 units vest on February 15, 2020 and 21,497 units vest on February 12, 2022. Mr. Lambert's restricted units vest as follows: 10,128 units vest on January 5, 2020, 11,919 units vest on January 8, 2020, 12,988 units vest on January 10, 2020, 61,919 units vest on January 8, 2021, 12,988 units vest on January 10, 2021 and 12,989 units vest on January 10, 2022. Mr. Lambert's phantom performance units vests as follows: 20,548 units vest on February 15, 2020 and 26,872 units vest on February 12, 2022. The above vesting schedule does not include the unitized accrued distributions on the performance phantom unit grants.

(2) Does not includes unitization of the accrued distributions on the performance phantom unit grants and does not include the potential increase/decrease in the number of performance phantom units that ultimately vest based on satisfaction of the performance factors summarized in the Compensation Discussion & Analysis.

(3) Market value for CEQP units based on the NYSE closing price of $30.82 on December 31, 2019.

(4) Represents Mr. Deneke’ss 2017 performance phantom unit grant that was not subject to accelerated vesting upon his termination of employment.

Units Vested During Fiscal 2019

The following table provides information regarding restricted units vesting during Fiscal 2019 for each of the NEOs. Value realized on vesting was calculated by using the NYSE closing price of Crestwood Equity Partners LP on the day immediately prior to the date that the award vested.

	UNIT AWARDS
Name	Number of Units Acquired On Vesting (#)	Value Realized on Vesting ($)
Robert G. Phillips	92,589	2,775,617
Robert T. Halpin	52,182	1,567,675
William H. Moore	38,658	1,175,547
Steven M. Dougherty	34,697	1,039,496
Joel C. Lambert	34,697	1,039,496
J. Heath Deneke	281,160 (1)	9,985,499

(1) The vesting date of Mr. Deneke’s outstanding restricted units and his 2019 performance unit grant was accelerated to April 15, 2019 pursuant to the terms of the Separation Agreement.

Pension Benefits during Fiscal 2019

We do not offer any pension benefits.

Non-qualified Deferred Compensation during Fiscal 2019

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

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

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

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Potential Payments upon a Change in Control or Termination during Fiscal 2019

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

Under the terms of the Executive Employment Agreements (other than Mr. Phillips), if the named executive officer is terminated during the period beginning three months prior to a Change in Control and ending twelve months after a Change in Control, then the severance amount payable shall be increased to three (3) times his base salary and average annual bonus for the prior two years.

The following table presents information about the gross payments potentially payable to our named executive officers pursuant to the Executive Employment Agreements, assuming each such named executive officer experienced a qualifying termination of employment on December 31, 2019.

Name	Cash Severance ($)(1)	Accelerated Vesting of Restricted Units ($)(2)	Benefit Continuation ($)(3)	Total ($)
Robert G. Phillips	5,715,000	17,008,182	24,198	22,747,380
Robert T. Halpin	2,326,000	7,746,086	28,003	10,100,089
William H. Moore	1,906,500	5,552,072	28,009	7,486,581
Steven M. Dougherty	1,834,640	5,540,115	28,009	7,402,764
Joel C. Lambert	1,867,000	5,858,178	28,009	7,753,187

(1) As described above, amounts reflect cash severance payments payable upon a qualifying termination without “employer cause” or the named executive officer resigns due to “employee cause” that the named executive officer will be entitled to receive pursuant to his Employment Agreements, subject to the executive’s execution of a release of claims. The severance payments are equal to two (or, in the case of Mr. Phillips, three) times the sum of the named executive officer’s base salary and average annual bonus for the prior two years. The cash severance payable to each of Messrs. Halpin, Moore, Dougherty and Lambert would increase to $3,489,000, $2,859,750, $2,751,960, and $2,800,500, respectively, in the event his qualifying termination was in connection with a Change in Control.

(2) The amounts reflected in the table above include the value of restricted units and performance phantom units which would be subject to accelerated vesting upon a change of control or termination without “employer cause” or the named executive officer resigns due to “employee cause.” The value reflected for the restricted units is based on the NYSE closing price of $30.82 for CEQP units on December 31, 2019. This value does not reflect the unitization of the accrued distributions on the performance phantom unit grants.

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

Director Compensation Table for Fiscal 2019

The following table sets forth the cash and non-cash compensation for Fiscal 2019 by each person who served as a non-employee director of our general partner during such time.

Name	Fees Earned or Paid in Cash ($)	Unit Awards ($)(1)	Non-Qualified Deferred Comp Earnings ($)	Total ($)
Alvin Bledsoe	120,000	103,985	2,815 (2)	226,800
William Brown	—	94,735	—	94,735
Warren Gfeller	130,000	103,985	—	233,985
Janeen Judah	120,000	103,985	—	223,985
David Lumpkins	120,000	103,985	—	223,985
Gary Reaves	—	110,683	—	110,683
John Sherman	100,000	103,985	—	203,985
John Somerhalder II(3)	120,000	103,985	23,591 (2)	247,576

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(1) Reflects the value of restricted unit awards, calculated in accordance with ASC 718, disregarding estimated forfeitures. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13 for a discussion of the assumptions used to determine the FASB ASC Topic 718 value of the awards. These restricted unit grants will vest on the first anniversary of the grant date and as of December 31, 2019, our non-employee directors held the following restricted unit awards: Mr. France, Mr. Gfeller, Ms. Judah, Mr. Lumpkins and Mr. Sherman each held 3,582 restricted units. Mr. Reaves was appointed to the CEQP board of directors on January 22, 2019 and received 3,582 restricted units and Mr. Brown was appointed to the CEQP board of directors on May 3, 2019 and received 2,686 restricted units. Mr. Bledsoe and Mr. Somerhalder deferred their unit awards pursuant to the Non-Qualified Deferred Compensation Plan.

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

(3) Mr. Somerhalder II resigned from the board of directors effective February 20, 2020.

Compensation of Directors during Fiscal 2019

Officers of our general partner who also serve as directors do not receive additional compensation. Each director receives cash compensation of $100,000 per year for serving on our board of directors. The lead director, audit committee chairperson, conflicts committee chairperson and finance committee chairperson each receive additional cash compensation of $20,000 per year and the compensation committee chairperson receives additional cash compensation of $10,000 per year. All cash compensation is paid to the non-employee directors in quarterly installments. Additionally, each non-employee director receives an annual grant of restricted units under our long-term incentive plan equal to approximately $100,000 in value that vests on the first anniversary of the date of issuance. Each non-employee director is reimbursed for out-of-pocket expenses in connection with attending meetings of the board of directors or committees.

In December 2019, our board of directors approved an increase in the annual grant of restricted units to our directors to approximately $110,000 in value and increased the fee paid to the compensation committee chair to $20,000 per year. These changes became effective on January 1, 2020.

CEO Pay Ratio

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

We identified the median employee by examining the 2019 total taxable cash and equity compensation (again, to the extent taxed to the employee in 2019), as reflected in our payroll records as reported to the Internal Revenue Service on Form W-2, for all individuals, including our CEO, who were employed on December 31, 2019. We included all employees, whether employed on a full-time, part-time, temporary or seasonal basis. As of December 31, 2019, we employed 899 such persons.  We annualized the compensation for any employees that were not employed for all of 2019 (not including seasonal or temporary employees), but did not make any other assumptions, adjustments, or estimates with respect to total cash compensation or equity. Since all of our employees, including our CEO, are located in the United States, we did not make any cost of living adjustments in identifying the median employee. We believe the use of total cash and equity compensation for all employees is the most appropriate compensation measure since it includes the main elements of compensation for the majority of our employees. 

After identifying the median employee based on total cash and equity compensation, we calculated annual 2019 compensation for the median employee using the same methodology used to calculate the Chief Executive Officer’s total compensation as reflected in the Summary Compensation Table above.  The median employee’s annual 2019 compensation was as follows:

Name	Year	Salary	Bonus	Stock Awards	Non-Equity Incentive Plan Compensation	All Other Compensation	Total
Median Employee	2019	$90,737	$—	$—	$—	$—	$90,737

With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2019 Summary Compensation Table included in this Annual Report, which was $9,065,297. Our 2019 ratio of Chief Executive Officer total compensation to our median employee’s total compensation is reasonably estimated to be 99:1.

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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 17, 2020, 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 Owned
Crestwood Gas Services Holdings LLC(2)(3)(4)	9,985,462		13.6%
Crestwood Holdings LLC(2)(3)	7,484,449		10.2%
ALPS Advisors, Inc.(5)	5,915,659		8.1%
Goldman Sachs Asset Management(6)	4,075,975		5.6%
Alvin Bledsoe(7)	40,768		*
William Brown	6,255		*
Steven M. Dougherty	253,430		*
Warren H. Gfeller	51,983		*
Robert T. Halpin	362,320		*
Janeen S. Judah	7,898		*
Joel C. Lambert	200,099		*
David Lumpkins	41,590		*
William H. Moore	234,662		*
Robert G. Phillips	650,380		*
Gary D. Reaves	7,151		*
John J. Sherman	3,231,482		4.4%
Directors and executive officers as a group (12 persons)	5,088,018	(8)	6.9%

* Indicates less than 1%

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

(2) Crestwood Holdings LLC has shared voting power and shared investment power with Crestwood Gas Services Holdings LLC on 9,985,462 common units. Crestwood Holdings LLC, FR Crestwood Management Co-Investment LLC, Crestwood Holdings Partners LLC, FR XI CMP Holdings LLC, FR Midstream Holdings LLC, First Reserve GP XI, L.P., First Reserve GP XI, Inc., and William E. Macaulay have control over 17,469,911 common units.

(3) Common units owned by Crestwood Gas Services Holdings LLC and Crestwood Holdings LLC are pledged as collateral under the Crestwood Holdings term loan.

(4) Does not include 438,789 subordinated units. The subordinated units may be converted to common units on a one-for-one basis upon the termination of the subordination period as set forth in the Crestwood Equity Partners LP Partnership Agreement.

(5) Based on Schedule 13G filed by ALPS Advisors, Inc. on February 7, 2020. The address of ALPS Advisors, Inc. is 1290 Broadway, Suite 1000, Denver, CO 80203.

(6) Based on Schedule 13G filed by Goldman Sachs Asset Management on February 4, 2020. The address of Goldman Sachs Asset Management is 200 West Street, New York, NY 10282.

(7) Includes 14,157 restricted units held in the Crestwood Nonqualified Deferred Compensation Plan.

(8) Excludes 305,295 performance phantom units granted to our executive officers pursuant to the Crestwood Equity Long-Term Incentive Plan.

See Part II, Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities of this report for certain information regarding securities authorized for issuance under our equity compensation plans.

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Item 13. Certain Relationships, Related Transactions and Director Independence

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

Transactions with Related Persons

First Reserve Joint Venture

In October 2016, Crestwood Infrastructure Holdings LLC, our wholly-owned subsidiary, and an affiliate of First Reserve formed a joint venture, Crestwood Permian Basin Holdings LLC (Crestwood Permian), to fund and own the Nautilus gathering system and other potential investments in the Delaware Permian. On June 21, 2017, the Company contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico Pipeline LLC (Crestwood New Mexico), its wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New Mexico. These assets consisted of two dry gas gathering systems (Las Animas systems) and one rich gas gathering system and processing plant (Willow Lake system). In conjunction with this contribution, First Reserve contributed to Crestwood Permian the first $151 million of capital cost required to fund the expansion of the Delaware Basin assets, including a new processing plant located in Orla, Texas and associated pipelines (Orla processing plant), which went into service in July 2018. We received 100% of the available cash flow generated by Crestwood New Mexico through June 30, 2018. Beginning with the third quarter of 2018, both parties will receive distributions on a 50/50 basis.

Review, Approval or Ratification of Transactions with Related Persons

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

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

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

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

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

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

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

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

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

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

• any applicable generally accepted accounting practices or principles; and

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• such additional factors as the general partner or conflicts committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

A related party transaction that is approved by the conflicts committee is, as discussed in greater detail above, conclusively deemed to be fair and reasonable to us. Under our partnership agreement, the material facts known to our general partner or any of our affiliates regarding the transaction must be disclosed to the conflicts committee at the time the committee gives its approval. When approving a related party transaction, the conflicts committee considers all factors it considers relevant, reasonable or appropriate under the circumstances, including the relative interests of any party to the transaction, customary industry practices and generally accepted accounting principles.

Under our partnership agreement, in the absence of bad faith by the general partner, the resolution, action or terms so made, taken or provided by the general partner with respect to approval of the related party transaction will not constitute a breach of our partnership agreement or any standard of fiduciary duty.

Under our related person transactions policy, as well as under our partnership agreement, there is no obligation to take any particular conflict to the conflicts committee-empaneling that committee is entirely at the discretion of the general partner. In many ways, the decision to engage the conflicts committee can be analogized to the kinds of transactions for which a Delaware corporation might establish a special committee of independent directors. The general partner considers the specific facts and circumstances involved. Relevant facts would include:

• the nature and size of the transaction (i.e., transaction with a controlling unitholder, magnitude of consideration to be paid or received, impact of proposed transaction on the general partner and holders of common units);

• the related person’s interest in the transaction;

• whether the transaction is on terms no less favorable than terms generally available to an unaffiliated third-party under the same or similar circumstances;

• if applicable, the availability of other sources of comparable services or products; and

• the financial costs involved, including costs for separate financial, legal and possibly other advisors at our expense.

When determining whether a related party transaction is in the normal course of our business and is (a) on terms no less favorable to us than those generally being provided to or available from unrelated third parties or (b) fair to us, taking into account the totality of the relationships between the parties involved (including other transactions that may be particularly favorable or advantageous to us), the general partner considers any facts and circumstances that it deems to be relevant, including:

• the terms of the transaction, including the aggregate value;

• the business purpose of the transaction;

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

• whether the terms of the transaction are comparable to the terms that would exist in a similar transaction with an unaffiliated third party;

• any customary or accepted industry practices;

• any applicable generally accepted accounting practices or principles; and

• such additional factors as the general partner or the conflicts committee determines in its sole discretion to be relevant, reasonable or appropriate under the circumstances.

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Item 14. Principal Accountant Fees and Services

The Audit Committee of the Board of Directors of Crestwood Equity GP LLC approved the engagement of Ernst & Young LLP as the principal accountant to audit the partnership’s financial statements as of and for the fiscal year ending December 31, 2019. The following table summarizes the fees for professional services rendered by Ernst & Young LLP for the years ended December 31, 2019 and 2018 (in millions).

	2019		2018
Audit-related fees(1)	$	1.9	$	1.8
All other fees(2)	0.1		0.2
Total	$	2.0	$	2.0

(1) Includes fees related to the performance of the annual audit and quarterly reviews (including internal control evaluation and reporting) of the consolidated financial statements of Crestwood Equity and Crestwood Midstream and its subsidiaries.

(2) Includes fees primarily associated with acquisitions, dispositions and issuances of debt and equity.

The audit committee of Crestwood Equity’s general partner reviewed and approved all audit and non-audit services provided during 2019. Crestwood Midstream is a wholly-owned subsidiary of Crestwood Equity and, as such, it does not have a separate audit committee. Crestwood Equity’s audit committee has adopted a pre-approval policy for audit and non-audit services. For information regarding the audit committee’s pre-approval policies and procedures, see Crestwood Equity’s audit committee charter on its website at www.crestwoodlp.com.

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PART IV

Item 15. Exhibits, Financial Statement Schedules

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

1. Financial Statements:

See Index Page for Financial Statements

2. Financial Statement Schedules:

Schedule I: Parent Only Condensed Financial Statements

Schedule II: Valuation and Qualifying Accounts

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

3. Exhibits:

Exhibit Number	Description
2.1	Agreement and Plan of Merger, dated as of May 5, 2015, by and among Crestwood Equity Partners LP, Crestwood Equity GP LLC, CEQP ST SUB LLC, MGP GP, LLC, Crestwood Midstream Holdings LP, Crestwood Midstream Partners LP, Crestwood Midstream GP LLC and Crestwood Gas Services GP LLC (incorporated by reference to Exhibit 2.1 to Crestwood Equity Partners LP’s Form 8-K filed May 6, 2015)
2.2	Contribution Agreement, dated as of April 20, 2016, by and between Crestwood Pipeline and Storage Northeast LLC and Con Edison Gas Pipeline and Storage Northeast, LLC (incorporated herein by reference to Exhibit 2.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 22, 2016)
2.3	Purchase Agreement dated as of April 9, 2019 by and between Crestwood Niobrara LLC and Williams MLP Operating LLC (incorporated by reference to Exhibit 2.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 10, 2019)
3.1	Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-56976) filed on March 14, 2001)
3.2	Certificate of Correction of Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q filed on May 12, 2003)
3.3	Amendment to the Certificate of Limited Partnership of Crestwood Equity Partners LP (f/k/a Inergy, L.P.) (the “Partnership”) dated as of October 7, 2013 (incorporated herein by reference to Exhibit 3.2 to Crestwood Equity Partners LP’s Form 8-K filed on October 10, 2013)
3.4	Fifth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners LP dated April 11, 2014 (incorporated herein by reference to Exhibit 3.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 11, 2014)
3.5	First Amendment to the Fifth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners LP, dated as of September 30, 2015 (incorporated herein by reference to Exhibit 3.1 to the Crestwood Equity Partners LP’s Form 8-K filed on October 1, 2015)
3.6	Second Amendment to the Fifth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners LP, dated as of November 8, 2017 (incorporated herein by reference to Exhibit 3.1 to Crestwood Equity Partners LP’s Form 8-K filed on November 13, 2017)
3.7	Certificate of Formation of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.5 to Inergy, L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
3.8	Certificate of Amendment of Crestwood Equity GP LLC (f/k/a Inergy GP, LLC) dated October 7, 2013 (incorporated herein by reference to Exhibit 3.3A to Crestwood Equity Partners LP’s Form 10-Q filed on November 8, 2013)

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Exhibit Number	Description
3.9	First Amended and Restated Limited Liability Company Agreement of Inergy GP, LLC dated as of September 27, 2012 (incorporated by reference to Exhibit 3.1 to Inergy, L.P.’s Form 8-K filed on September 27, 2012)
3.10	Amendment No. 1 to the First Amended and Restated Limited Liability Company Agreement of Crestwood Equity GP LLC (f/k/a Inergy GP, LLC) entered into effective October 7, 2013 (incorporated herein by reference to Exhibit 3.4A to Crestwood Equity Partners LP’s Form 10-Q filed on November 8, 2013)
3.11	Certificate of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.4 to Inergy Midstream, L.P.’s Form S-1/A filed on November 21, 2011)
3.12	Amendment to the Certificate of Limited Partnership of Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.2 to Inergy Midstream, L.P.’s Form 8-K filed on October 10, 2013)
3.13	First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P., dated December 21, 2011 (incorporated herein by reference to Exhibit 4.2 to Inergy Midstream, L.P.’s Form S-8 filed on December 21, 2011)
3.14	Amendment No. 1 to the First Amended and Restated Agreement of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to Exhibit 3.1 to Inergy Midstream, L.P.’s Form 8-K filed on October 1, 2013)
3.15	Amendment No. 2 to the First Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP (f/k/a Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.1 to Crestwood Midstream Partners LP’s Form 8-K filed on October 10, 2013)
3.16	Amendment No. 3 to the First Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP dated as of June 17, 2014 (incorporated herein by reference to Exhibit 3.1 to Crestwood Midstream Partners LP’s Form 8-K filed on June 19, 2014)
3.17	Second Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners LP, dated as of September 30, 2015 (incorporated by reference to Exhibit 3.1 to Crestwood Midstream Partners LP’s Form 8-K filed on October 1, 2015)
3.18	Certificate of Formation of NRGM GP, LLC (incorporated herein by reference to Exhibit 3.7 to Inergy Midstream, L.P.’s Form S-1/A filed on November 21, 2011)
3.19	Certificate of Amendment of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.37 to Crestwood Midstream Partners LP’s Form S-4/A filed on October 28, 2013)
3.20	Amended and Restated Limited Liability Company Agreement of NRGM GP, LLC, dated December 21, 2011 (incorporated herein by reference to Exhibit 3.2 to Inergy Midstream, L.P.’s Form 8-K filed on December 22, 2011)
3.21	Amendment No. 1 to the Amended and Restated Limited Liability Company Agreement of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.39 to Crestwood Midstream Partners LP’s Form S-4/A filed on October 28, 2013)
3.22	Third Amendment to the Fifth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners LP entered into and effective as of May 30, 2018 (incorporated by reference to Exhibit 3.1 to Crestwood Equity Partners LP’s Form 8-K filed on June 4, 2018)
3.23	Fourth Amendment to the Fifth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners LP, dated as of June 28, 2019 (incorporated by reference to Exhibit 3.1 to Crestwood Equity Partners LP’s Form 8-K filed on June 28, 2019)
4.1	Specimen Unit Certificate for Common Units (incorporated herein by reference to Exhibit 4.3 to Inergy L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
4.2	Indenture, dated as of March 14, 2017, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on March 15, 2017)

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Exhibit Number	Description
4.3	Supplemental Indenture dated as of June 5, 2017, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, each existing Guarantor and U.S. Bank National Association, as trustee (incorporated by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 10-Q filed on August 4, 2017)
4.4	Supplemental Indenture dated as of December 1, 2017, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, each existing Guarantor and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.4 to Crestwood Equity Partners LP’s Form 10-K filed on February 26, 2018)
4.5	Indenture, dated as of March 23, 2015, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 8-K filed on March 27, 2015)
4.6	First Supplemental Indenture, dated March 4, 2016, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the Guarantors named therein and U.S. Bank National Association (incorporated herein by reference to Exhibit 4.3 to Crestwood Midstream Partners LP’s Form 8-K filed on March 7, 2016)
4.7	Supplemental Indenture, dated as of June 3, 2016, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 10-Q filed on August 4, 2016)
4.8	Supplemental Indenture, dated as of September 30, 2016, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form 10-Q filed on November 4, 2016)
4.9	Indenture, dated as of April 15, 2019, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 16, 2019
4.10	Third Amended and Restated Limited Liability Company Agreement for Crestwood Niobrara LLC, dated between Crestwood Midstream Partners LP and CN Jackalope Holdings, LLC (incorporated herein by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 10-Q filed on May 2, 2019)
4.11	Registration Rights Agreement, dated December 28, 2017, by and among Crestwood Equity Partners LP and CN Jackalope Holdings, LLC (incorporated herein by reference to Exhibit 4.10 to Crestwood Equity Partners LP’s Form 10-K filed on February 26, 2018)
4.12	First Amendment to Registration Rights Agreement dated as of April 9, 2019 by and between Crestwood Equity Partners LP and CN Jackalope Holdings, LLC (incorporated herein by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 10, 2019)
4.13	Registration Rights Agreement, dated March 14, 2017, by and among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corp., the guarantors named therein and J.P. Morgan Securities LLC, as representative of the several initial purchasers, with respect to the 5.72% Senior Notes due 2025 (incorporated by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on March 15, 2017.
4.14	Registration Rights Agreement, dated as of September 30, 2015, by and among Crestwood Equity Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on October 1, 2015)
4.15	Supplemental Indenture dated as of October 22, 2018, among Crestwood Midstream Partners LP, Crestwood Midstream Finance Corporation, each existing Guarantor and U.S. Bank National Association, as trustee (incorporated herein by reference to Exhibit 4.13 to Crestwood Equity Partners LP’s Form 10-K filed on February 22, 2019)
**4.16	Description of Securities
*10.1	Second Amended and Restated Employment Agreement, dated July 21, 2017, between Heath Deneke and Crestwood Operations LLC (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on July 25, 2017)

97

Exhibit Number	Description
*10.2	Omnibus Amendment to Employment Agreements dated February 22, 2018 by and between Crestwood Operations LLC and each of Robert G. Phillips, Robert Halpin, Steven Dougherty, Joel Lambert and William H. Moore (incorporated herein by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 10-K filed on February 26, 2018)
*10.3	Employment Agreement between Robert G. Phillips and Crestwood Operations LLC dated as of January 21, 2014 (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on January 27, 2014)
*10.4	Employment Agreement between Joel Lambert and Crestwood Operations LLC dated as of January 21, 2014 (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s Form 10-K filed on February 28, 2014)
*10.5	Employment Agreement between William H. Moore and Crestwood Operations LLC dated as of January 21, 2014 (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s Form 10-K filed on March 2, 2015)
*10.6	Employment Agreement between Steven M. Dougherty and Crestwood Operations LLC dated as of January 21, 2014 (incorporated herein by reference to Exhibit 10.4 to Crestwood Equity Partners LP’s Form 10-K filed on February 29, 2016)
*10.7	Amended and Restated Employee Agreement between Robert T. Halpin and Crestwood Operations LLC dated as of April 1, 2015 (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s Form 10-K filed on February 29, 2016)
*10.8	Crestwood Equity Partners LP Long Term Incentive Plan (incorporated herein by reference to Exhibit 10.7 to Crestwood Equity Partners LP’s Form 10-K filed on February 28, 2014)
*10.9	Form of Crestwood Equity Partners LP’s Restricted Unit Award Agreement (incorporated herein by reference to Exhibit 4.12 to Crestwood Equity Partner LP’s Form S-8 filed on January 16, 2015)
*10.10	Form of Crestwood Equity Partners LP’s Phantom Unit Award Agreement (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on January 23, 2015)
*10.11	Form of Crestwood Equity Partners LP’s Performance Unit Grant Agreement (incorporated by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 10-Q filed on May 4, 2017)
*10.12	Crestwood Equity Partners Non-Qualified Deferred Compensation Plan (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on November 15, 2016)
10.13	Amended and Restated Credit Agreement, dated as of September 30, 2015, by and among Crestwood Midstream Partners LP, as borrower, the lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on October 1, 2015)
10.14	Amendment dated as of April 20, 2016, among Crestwood Midstream Partners LP, as borrower, certain guarantors and financial institutions party thereto, and Wells Fargo Bank, National Association, as administrative agent and collateral agent. (incorporated herein by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 8-K filed on April 22, 2016)
10.15	Guaranty, dated as of April 20, 2016, made by Crestwood Equity Partners LP in favor of Con Edison Gas Pipeline and Storage Northeast, LLC (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 22, 2016)
10.16	Amended and Restated Limited Liability Company Agreement of Stagecoach Gas Services LLC dated as of June 3, 2016. (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on June 8, 2016)
10.17	Gas Gathering Agreement, dated as of April 6, 2016, among Cowtown Pipeline Partners L.P., as Gatherer, and BlueStone Natural Resources II, LLC, as Producer (incorporated herein by reference to Exhibit 10.3 to Crestwood Equity Partners LP’s Form 10-Q filed on August 4, 2016)
10.18	Gas Gathering and Processing Agreement, dated as of April 6, 2016, among BlueStone Natural Resources II, LLC, as Producer, Cowtown Pipeline Partners L.P., as Gatherer, and Cowtown Gas Processing Partners LP, as Processor (incorporated herein by reference to Exhibit 10.4 to Crestwood Equity Partners LP’s Form 10-Q filed on August 4, 2016)
10.19	Gas Gathering Agreement, dated as of April 6, 2016, among BlueStone Natural Resources II, LLC, as Producer, and Cowtown Pipeline Partners L.P., as Gatherer (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s Form 10-Q filed on August 4, 2016)

98

Exhibit Number	Description
10.20	Letter Agreement to Gathering and Processing Agreements, dated as of April 6, 2016, among Cowtown Pipeline Partners L.P., Cowtown Gas Processing Partners L.P. and BlueStone Natural Resources II, LLC(incorporated herein by reference to Exhibit 10.6 to Crestwood Equity Partners LP’s Form 10-Q filed on August 4, 2016)
10.21	Guarantee, dated as of February 24, 2012, by Crestwood Holdings LLC and Crestwood Midstream Partners LP, in favor of Antero Resources Appalachian Corporation (incorporated herein by reference to Exhibit 10.1 to Crestwood Midstream Partners LP’s Form 8-K filed on February 28, 2012)
10.22	Gas Gathering and Compression Agreement, dated as of January 1, 2012, by and between Antero Resources Appalachian Corporation and Crestwood Marcellus Midstream LLC (incorporated herein by reference to Exhibit 10.23 to Crestwood Midstream Partners LP’s Form 10-K filed on February 28, 2013)
10.23	Registration Rights Agreement, dated as of September 30, 2015, by and among Crestwood Equity Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on October 1, 2015)
10.24	Board Representation and Standstill Agreement, dated as of September 30, 2015, by and among Crestwood Equity GP LLC, Crestwood Equity Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 8-K filed on October 1, 2015)
10.25	Support Agreement, dated as of May 5, 2015, by and among Crestwood Equity Partners LP, Crestwood Midstream Partners LP and CGS GP (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on May 6, 2015)
10.26	Equity Distribution Agreement, dated August 4, 2017, by and among Crestwood Equity Partners LP and the Managers named therein (incorporated by reference to Exhibit 1.1 to Crestwood Equity Partners LP’s Form 8-K filed on August 4, 2017)
*10.27	Crestwood Equity Partners LP 2018 Long Term Incentive Plan (incorporated by reference to Exhibit 10.1 to the Registrant’s Current Report on Form 8-K, filed with the Commission on May 16, 2018)
*10.28	Crestwood Equity Partners LP Employee Unit Purchase Plan. (incorporated by reference to Exhibit 10.1 to the Registrant’s Form 8-K, filed with the Commission on August 24, 2018)
*10.29	Form of Crestwood Equity Partners LP’s Executive Restricted Unit Award Grant Notice (incorporated by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 10-Q filed November 1, 2018)
*10.30	Form of Crestwood Equity Partners LP’s Non-Executive Restricted Unit Award Grant Notice (incorporated by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 10-Q filed on November 1, 2018)
*10.31	Form of Crestwood Equity Partners LP’s Director Restricted Unit Award Grant Notice (incorporated by reference to Exhibit 10.3 to Crestwood Equity Partners LP’s Form 10-Q filed on November 1, 2018)
*10.32	Form of Crestwood Equity Partners LP’s Restricted Unit Award Agreement (incorporated by reference to Exhibit 10.4 to Crestwood Equity Partners LP’s Form 10-Q filed on November 1, 2018)
10.33	Second Amended and Restated Credit Agreement, dated as of October 18, 2018, and among Crestwood Midstream Partners LP, as borrower, the lenders party thereto, and Wells Fargo Bank National Association, as Administrative Agent and Collateral Agent. (incorporated by reference to Exhibit 10-1 to Crestwood Equity Partners LP’s Form 8-K filed on October 18, 2018)
10.34	First Amendment to Second Amended and Restated Credit Agreement, dated as of April 9, 2019 by, and among Crestwood Midstream Partners LP, as borrower, the lenders party thereto, and Wells Fargo Bank National Association, as Administrative Agent and Collateral Agent (incorporated by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 10, 2019)
*10.35	Separation Agreement and Release dated March 25, 2019 between Crestwood Operations LLC and Heath Deneke (incorporated by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 10-Q filed on May 2, 2019)
16.1	Letter Regarding Change in Certifying Accountant (incorporated herein by reference to Exhibit 16.1 to Inergy, L.P.’s Form 8-K/A filed on July 23, 2013)
**21.1	List of subsidiaries of Crestwood Equity Partners LP

99

Exhibit Number	Description
**23.1	Consent of Ernst & Young LLP - Crestwood Equity Partners LP
**23.2	Consent of Ernst & Young LLP - Stagecoach Gas Services LLC
**31.1	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended - Crestwood Equity Partners LP
**31.2	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended - Crestwood Equity Partners LP
**31.3	Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended - Crestwood Midstream Partners LP
**31.4	Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the Securities Exchange Act, as amended - Crestwood Midstream Partners LP
**32.1	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Equity Partners LP
**32.2	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Equity Partners LP
**32.3	Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Midstream Partners LP
**32.4	Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Midstream Partners LP
**99.1	Financial Statements for Stagecoach Gas Services LLC as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017 (audited) pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09)
**101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document
**101.SCH	Inline XBRL Taxonomy Extension Schema Document
**101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document
**101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document
**101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document
**101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document
104	Cover Page Interactive Data File (contained in Exhibit 101)

*	Management contracts or compensatory plans or arrangements
**	Filed herewith

(b) Exhibits.

See exhibits identified above under Item 15(a)3.

(c) Financial Statement Schedules.

Financial Statements for Stagecoach Gas Services LLC as of December 31, 2019 and 2018 and for the years ended December 31, 2019, 2018 and 2017 (audited) pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09) and is filed herein as Exhibit 99.1.

100

Crestwood Equity Partners LP

Crestwood Midstream Partners LP

Index to Financial Statements

Crestwood Equity Partners LP
Report of Independent Registered Public Accounting Firm	102
Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial Reporting	107
Audited Consolidated Financial Statements:
Consolidated Balance Sheets	108
Consolidated Statements of Operations	109
Consolidated Statements of Comprehensive Income	111
Consolidated Statements of Partners’ Capital	112
Consolidated Statements of Cash Flows	113
Notes to Consolidated Financial Statements	121
Crestwood Midstream Partners LP
Report of Independent Registered Public Accounting Firm	115
Audited Consolidated Financial Statements:
Consolidated Balance Sheets	116
Consolidated Statements of Operations	117
Consolidated Statements of Partners’ Capital	118
Consolidated Statements of Cash Flows	119
Notes to Consolidated Financial Statements	121

101

Report of Independent Registered Public Accounting Firm

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

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Crestwood Equity Partners LP (the Partnership) as of December 31, 2019 and 2018, and the related consolidated statements of operations, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and financial statement schedules listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Partnership's internal control over financial reporting as of December 31, 2019, 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 21, 2020 expressed an unqualified opinion thereon.

Adoption of ASU No. 2014-09

As discussed in Note 2 to the consolidated financial statements, the Company changed its method of accounting for revenue recognition in 2018 due to the adoption of Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606).”

Basis for Opinion

These financial statements are the responsibility of the Partnership's management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

	Valuation of goodwill
Description of the Matter	The Partnership’s goodwill is attributable to past acquisitions and is assigned to reporting units as of the acquisition date. As discussed in Note 2 to the consolidated financial statements, goodwill is tested for impairment at least annually at the reporting unit level. At December 31, 2019, the Partnership’s goodwill in its Powder River Basin (“PRB”) reporting unit was $80.3 million. Auditing management’s annual goodwill impairment test for the PRB reporting unit was complex and highly judgmental due to the significant estimation required in determining the fair value of the reporting unit and the sensitivity of the fair value compared to the carrying amount for this reporting unit. The fair value estimate was sensitive to significant assumptions, such as the weighted average cost of capital, revenue growth rate, operating margin, and terminal value, which are affected by expectations about future market or economic conditions.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership’s goodwill impairment review process, including controls over management’s review of the significant assumptions described above. To test the estimated fair value of the Partnership’s PRB reporting unit, we performed audit procedures that included, among others, assessing methodologies and testing the significant assumptions discussed above and the underlying data used by the Partnership in its analysis. We compared the significant assumptions used by management to current industry and economic trends, changes to the Partnership’s business model, and other relevant factors. We assessed the historical accuracy of management’s estimates and performed sensitivity analyses of significant assumptions to evaluate the changes in the fair value of the PRB reporting unit that would result from changes in the assumptions. We also involved our valuation specialist to assist in our evaluation of the valuation methodologies applied by the Partnership and the significant assumptions used in estimating the fair value of the PRB reporting unit. We also tested management’s reconciliation of the fair value of all the Partnership’s reporting units to the market capitalization of the Partnership.
	Accounting for acquisition of Jackalope Gas Gathering Services

102

Description of the Matter	As described in Note 3 to the consolidated financial statements, during 2019, the Partnership acquired the remaining 50% interest in Jackalope Gas Gathering Services, LLC (“Jackalope”) for $484.6 million. The transaction was accounted for as a business combination. Auditing the Partnership’s accounting for its acquisition of Jackalope was complex due to the significant estimation uncertainty in the Partnership’s determination of the fair value of the customer contract intangible asset of $306 million. The significant estimation uncertainty was primarily due to the sensitivity of the fair value to underlying assumptions about the future performance of the acquired business. The Partnership used a discounted cash flow model to measure the customer contract intangible asset. The significant assumptions used to estimate the fair value of the customer contract intangible asset included the discount rate and certain assumptions that form the basis of the forecasted results (e.g., revenue growth rates and capital expenditures). These significant assumptions are forward looking and could be affected by future economic and market conditions.
How We Addressed the Matter in Our Audit	We obtained an understanding, evaluated the design and tested the operating effectiveness of the Partnership's controls over its accounting for the acquisition. For example, we tested controls over the estimation of the fair value of the customer contract intangible asset, including the valuation models and underlying assumptions used to develop such estimates. To test the estimated fair value of the customer contract intangible asset, we performed audit procedures that included, among others, evaluating the Partnership's use of the income approach (the excess earnings method) and testing the significant assumptions used in the model, including the completeness and accuracy of the underlying data. For example, we compared the significant assumptions to current industry, market and economic trends, to customer contract terms, to the historical results of the acquired business and to other guidelines used by companies within the same industry. We also involved our valuation specialist to assist in our evaluation of the valuation methodology applied by the Partnership and the significant assumptions used in estimating the fair value of the customer contract intangible asset.
	Revenue recognition - Measuring variable consideration

103

Description of the Matter	As described in Note 2 to the consolidated financial statements, the Partnership recognizes revenues for services and products under revenue contracts as obligations to perform services or deliver/sell products under the contracts are satisfied. For a significant customer contract associated with the Partnership’s Powder River Basin gathering and processing assets, consideration to be received under the contact is estimated over the life of the contract and the contract’s transaction price is allocated to each performance obligation in the contract and recognized as revenue when, or as, the performance obligation is satisfied. Auditing the Partnership's measurement of variable consideration under this contract involved especially challenging judgment because the calculation involves subjective management assumptions about estimates of future revenues including forecasted production of its customer over the life of the contract. For example, the future revenues estimate reflects management's assumptions about future economic conditions and expected volumes to be gathered and processed, and changes in those assumptions can have a material effect on the amount of revenue recognized.
How We Addressed the Matter in Our Audit	Our audit procedures included, among others, evaluating the significant assumptions and the accuracy and completeness of the underlying data used in management's calculation. This included testing management's estimated future revenues by obtaining the customer’s forecasted volumes and the recalculation of revenue based on the volumes and executed contract rates. In addition, we performed sensitivity analyses to evaluate the changes in variable consideration that would result from changes in the Partnership's significant assumptions.
	Consolidation - Voting Interest Model

104

Description of the Matter As disclosed in Note 3 to the consolidated financial statements, on April 9, 2019, Crestwood Niobrara LLC (“CWN”) issued $235 million of new Series A-3 preferred units and amended the Limited Liability Company (“LLC”) agreement for the existing Series A-2 preferred units in connection with the acquisition of Jackalope Gas Gathering Services, LLC. The Partnership consolidated CWN pursuant to the voting interest model.
Auditing management’s application of the voting interest model to this transaction, including the process of evaluating CWN for consolidation based on whether the holders of the preferred units have protective versus participating rights, required significant judgment. In particular, we had to make significant judgments to audit management’s determination of (1) whether CWN has sufficient equity at risk to finance its activities without additional subordinated financial support and (2) whether the holders of preferred units in CWN participate in significant financial and operating decisions of CWN that are made in the ordinary course of business.

105

How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership’s application of the voting interest model. For example, we tested controls over management’s process of evaluating whether the entity is a voting interest entity and whether the Partnership controls the significant financial and operating decisions of CWN.
To test whether CWN has sufficient equity at risk to finance its activities without additional subordinated financial support, our audit procedures included, among others, evaluating the equity that is considered “at risk,” testing the related fair value and evaluating whether the equity is sufficient to induce other investors to provide the funds necessary for CWN to conduct its activities. For example, we compared certain information to underlying legal documents and tested the fair value of the equity with the assistance of our valuation specialists. We also considered the amount of equity at risk at other similar entities that finance their operations with no additional subordinated financial support to assess whether CWN has sufficient equity. In addition, to test the Partnership’s assertion that it has control over CWN’s significant financial and operating decisions, we performed audit procedures that included, among others, reviewing management’s analysis of the significant activities (e.g., financing decisions, capital decisions and operating decisions) and evaluating which party has the control over such activities. Our evaluation considered the legal rights of the preferred unit holders (e.g., participating and protective) and whether these rights are substantive in nature such that they would prevent the Partnership from controlling the significant financial and operating decisions of CWN. We also compared the rights of each party to underlying legal documents, the LLC agreement, and management committee minutes.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2013.

Houston, Texas

February 21, 2020

106

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

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

Opinion on Internal Control over Financial Reporting

We have audited Crestwood Equity Partners LP’s internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Crestwood Equity Partners LP (the Partnership) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on the COSO criteria.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets as of December 31, 2019 and 2018 and related consolidated statements of operations, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and financial statement schedules listed in the Index at Item 15(a) of the Partnership and our report dated February 21, 2020 expressed an unqualified opinion thereon.

Basis for Opinion

The Partnership’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 Partnership’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.

Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

As indicated in the accompanying Management’s Report on Internal Control Over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of Jackalope Gas Gathering Services, LLC (Jackalope), which is included in the 2019 consolidated financial statements of the Partnership and constituted 21% and 45% of total and net assets, respectively, as of December 31, 2019 and 2% and 7% of revenues and net income, respectively, for the year then ended. Our audit of internal control over financial reporting of the Partnership also did not include an evaluation of the internal control over financial reporting of Jackalope.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Ernst & Young LLP

Houston, Texas

February 21, 2020

107

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED BALANCE SHEETS (in millions, except unit information)
	December 31,
	2019		2018
Assets
Current assets:
Cash	$	25.7	$	0.9
Restricted cash	—		16.3
Accounts receivable, less allowance for doubtful accounts of $0.3 million at both December 31, 2019 and 2018	242.2		251.5
Inventory	53.7		64.6
Assets from price risk management activities	43.2		34.7
Prepaid expenses and other current assets	11.6		11.3
Total current assets	376.4		379.3
Property, plant and equipment	3,612.5		2,598.1
Less: accumulated depreciation	703.4		568.4
Property, plant and equipment, net	2,909.1		2,029.7
Intangible assets	1,076.3		770.3
Less: accumulated amortization	271.1		216.5
Intangible assets, net	805.2		553.8
Goodwill	218.9		138.6
Operating lease right-of-use assets, net	53.8		—
Investments in unconsolidated affiliates	980.4		1,188.2
Other non-current assets	5.5		4.9
Total assets	$	5,349.3	$	4,294.5
Liabilities and capital
Current liabilities:
Accounts payable	$	189.2	$	213.0
Accrued expenses and other liabilities	161.7		112.4
Liabilities from price risk management activities	6.7		5.8
Current portion of long-term debt	0.2		0.9
Total current liabilities	357.8		332.1
Long-term debt, less current portion	2,328.3		1,752.4
Other long-term liabilities	301.6		173.6
Deferred income taxes	2.6		2.6
Total liabilities	2,990.3		2,260.7
Commitments and contingencies (Note 15)
Interest of non-controlling partner in subsidiary (Note 12)	426.2		—
Crestwood Equity Partners LP partners' capital (72,282,942 and 71,659,385 common and subordinated units issued and outstanding at December 31, 2019 and 2018)	1,320.8		1,240.5
Preferred units (71,257,445 units issued and outstanding at December 31, 2019 and 2018)	612.0		612.0
Total Crestwood Equity Partners LP partners’ capital	1,932.8		1,852.5
Interest of non-controlling partner in subsidiary (Note 12)	—		181.3
Total partners’ capital	1,932.8		2,033.8
Total liabilities and capital	$	5,349.3	$	4,294.5

See accompanying notes.

108

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF OPERATIONS (in millions, except per unit data)
	Year Ended December 31,
	2019			2018		2017
Revenues:
Product revenues:
Gathering and processing	$	455.8		$	670.5	$	1,369.1
Marketing, supply and logistics	2,296.6			2,639.2		2,093.1
Related party (Note 16)	2.9			—		—
	2,755.3			3,309.7		3,462.2
Service revenues:
Gathering and processing	380.0			276.1		317.3
Storage and transportation	20.4			17.1		37.2
Marketing, supply and logistics	26.2			50.2		62.4
Related party (Note 16)	—			1.0		1.8
	426.6			344.4		418.7
Total revenues	3,181.9			3,654.1		3,880.9
Costs of product/services sold (exclusive of items shown separately below):
Product costs	2,469.7			2,950.5		3,309.5
Product costs - related party (Note 16)	45.4			134.7		15.3
Service costs	29.8			44.2		49.9
Total costs of products/services sold	2,544.9			3,129.4		3,374.7
Operating expenses and other:
Operations and maintenance	138.8			125.8		136.0
General and administrative	103.4			88.1		96.5
Depreciation, amortization and accretion	195.8			168.7		191.7
Loss on long-lived assets, net	6.2			28.6		65.6
Gain on acquisition	(209.4		)	—		—
Goodwill impairment	—			—		38.8
Loss on contingent consideration	—			—		57.0
	234.8			411.2		585.6
Operating income (loss)	402.2			113.5		(79.4		)

109

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF OPERATIONS (continued) (in millions, except per unit data)
	Year Ended December 31,
	2019			2018			2017
Earnings from unconsolidated affiliates, net	32.8			53.3			47.8
Interest and debt expense, net	(115.4		)	(99.2		)	(99.4		)
Loss on modification/extinguishment of debt	—			(0.9		)	(37.7		)
Other income, net	0.6			0.4			1.3
Income (loss) before income taxes	320.2			67.1			(167.4		)
(Provision) benefit for income taxes	(0.3		)	(0.1		)	0.8
Net income (loss)	319.9			67.0			(166.6		)
Net income attributable to non-controlling partner	34.8			16.2			25.3
Net income (loss) attributable to Crestwood Equity Partners LP	285.1			50.8			(191.9		)
Net income attributable to preferred units	60.1			60.1			62.5
Net income (loss) attributable to partners	$	225.0		$	(9.3	)	$	(254.4	)
Subordinated unitholders’ interest in net income	$	1.4		$	—		$	—
Common unitholders’ interest in net income (loss)	$	223.6		$	(9.3	)	$	(254.4	)
Net income (loss) per limited partner unit:
Basic	$	3.11		$	(0.13	)	$	(3.64	)
Diluted	$	2.93		$	(0.13	)	$	(3.64	)
Weighted-average limited partners’ units outstanding:
Basic	71.8			71.2			69.8
Dilutive	5.1			—			—
Diluted	76.9			71.2			69.8

See accompanying notes.

110

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME (in millions)
	Year Ended December 31,
	2019		2018			2017
Net income (loss)	$	319.9	$	67.0		$	(166.6	)
Change in fair value of Suburban Propane Partners, L.P. units	0.3		(0.7		)	(0.8		)
Comprehensive income (loss)	320.2		66.3			(167.4		)
Comprehensive income attributable to non-controlling partner	34.8		16.2			25.3
Comprehensive income (loss) attributable to Crestwood Equity Partners LP	$	285.4	$	50.1		$	(192.7	)

See accompanying notes.

111

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (in millions)
	Preferred				Partners
	Units	Capital			Common Units		Subordinated Units	Capital			Non-Controlling Partner			Total Partners’ Capital
Balance at December 31, 2016	66.5	$	564.5		69.1		0.4	$	1,782.0		$	192.5		$	2,539.0
Distributions to partners	4.8	(15.0		)	—		—	(167.6		)	(15.2		)	(197.8		)
Unit-based compensation charges	—	—			0.8		—	25.5			—			25.5
Taxes paid for unit-based compensation vesting	—	—			(0.2	)	—	(5.5		)	—			(5.5		)
Change in fair value of Suburban Propane Partners, L.P. units	—	—			—		—	(0.8		)	—			(0.8		)
Issuance of common units	—	—			0.6		—	15.2			—			15.2
Redemption of non-controlling interest	—	—			—		—	—			(202.7		)	(202.7		)
Issuance of non-controlling interest	—	—			—		—	—			175.0			175.0
Other	—	—			—		—	(0.9		)	0.1			(0.8		)
Net income (loss)	—	62.5			—		—	(254.4		)	25.3			(166.6		)
Balance at December 31, 2017	71.3	612.0			70.3		0.4	1,393.5			175.0			2,180.5
Cumulative effect of accounting change (Note 2)	—	—			—		—	7.5			—			7.5
Distributions to partners	—	(60.1		)	—		—	(170.8		)	(9.9		)	(240.8		)
Unit-based compensation charges	—	—			1.1		—	28.5			—			28.5
Taxes paid for unit-based compensation vesting	—	—			(0.2	)	—	(7.4		)	—			(7.4		)
Change in fair value of Suburban Propane Partners, L.P. units	—	—			—		—	(0.7		)	—			(0.7		)
Other	—	—			—		—	(0.8		)	—			(0.8		)
Net income (loss)	—	60.1			—		—	(9.3		)	16.2			67.0
Balance at December 31, 2018	71.3	612.0			71.2		0.4	1,240.5			181.3			2,033.8
Distributions to partners	—	(60.1		)	—		—	(172.4		)	(6.6		)	(239.1		)
Unit-based compensation charges	—	—			1.0		—	42.4			—			42.4
Taxes paid for unit-based compensation vesting	—	—			(0.3	)	—	(11.0		)	—			(11.0		)
Non-controlling interest reclassification (Note 12)	—	—			—		—	—			(178.8		)	(178.8		)
Change in fair value of Suburban Propane Partners, L.P. units	—	—			—		—	0.3			—			0.3
Other	—	—			—		—	(4.0		)	0.1			(3.9		)
Net income	—	60.1			—		—	225.0			4.0			289.1
Balance at December 31, 2019	71.3	$	612.0		71.9		0.4	$	1,320.8		$	—		$	1,932.8

See accompanying notes.

112

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)
	Year Ended December 31,
	2019			2018			2017
Operating activities
Net income (loss)	$	319.9		$	67.0		$	(166.6	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion	195.8			168.7			191.7
Amortization of debt-related deferred costs	6.2			6.8			7.2
Unit-based compensation charges	47.0			28.5			25.5
Loss on long-lived assets, net	6.2			28.6			65.6
Gain on acquisition	(209.4		)	—			—
Goodwill impairment	—			—			38.8
Loss on contingent consideration	—			—			57.0
Loss on modification/extinguishment of debt	—			0.9			37.7
Earnings from unconsolidated affiliates, net, adjusted for cash distributions received	6.9			0.5			(0.1		)
Deferred income taxes	—			(0.7		)	(2.1		)
Other	—			0.2			0.9
Changes in operating assets and liabilities:
Accounts receivable	42.9			167.8			(170.7		)
Inventory	10.9			(24.1		)	(9.9		)
Prepaid expenses and other current assets	0.1			(3.1		)	1.8
Accounts payable, accrued expenses and other liabilities	(23.3		)	(138.6		)	140.1
Reimbursements of property, plant and equipment	24.8			21.7			19.6
Change in price risk management activities, net	(7.6		)	(70.6		)	19.4
Net cash provided by operating activities	420.4			253.6			255.9
Investing activities
Acquisition, net of cash acquired (Note 3)	(462.1		)	—			—
Purchases of property, plant and equipment	(455.5		)	(305.5		)	(188.4		)
Investment in unconsolidated affiliates	(61.3		)	(64.4		)	(58.0		)
Capital distributions from unconsolidated affiliates	35.5			49.2			59.9
Net proceeds from sale of assets	0.8			79.5			225.2
Other	(1.1		)	—			—
Net cash provided by (used in) investing activities	(943.7		)	(241.2		)	38.7

113

CRESTWOOD EQUITY PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (in millions)
	Year Ended December 31,
	2019			2018			2017
Financing activities
Proceeds from the issuance of long-term debt	2,307.3			2,274.8			2,838.6
Payments on long-term debt	(1,729.5		)	(2,015.7		)	(2,913.9		)
Payments on finance/capital leases	(3.5		)	(1.6		)	(2.7		)
Payments for deferred financing costs	(9.0		)	(5.7		)	(1.0		)
Redemption of non-controlling interest	—			—			(202.7		)
Net proceeds from issuance of non-controlling interest	235.0			—			175.0
Distributions to partners	(172.4		)	(170.8		)	(167.6		)
Distributions to non-controlling partner	(25.0		)	(9.9		)	(15.2		)
Distributions to preferred unitholders	(60.1		)	(60.1		)	(15.0		)
Net proceeds from issuance of common units	—			—			15.2
Taxes paid for unit-based compensation vesting	(11.0		)	(7.4		)	(5.5		)
Other	—			(0.1		)	(0.1		)
Net cash provided by (used in) financing activities	531.8			3.5			(294.9		)
Net change in cash and restricted cash	8.5			15.9			(0.3		)
Cash and restricted cash at beginning of period	17.2			1.3			1.6
Cash and restricted cash at end of period	$	25.7		$	17.2		$	1.3
Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	123.7		$	97.4		$	95.1
Cash paid during the period for income taxes	$	0.6		$	3.1		$	3.1
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(27.7	)	$	0.3		$	(20.4	)

See accompanying notes.

114

Report of Independent Registered Public Accounting Firm

The Board of Directors of Crestwood Equity GP LCC

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of Crestwood Midstream Partners (the Partnership) as of December 31, 2019 and 2018, and the related consolidated statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2019, and the related notes and financial statement schedule listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with U.S. generally accepted accounting principles.

Adoption of ASU No. 2014-09

As discussed in Note 2 to the consolidated financial statements, the Partnership changed its method of accounting for revenue recognition in 2018 due to the of adoption of Accounting Standards Update No. 2014-09, “Revenue from Contracts with Customers (Topic 606).”

Basis for Opinion

These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial reporting. Accordingly, we express no such opinion.

Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Ernst & Young LLP

We have served as the Company’s auditor since 2013.

Houston, Texas

February 21, 2020

115

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED BALANCE SHEETS (in millions)
	December 31,
	2019		2018
Assets
Current assets:
Cash	$	25.4	$	0.2
Restricted cash	—		16.3
Accounts receivable, less allowance for doubtful accounts of $0.3 million at both December 31, 2019 and 2018	241.9		249.9
Inventory	53.7		64.6
Assets from price risk management activities	43.2		34.7
Prepaid expenses and other current assets	11.6		11.3
Total current assets	375.8		377.0
Property, plant and equipment	3,942.6		2,928.2
Less: accumulated depreciation	875.1		725.9
Property, plant and equipment, net	3,067.5		2,202.3
Intangible assets	1,076.3		770.3
Less: accumulated amortization	271.1		216.5
Intangible assets, net	805.2		553.8
Goodwill	218.9		138.6
Operating lease right-of-use assets, net	53.8		—
Investments in unconsolidated affiliates	980.4		1,188.2
Other non-current assets	2.4		2.1
Total assets	$	5,504.0	$	4,462.0
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	186.6	$	210.5
Accrued expenses and other liabilities	160.4		111.3
Liabilities from price risk management activities	6.7		5.8
Current portion of long-term debt	0.2		0.9
Total current liabilities	353.9		328.5
Long-term debt, less current portion	2,328.3		1,752.4
Other long-term liabilities	295.6		171.0
Deferred income taxes	0.7		0.6
Total liabilities	2,978.5		2,252.5
Commitments and contingencies (Note 15)
Interest of non-controlling partner in subsidiary (Note 12)	426.2		—
Partners’ capital	2,099.3		2,028.2
Interest of non-controlling partner in subsidiary (Note 12)	—		181.3
Total partners’ capital	2,099.3		2,209.5
Total liabilities and capital	$	5,504.0	$	4,462.0

See accompanying notes.

116

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF OPERATIONS (in millions)
	Year Ended December 31,
	2019			2018			2017
Revenues:
Product revenues:
Gathering and processing	$	455.8		$	670.5		$	1,369.1
Marketing, supply and logistics	2,296.6			2,639.2			2,093.1
Related party (Note 16)	2.9			—			—
	2,755.3			3,309.7			3,462.2
Service revenues:
Gathering and processing	380.0			276.1			317.3
Storage and transportation	20.4			17.1			37.2
Marketing, supply and logistics	26.2			50.2			62.4
Related party (Note 16)	—			1.0			1.8
	426.6			344.4			418.7
Total revenues	3,181.9			3,654.1			3,880.9
Costs of product/services sold (exclusive of items shown separately below):
Product costs	2,469.7			2,950.5			3,309.5
Product costs - related party (Note 16)	45.4			134.7			15.3
Service costs	29.8			44.2			49.9
Total costs of products/services sold	2,544.9			3,129.4			3,374.7
Operating expenses and other:
Operations and maintenance	138.8			125.8			136.0
General and administrative	98.2			83.5			93.1
Depreciation, amortization and accretion	209.9			181.4			202.7
Loss on long-lived assets, net	6.2			28.6			65.6
Gain on acquisition	(209.4		)	—			—
Goodwill impairment	—			—			38.8
Loss on contingent consideration	—			—			57.0
	243.7			419.3			593.2
Operating income (loss)	393.3			105.4			(87.0		)
Earnings from unconsolidated affiliates, net	32.8			53.3			47.8
Interest and debt expense, net	(115.4		)	(99.2		)	(99.4		)
Loss on modification/extinguishment of debt	—			(0.9		)	(37.7		)
Other income, net	0.2			—			0.8
Income (loss) before income taxes	310.9			58.6			(175.5		)
Provision for income taxes	(0.3		)	—			—
Net income (loss)	310.6			58.6			(175.5		)
Net income attributable to non-controlling partner	34.8			16.2			25.3
Net income (loss) attributable to Crestwood Midstream Partners LP	$	275.8		$	42.4		$	(200.8	)

See accompanying notes.

117

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL (in millions)
	Partners			Non-controlling Partners			Total Partners’ Capital
Balance at December 31, 2016	$	2,550.7		$	192.5		$	2,743.2
Distributions to partners	(174.0		)	(15.2		)	(189.2		)
Unit-based compensation charges	25.5			—			25.5
Taxes paid for unit-based compensation vesting	(5.5		)	—			(5.5		)
Redemption of non-controlling interest	—			(202.7		)	(202.7		)
Issuance of non-controlling interest	—			175.0			175.0
Other	(0.5		)	0.1			(0.4		)
Net income (loss)	(200.8		)	25.3			(175.5		)
Balance at December 31, 2017	2,195.4			175.0			2,370.4
Cumulative effect of accounting change (Note 2)	7.5			—			7.5
Distributions to partners	(238.4		)	(9.9		)	(248.3		)
Unit-based compensation charges	28.5			—			28.5
Taxes paid for unit-based compensation vesting	(7.4		)	—			(7.4		)
Other	0.2			—			0.2
Net income	42.4			16.2			58.6
Balance at December 31, 2018	2,028.2			181.3			2,209.5
Distributions to partners	(235.8		)	(6.6		)	(242.4		)
Unit-based compensation charges	42.4			—			42.4
Taxes paid for unit-based compensation vesting	(11.0		)	—			(11.0		)
Non-controlling interest reclassification (Note 12)	—			(178.8		)	(178.8		)
Other	(0.3		)	0.1			(0.2		)
Net income	275.8			4.0			279.8
Balance at December 31, 2019	$	2,099.3		$	—		$	2,099.3

See accompanying notes.

118

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)
	Year Ended December 31,
	2019			2018			2017
Operating activities
Net income (loss)	$	310.6		$	58.6		$	(175.5	)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion	209.9			181.4			202.7
Amortization of debt-related deferred costs	6.2			6.8			7.2
Unit-based compensation charges	47.0			28.5			25.5
Loss on long-lived assets, net	6.2			28.6			65.6
Gain on acquisition	(209.4		)	—			—
Goodwill impairment	—			—			38.8
Loss on contingent consideration	—			—			57.0
Loss on modification/extinguishment of debt	—			0.9			37.7
Earnings from unconsolidated affiliates, net, adjusted for cash distributions received	6.9			0.5			(0.1		)
Deferred income taxes	0.2			(0.1		)	—
Other	—			0.2			0.9
Changes in operating assets and liabilities:
Accounts receivable	41.6			169.3			(170.5		)
Inventory	10.9			(24.1		)	(9.9		)
Prepaid expenses and other current assets	0.1			(3.1		)	1.8
Accounts payable, accrued expenses and other liabilities	(23.3		)	(138.1		)	142.0
Reimbursements of property, plant and equipment	24.8			21.7			19.6
Change in price risk management activities, net	(7.6		)	(70.6		)	19.4
Net cash provided by operating activities	424.1			260.5			262.2
Investing activities
Acquisition, net of cash acquired (Note 3)	(462.1		)	—			—
Purchases of property, plant and equipment	(455.5		)	(305.5		)	(188.4		)
Investment in unconsolidated affiliates	(61.3		)	(64.4		)	(58.0		)
Capital distributions from unconsolidated affiliates	35.5			49.2			59.9
Net proceeds from sale of assets	0.8			79.5			225.2
Other	(1.1		)	—			—
Net cash provided by (used in) investing activities	(943.7		)	(241.2		)	38.7

119

CRESTWOOD MIDSTREAM PARTNERS LP CONSOLIDATED STATEMENTS OF CASH FLOWS (continued) (in millions)
	Year Ended December 31,
	2019			2018			2017
Financing activities
Proceeds from the issuance of long-term debt	2,307.3			2,274.8			2,838.6
Payments on long-term debt	(1,729.5		)	(2,015.7		)	(2,913.9		)
Payments on finance/capital leases	(3.5		)	(1.6		)	(2.7		)
Payments for deferred financing costs	(9.0		)	(5.7		)	(1.0		)
Redemption of non-controlling interest	—			—			(202.7		)
Net proceeds from issuance of non-controlling interest	235.0			—			175.0
Distributions to partner	(235.8		)	(238.4		)	(174.0		)
Distributions to non-controlling partner	(25.0		)	(9.9		)	(15.2		)
Taxes paid for unit-based compensation vesting	(11.0		)	(7.4		)	(5.5		)
Other	—			0.1			0.2
Net cash provided by (used in) financing activities	528.5			(3.8		)	(301.2		)
Net change in cash and restricted cash	8.9			15.5			(0.3		)
Cash and restricted cash at beginning of period	16.5			1.0			1.3
Cash and restricted cash at end of period	$	25.4		$	16.5		$	1.0
Supplemental disclosure of cash flow information
Cash paid during the period for interest	$	123.7		$	97.4		$	95.1
Cash paid during the period for income taxes	$	0.6		$	0.6		$	0.6
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$	(27.7	)	$	0.3		$	(20.4	)

See accompanying notes.

120

CRESTWOOD EQUITY PARTNERS LP

CRESTWOOD MIDSTREAM PARTNERS LP

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Organization and Description of Business

The accompanying notes to the consolidated financial statements apply to Crestwood Equity Partners LP (the Company, Crestwood Equity or CEQP) and Crestwood Midstream Partners LP (Crestwood Midstream or CMLP) unless otherwise indicated.

Organization

Crestwood Equity Partners LP. CEQP is a publicly-traded (NYSE: CEQP) Delaware limited partnership formed in March 2001. Crestwood Equity GP LLC, which is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), owns our non-economic general partnership interest. Crestwood Holdings, which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve), also owns approximately 25% of Crestwood Equity’s common units and all of its subordinated units.

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

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The diagram below reflects a simplified version of our ownership structure as of December 31, 2019:

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

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Description of Business

Crestwood Equity develops, acquires, owns or controls, and operates primarily fee-based assets and operations within the energy midstream sector. We provide broad-ranging infrastructure solutions across the value chain to service premier liquids-rich natural gas and crude oil shale plays across the United States. We own and operate a diversified portfolio of crude oil and natural gas gathering, processing, storage and transportation assets that connect fundamental energy supply with energy demand across the United States. Crestwood Equity is a holding company and all of its consolidated operating assets are owned by or through its wholly-owned subsidiary, Crestwood Midstream.

Our financial statements reflect three operating and reporting segments described below.

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

• Storage and Transportation. Our storage and transportation (S&T) operations provide crude oil and natural gas storage and transportation services to producers, utilities and other customers. This segment primarily includes (i) the COLT Hub which consists of our integrated crude oil loading, storage and pipeline terminal located in the heart of the Bakken and Three Forks Shale oil-producing areas in Williams County, North Dakota; and (ii) joint ventures that own regulated natural gas storage and transportation facilities in New York and Pennsylvania, natural gas storage facilities in Texas and a crude-by-rail terminal in Wyoming.

• Marketing, Supply and Logistics. Our marketing, supply and logistics (MS&L) operations provide NGL, crude oil and natural gas marketing, storage and transportation services to producers, refiners, marketers and other customers. This segment primarily includes (i) our fleet of rail and rolling stock, which includes our rail-to-truck NGL terminals located in Florida, New Jersey, New York, Rhode Island, North Carolina and Connecticut, and our truck maintenance facilities located in North Dakota, Indiana, West Virginia and New Jersey; (ii) our Bath and Seymour NGL storage facilities located in New York and Indiana; and (iii) our crude oil transportation assets.

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

Basis of Presentation

Our consolidated financial statements are prepared in accordance with GAAP and include the accounts of all consolidated subsidiaries after the elimination of all intercompany accounts and transactions. In management’s opinion, all necessary adjustments to fairly present our results of operations, financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and recurring nature.

Significant Accounting Policies

Principles of Consolidation

We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination to consolidate or apply the equity method of accounting to an entity can also require us to evaluate whether that entity is considered a variable interest entity (VIE). This evaluation, along with the determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions or activities of an entity and in the case of a VIE, are not the primary beneficiary. We use the cost method of accounting where we are unable to exert significant influence over the entity. All of our consolidated entities and equity method investments are not VIEs except for our investment in Crestwood Permian Basin Holdings LLC (Crestwood Permian).

Our equity interest in Crestwood Permian is considered a VIE because CEQP has provided a guarantee to a third party that requires CEQP to pay up to $10 million if Crestwood Permian fails to honor its obligations to its equity investee, Crestwood

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Permian Basin, in the event Crestwood Permian Basin fails to satisfy its obligations under its gas gathering agreement with a third party. We account for our investment in Crestwood Permian as an equity method investment because we are not the primary beneficiary of the VIE as of December 31, 2019 and 2018. See Note 6 for a further discussion of our investment in Crestwood Permian.

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.

Restricted Cash

On January 1, 2018, we adopted the provisions of ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) which changed the classification and presentation of restricted cash in the statement of cash flows. The standard requires us to include restricted cash in our total cash when reconciling the beginning of period and end of period amounts shown on our consolidated statements of cash flows. The retrospective application of this ASU did not have an impact on our consolidated statement of cash flows for the year ended December 31, 2017.

Our restricted cash represents cash held under the terms of certain contractual agreements and is classified as current on our consolidated balance sheets. The $16.3 million decrease in restricted cash during the year ended December 31, 2019 and the $16.3 million increase in restricted cash during the year ended December 31, 2018 is included in operating activities (change in accounts payable, accrued expenses and other liabilities) in the consolidated statements of cash flows.

Inventory

Our inventory is stated at the lower of cost or net realizable value and cost is computed predominantly using the average cost method. Inventory consisted of the following at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Crude oil and NGLs	$	53.2	$	64.2
Spare parts	0.5		0.4
Total inventory	$	53.7	$	64.6

Property, Plant and Equipment

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

	Years
Gathering systems and pipelines	15 - 20
Facilities and equipment	3 - 25
Buildings, rights-of-way and easements	1 - 40
Office furniture and fixtures	5 - 10
Vehicles	5

We 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

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and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset, which is typically based on discounted cash flow projections using assumptions as to revenues, costs and discount rates typical of third party market participants, which is a Level 3 fair value measurement.

During 2019 and 2017, we recorded impairments of our property, plant and equipment and we reflected these impairments in long on long-lived assets in our consolidated statements of operations. We did not record impairments of our property, plant and equipment during the year ended December 31, 2018. During 2019, we incurred $4.3 million of impairments of our property, plant and equipment related to certain of our water gathering facilities in our Arrow operations which is further discussed in Note 15. During 2017, we incurred $81.4 million of impairments of our property, plant and equipment related to our MS&L West Coast operations, which resulted from decreasing the forecasted cash flows to be generated by those operations. At December 31, 2017, our estimates of fair value considered a number of factors, including the potential value if we sold the asset, a 12% discount rate and projected cash flows, which is a Level 3 fair value measurement. During 2018, we sold our MS&L West Coast operations for $70.5 million, and recorded a loss on long-lived assets of approximately $26.9 million (including $9.0 million related to the write off of goodwill). See “Goodwill” below and Note 3 for further information on the sale of these assets.

Projected cash flows of our property, plant and equipment are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, constructions costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Identifiable Intangible Assets

Our identifiable intangible assets consist of customer accounts, trademarks and certain revenue contracts. These intangible assets have arisen primarily from acquisitions. We amortize certain of our revenue contracts based on the projected cash flows associated with these contracts if the projected cash flows are readily determinable, otherwise we amortize our revenue contracts on a straight-line basis.  We recognize acquired intangible assets separately if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

We did not record impairments of our intangible assets during the years ended December 31, 2019 and 2018. During 2017, we fully impaired $0.8 million of intangible assets related to our MS&L West Coast operations, which resulted from decreasing forecasted cash flows to be generated by those operations and we reflected the impairment in loss on long-lived assets in our consolidated statements of operations. During 2018, we sold our MS&L West Coast operations for $70.5 million, and recorded a $26.9 million of loss on long-lived assets associated with the sale. See Note 3 for further information on the sale of these assets.

Projected cash flows of our intangible assets are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:

	Weighted-Average Life (years)
Customer accounts and revenue contracts	20
Trademarks	10

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Goodwill

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

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

Upon acquisition, we are required to record the assets, liabilities and goodwill of a reporting unit at its fair value on the date of acquisition. As a result, any level of decrease in the forecasted cash flows of these businesses or increases in the discount rates utilized to value those businesses from their respective acquisition dates would likely result in the fair value of the reporting unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill is impaired.

Current commodity prices are significantly lower compared to commodity prices during 2014, and that decrease has adversely impacted forecasted cash flows, discount rates and stock/unit prices for most companies in the midstream industry, including us. As a result, we recorded goodwill impairments on several of our reporting units during 2017. We did not record impairments of our goodwill during the years ended December 31, 2019 and 2018. At December 31, 2019, our accumulated goodwill impairments at CEQP and CMLP were approximately $1,656.5 million and $1,399.3 million, respectively. The following table summarizes the goodwill of our various reporting units (in millions):

	Goodwill Impairments during the Year Ended December 31, 2017		Goodwill at January 1, 2018		Other				Impact of Sale of West Coast				Goodwill at December 31, 2018		Goodwill Addition during the Year Ended December 31, 2019			Goodwill at December 31, 2019
G&P
Arrow	$	—	$	45.9	$	—			$	—			$	45.9	$	—		$	45.9
Powder River Basin	—		—		—				—				—		80.3		(3)	80.3
MS&L
NGL Marketing and Logistics	—		—		101.7			(1)	(9.0		)	(2)	92.7		—			92.7
West Coast	2.4		—		—				—				—		—			—
Supply and Logistics	—		101.7		(101.7		)	(1)	—				—		—			—
Storage and Terminals	36.4		—		—				—				—		—			—
Total	$	38.8	$	147.6	$	—			$	(9.0	)		$	138.6	$	80.3		$	218.9

(1) Reflects the combination of the MS&L reporting units into one NGL Marketing and Logistics reporting unit as further discussed below.

(2) In October 2018, we sold our West Coast assets and wrote off the goodwill attributable to these assets as further discussed below.

(3) In April 2019, we acquired the remaining 50% equity interest in Jackalope from Williams. See Note 3 for a further discussion of the acquisition.

On January 1, 2018, we combined the four reporting units included in the MS&L segment into one NGL Marketing and Logistics reporting unit for the purpose of evaluating goodwill for impairment on an ongoing basis. We combined these reporting units based on a strategic shift in the way in which we manage, operate and report our NGL operations as an integrated platform instead of as four individual stand-alone operations. We allocated approximately $9.0 million of the

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goodwill associated with our NGL Marketing and Logistics reporting unit to the West Coast facilities during 2018, and this goodwill was included in the loss on the sale of the West Coast assets. See Note 3 for a further discussion of the sale of our West Coast assets.

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

Leases

We maintain leases in the ordinary course of our business activities. Our leases include those for office buildings, crude oil railroad cars, certain vehicles and other operating facilities and equipment. We also sublease certain of our crude oil railroad cars and trucks to a third party. We do not have any material leases where we are considered to be the lessor. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants.

Prior to January 1, 2019, we classified our leases as either capital or operating leases under ASC Topic 840, Leases (Topic 840). We recognized assets (included in property, plant and equipment) and liabilities (included in accrued expenses and other liabilities and other long-term liabilities) related to our capital leases on our consolidated balance sheets. We also recognized depreciation expense and interest expense related to our capital leases on our consolidated statements of operations. The majority of our lease arrangements were classified as operating leases, under which we did not recognize assets or liabilities on our consolidated balance sheets, but rather recognized lease payments on our consolidated statements of operations as either costs of product/services sold or operations and maintenance expense on a straight-line basis over the lease term.

On January 1, 2019, we adopted the provisions of ASC Topic 842, Leases (Topic 842), which revises the accounting for leases by requiring certain leases to be recognized as assets and liabilities on the balance sheet, and requiring companies to disclose additional information about their leasing arrangements. We adopted the standard using the modified retrospective method. Based on the practical expedients allowed for in the standard, we did not reassess the current GAAP classification of leases, easements and rights of way that existed as of January 1, 2019, and we did not utilize the hindsight method in determining the assets and liabilities to be recorded for our existing leases on January 1, 2019. The adoption of this standard required us to make significant judgments on whether our revenue and expenditure-related contracts were considered to be leases (or contain leases) under Topic 842, and if contracts were considered to be leases whether they should be considered operating leases or finance leases under the new standard. We do not have any material revenue contracts that are considered leases under Topic 842.

Upon the adoption of this standard, on January 1, 2019, we recorded a $67.5 million increase to our operating lease right-of-use assets, an $18.6 million increase to our accrued expenses and other liabilities and a $48.9 million increase to our long-term operating lease liabilities, related to reflecting our operating leases on our consolidated balance sheet as a result of adopting the new standard. We also recorded a $1.6 million increase to our property, plant and equipment, $0.3 million increase to our accrued expenses and other liabilities and a $1.3 million increase to our other long-term liabilities, related to our finance leases (which were all formerly capital leases under Topic 840) as a result of applying the provisions of the new standard to the leases. The adoption of the standard did not result in a material cumulative effect of accounting change to our consolidated financial statements. See Note 15 for a further discussion of our leases.

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Investments in Unconsolidated Affiliates

Equity method investments in which we exercise significant influence, but do not control and are not the primary beneficiary, are accounted for using the equity method of accounting. Differences in the basis of investments and the separate net asset values of the investees, if any, are amortized into net income or loss over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill. We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, or if we decide to sell an investment in unconsolidated affiliate, we adjust the carrying values of the asset downward, if necessary, to their estimated fair values. We did not record impairments of our equity method investments during the years ended December 31, 2019, 2018 and 2017.

Asset Retirement Obligations

An asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. We record a liability for legal or contractual obligations to retire our long-lived assets associated with our facilities and right-of-way contracts we hold. We record a liability in the period the obligation is incurred and estimable. An ARO is initially recorded at its estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the fair value of the liability as a result of the passage of time, which we record as depreciation, amortization and accretion expense on our consolidated statements of operations.

We have various obligations to remove property, plant and equipment on rights-of-way and leases for which we cannot currently estimate the fair value of those obligations because the associated assets have indeterminate lives. An asset retirement obligation liability (and related assets), if any, will be recorded for these obligations once sufficient information is available to reasonably estimate the fair value of the obligations. Our current AROs are reflected in accrued expenses and other liabilities and our long-term AROs are reflected in other long-term liabilities on our consolidated balance sheets. See Note 5 for a further discussion of our AROs.

Deferred Financing Costs

Deferred financing costs represent costs associated with obtaining long-term financing and are amortized over the term of the related debt using a method which approximates the effective interest method and has a weighted average life of five years. Our net deferred financing costs are reflected as a reduction of long-term debt on our consolidated balance sheets.

Revenue Recognition

We provide gathering, processing, compression, storage, fractionation, and transportation (consisting of pipelines, truck and rail terminals, truck/trailer units and rail cars) services and we sell commodities (including crude oil, natural gas, NGLs and water) under various contracts. These contracts include:

• Fixed-fee contracts. Under these contracts, we do not take title to the underlying crude oil, natural gas, NGLs and water but charge our customers a fixed-fee for the services we provide, which can be a firm reservation charge and/or a charge per volume gathered, processed, compressed, stored, loaded and/or transported (which, in certain contracts, can be subject to a minimum level of volumes);

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

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

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

On January 1, 2018, we adopted the provisions of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. We adopted the standard using the modified retrospective method for all revenue contracts that involve revenue generating

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activities that occur after January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under the new standard, while amounts prior to January 1, 2018 continue to be reported in accordance with our historic accounting under Revenue Recognition (Topic 605).

Prior to January 1, 2018, we recognized revenues for services and products when all of the following criteria were met under Topic 605: (i) services had been rendered or products delivered or sold; (ii) persuasive evidence of an exchange arrangement existed; (iii) the price for services was fixed or determinable; and (iv) collectability was reasonably assured. We recorded deferred revenue when we received amounts from our customers but had not yet met the criteria listed above. We recognized deferred revenue in our consolidated statement of operations when the criteria had been met and all services had been rendered.

Beginning January 1, 2018, we recognize revenues for services and products under revenue contracts as our obligations to perform services or deliver/sell products under the contracts are satisfied. A contract’s transaction price is allocated to each performance obligation in the contract and recognized as revenue when, or as, the performance obligation is satisfied. Our fixed-fee contracts and our percentage-of-proceeds service contracts primarily have a single performance obligation to deliver a series of distinct goods or services that are substantially the same and have the same pattern of transfer to our customers. For performance obligations associated with these contracts, we recognize revenues over time utilizing the output method based on the actual volumes of products delivered/sold or services performed, because the single performance obligation is satisfied over time using the same performance measure of progress toward satisfaction of the performance obligation. The transaction price under certain of our fixed-fee contracts and percentage-of-proceeds service contracts includes variable consideration that varies primarily based on actual volumes that are delivered under the contracts. Because the variable consideration specifically relates to our efforts to transfer the services and/or products under the contracts, we allocate the variable consideration entirely to the distinct service utilizing the allocation exception guidance under Topic 606, and accordingly recognize the variable consideration as revenues at the time the good or service is transferred to the customer.

Certain of our fixed-fee contracts contain minimum volume features under which the customers must utilize our services to gather, compress or load a specified quantity of crude oil or natural gas or pay a deficiency fee based on the difference between actual volumes and the contractual minimum volume. We recognize revenues from these contracts when actual volumes are gathered, compressed or loaded and the likelihood of a customer exercising its remaining rights to make up the deficient volumes under minimum volume commitments becomes remote.

We recognize revenues at a point in time for performance obligations associated with our percentage-of proceeds product contracts and purchase and sale contracts, and these revenues are recognized because control of the underlying product is transferred to the customer when the distinct good is provided to the customer.

The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our performance obligations requires significant judgments and assumptions, including our evaluation of the timing of when control of the underlying good or service has transferred to our customers and the relative standalone selling price of goods and services provided to customers under contracts with multiple performance obligations. Actual results can significantly vary from those judgments and assumptions. We did not have any material contracts with multiple performance obligations or under which we receive material amounts of non-cash consideration during the year ended December 31, 2019.

Contract Assets and Contract Liabilities. Amounts due from our customers under our revenue contracts are typically billed as the service is being provided or on a weekly, bi-weekly or monthly basis and are due within 30 days of billing. Under certain of our contracts, we recognize revenues in excess of billings which we present as contract assets on our consolidated balance sheets.

Under certain contracts, we may be entitled to receive payments in advance of satisfying our performance obligations under the contract. We recognize a liability for these payments in excess of revenue recognized and present it as deferred revenue or contract liabilities on our consolidated balance sheets. Our deferred revenue primarily relates to:

• Capital Reimbursements. Certain contracts in our G&P segment require that our customers reimburse us for capital expenditures related to the construction of long-lived assets utilized to provide services to them under the revenue contracts. Because we consider these amounts as consideration from customers associated with ongoing services to be provided to customers, we defer these upfront payments in deferred revenue and recognize the amounts in revenue over the life of the associated revenue contract as the performance obligations are satisfied under the contract. On January 1, 2018, we recorded an $87.6 million increase to our property, plant and equipment, net, a $69.1 million increase to our deferred revenue liability and an $18.5 million increase to partners’ capital as a result of applying the cumulative impact of adopting the new standard on these types of contracts.

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• Contracts with Increasing (Decreasing) Rates per Unit. Certain contracts in our G&P, S&T and MS&L segments have fixed rates per volume that increase and/or decrease over the life of the contract once certain time periods or thresholds are met. We record revenues on these contracts ratably per unit over the life of the contract based on the remaining performance obligations to be performed, which can result in the deferral of revenue for the difference between the consideration received and the ratable revenue recognized. On January 1, 2018, we recorded a $1.5 million increase to our deferred revenue liability and a corresponding decrease to partners’ capital as a result of applying the cumulative impact of adopting the new standard on these types of contracts.

Credit Risk and Concentrations

Inherent in our contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing credit risk and have established control procedures, which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate.

Income Taxes

Crestwood Equity is a master limited partnership and Crestwood Midstream is a limited partnership. Partnerships are generally not subject to federal income tax, although publicly-traded partnerships are treated as corporations for federal income tax purposes and therefore are subject to federal income tax, unless the partnership generates at least 90% of its gross income from qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a partnership for federal income tax purposes. We satisfy the qualifying income requirement and are treated as a partnership for federal and state income tax purposes. Our consolidated earnings are included in the federal and state income tax returns of our partners. However, legislation in certain states allows for taxation of partnerships, and as such, certain state taxes have been included in our accompanying financial statements as income taxes due to the nature of the tax in those particular states as discussed below. In addition, federal and state income taxes are provided on the earnings of the subsidiaries incorporated as taxable entities. We are required to recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax basis of assets and liabilities using expected rates in effect for the year in which the differences are expected to reverse.

We are responsible for the Texas Margin tax computed on the Texas franchise tax returns. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Environmental Costs and Other Contingencies

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

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

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

Price Risk Management Activities

We utilize certain derivative financial instruments to (i) manage our exposure to commodity price risk, specifically, the related change in the fair value of inventory, as well as the variability of cash flows related to forecasted transactions; (ii) ensure the availability of adequate physical supply of commodity; and (iii) manage our exposure to the interest rate risk associated with fixed and variable rate borrowings. We record all derivative instruments on the balance sheet at their fair values as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded through current earnings.

We did not have any derivatives designated as fair value hedges or cash flow hedges for accounting purposes during the years ended December 31, 2019, 2018 or 2017.

Unit-Based Compensation

Long-term incentive awards are granted under the Crestwood Equity incentive plan. Unit-based compensation awards consist of restricted units that are valued at the closing market price of CEQP’s common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. We generally recognize the expense associated with the award over the vesting period on a straight line basis.

New Accounting Pronouncement Issued But Not Yet Adopted

As of December 31, 2019, the following accounting standard had not yet been adopted by us:

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326), which provides guidance on how companies should evaluate their accounts and notes receivable and other financial instruments for impairment. The standard requires companies to evaluate their financial instruments for impairment by recording an allowance for doubtful accounts and/or bad debt expense based on certain categories of instruments rather than a specific identification approach. We utilized a method to estimate the allowance for doubtful accounts that considered both the aging of our accounts receivable and the projected loss rate of our receivables to adopt the provisions of this standard effective January 1, 2020. Upon adoption of this standard, we anticipate increasing our allowance for doubtful accounts by approximately $0.7 million.

Note 3 – Acquisition and Divestitures

Acquisition

On April 9, 2019, Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, acquired Williams Partners LP’s (Williams) 50% equity interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) for approximately $484.6 million (Jackalope Acquisition). The acquisition was funded through a combination of borrowings under the CMLP credit facility and the issuance of $235 million of new preferred units to CN Jackalope Holdings LLC (Jackalope Holdings) (see Note 12 for a further discussion of the issuance of the new preferred units). Prior to the Jackalope Acquisition, Crestwood Niobrara owned a 50% equity interest in Jackalope, which we accounted for under the equity method of accounting. As a result of this transaction, Crestwood Niobrara controls and owns 100% of the equity interests in Jackalope. The financial results of Jackalope are included in our gathering and processing segment from the date of the acquisition. Transaction costs related to the Jackalope Acquisition were approximately $2.8 million during the year ended December 31, 2019. These costs are included in operations and maintenance expenses in our consolidated statements of operations.

The fair values of the assets acquired and liabilities assumed were determined primarily utilizing market-related information and other projections on the performance of the assets acquired, including an analysis of the discounted cash flows at a discount rate of approximately 12%. Those fair values are Level 3 fair value measurements and were developed by management with the assistance of a third-party valuation firm.

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The following table summarizes the final valuation of the assets acquired and liabilities assumed at the acquisition date (in millions):

Cash	$	22.5
Other current assets	30.9
Property, plant and equipment	532.9
Intangible assets	306.0
Goodwill	80.3
Current liabilities	(30.4		)
Other long-term liabilities	(21.5		)
Estimated fair value of 100% interest in Jackalope	920.7
Less:
Elimination of equity investment in Jackalope	226.7
Gain on acquisition of Jackalope	209.4
Total purchase price	$	484.6

The identifiable intangible assets primarily consists of a customer contract that has a weighted-average remaining life of 17 years. The goodwill recognized relates primarily to anticipated operating synergies between the assets acquired and our existing operations. The fair value of the assets acquired and liabilities assumed in the Jackalope Acquisition exceeded the sum of the cash consideration paid and the historical book value of our 50% equity interest in Jackalope (which was remeasured at fair value and derecognized) and, as a result, we recognized a gain of approximately $209.4 million. This gain is included in gain on acquisition in our consolidated statements of operations.

Our consolidated statements of operations include the results of Jackalope since April 9, 2019, the closing date of the acquisition. During the year ended December 31, 2019, we recognized approximately $70.1 million of revenues and $20.9 million of net income related to Jackalope’s operations.

The tables below presents selected unaudited pro forma information as if the Jackalope Acquisition had occurred on January 1, 2017 (in millions). The pro forma information is not necessarily indicative of the financial results that would have occurred if the transaction had been completed as of the dates indicated. The amounts have been calculated after applying our accounting policies and adjusting the results to reflect the depreciation, amortization and accretion expense that would have been charged assuming the fair value adjustments to property, plant and equipment and intangible assets had been made at the beginning of the respective reporting period. The pro forma net income also includes the effects of interest expense on incremental borrowings and recognition of deferred revenue.

Crestwood Equity

	Year Ended December 31,
	2019		2018		2017
Revenues	$	3,202.6	$	3,729.5	$	3,935.4
Net income (loss)	$	313.5	$	45.0	$	(193.0	)

Crestwood Midstream

	Year ended December 31,
	2019		2018		2017
Revenues	$	3,202.6	$	3,729.5	$	3,935.4
Net income (loss)	$	304.2	$	36.6	$	(201.9	)

Divestitures

In October 2018, we sold our West Coast assets to a third party for proceeds of approximately $70.5 million. The West Coast assets included a gas gathering and processing system, fractionator, butamer and various rail and truck terminal and storage facilities located in California, Nevada, Wyoming and Utah. The sale of West Coast resulted in a decrease of $61.8 million of

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property, plant and equipment, net, $9.0 million of goodwill and $26.6 million of other assets and liabilities, net. During the year ended December 31, 2018, we recognized a loss from the sale of approximately $26.9 million (including the goodwill write off discussed in Note 2), which is included in loss on long-lived assets, net in our consolidated statement of operations. Our West Coast assets were previously included in our MS&L segment.

In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP, for net proceeds of approximately $223.6 million, and we recognized a gain from the sale of approximately $33.6 million, which is included in loss on long-lived assets, net in our consolidated statement of operations. US Salt was previously included in our MS&L segment.

Note 4 – Certain Balance Sheet Information

Property, Plant and Equipment

Property, plant and equipment consisted of the following at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Gathering systems and pipelines and related assets	$	1,017.8	$	758.6	$	1,160.6	$	901.5
Facilities and equipment	1,797.7		1,230.7		1,982.8		1,415.9
Buildings, land, rights-of-way, storage rights and easements	370.6		331.7		374.3		335.4
Vehicles	27.7		17.9		26.0		16.1
Construction in process	368.7		230.8		368.7		230.8
Office furniture and fixtures	30.0		28.4		30.2		28.5
	3,612.5		2,598.1		3,942.6		2,928.2
Less: accumulated depreciation	703.4		568.4		875.1		725.9
Total property, plant and equipment, net	$	2,909.1	$	2,029.7	$	3,067.5	$	2,202.3

Depreciation. CEQP’s depreciation expense totaled $139.5 million, $123.6 million and $135.9 million for the years ended December 31, 2019, 2018 and 2017. CMLP’s depreciation expense totaled $153.5 million, $137.7 million and $150.0 million for the years ended December 31, 2019, 2018 and 2017.

Capitalized Interest. During the years ended December 31, 2019, 2018 and 2017, CEQP and CMLP capitalized interest of $14.4 million, $5.0 million and $2.9 million related to certain expansion projects.

Finance Leases. We had finance lease assets of $9.5 million and $9.7 million included in property, plant and equipment, net at December 31, 2019 and 2018, primarily related to certain vehicle leases. See Notes 2 and 15 for a further discussion of our finance lease assets.

Intangible Assets

Intangible assets at CEQP and CMLP consisted of the following at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Customer accounts	$	438.9	$	438.9
Gas gathering, compression and processing contracts (1)	631.2		325.2
Trademarks	6.2		6.2
	1,076.3		770.3
Less: accumulated amortization	271.1		216.5
Total intangible assets, net	$	805.2	$	553.8

(1) Includes $306.0 million related to a revenue contract acquired from the Jackalope Acquisition, which is further discussed in Note 3.

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The following table summarizes total accumulated amortization of CEQP’s and CMLP’s intangible assets at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Customer accounts	$	134.4	$	112.1
Gas gathering, compression and processing contracts	132.5		100.8
Trademarks	4.2		3.6
Total accumulated amortization	$	271.1	$	216.5

Crestwood Equity’s amortization expense related to its intangible assets for the years ended December 31, 2019, 2018 and 2017, was approximately $54.6 million, $43.5 million and $53.7 million. Crestwood Midstream’s amortization expense related to its intangible assets for the years ended December 31, 2019, 2018 and 2017 was approximately $54.6 million, $42.1 million and $50.6 million.

Estimated amortization of CEQP’s and CMLP’s intangible assets for the next five years is as follows (in millions):

Year Ending December 31,
2020	$	58.9
2021	$	58.9
2022	$	58.9
2023	$	55.0
2024	$	50.1

Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Accrued expenses(1)	$	61.6	$	64.8	$	60.3	$	63.7
Accrued property taxes	6.1		2.6		6.1		2.6
Income tax payable	0.3		0.3		0.3		0.3
Interest payable	25.6		19.8		25.6		19.8
Accrued additions to property, plant and equipment	38.0		10.5		38.0		10.5
Operating leases	18.1		—		18.1		—
Finance leases	3.2		2.4		3.2		2.4
Deferred revenue	8.8		12.0		8.8		12.0
Total accrued expenses and other liabilities	$	161.7	$	112.4	$	160.4	$	111.3

(1) Includes $16.2 million of related party accrued expenses at December 31, 2018 related to deposits received from Jackalope prior to the acquisition of the remaining 50% equity interest in Jackalope from Williams in April 2019.

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Other Long-Term Liabilities

Other long-term liabilities consisted of the following at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Contract liabilities	$	144.7	$	65.4	$	144.7	$	65.4
Contingent consideration	57.0		57.0		57.0		57.0
Operating leases	41.5		—		41.5		—
Asset retirement obligations	33.3		27.6		33.3		27.6
Other	25.1		23.6		19.1		21.0
Total other long-term liabilities	$	301.6	$	173.6	$	295.6	$	171.0

Note 5 - Asset Retirement Obligations

We have legal obligations associated with our facilities and right-of-way contracts we hold. Where we can reasonably estimate the ARO, we accrue a liability based on an estimate of the timing and amount of settlement. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations. We did not have any material assets that were legally restricted for use in settling asset retirement obligations as of December 31, 2019 and 2018.

The following table presents the changes in the net asset retirement obligations for the years ended December 31, 2019 and 2018 (in millions):

	2019			2018
Net asset retirement obligations at January 1	$	28.1		$	28.1
Liabilities acquired (1)	1.7			—
Liabilities incurred	3.4			1.2
Liabilities settled	(0.1		)	(2.8		)
Accretion expense	1.7			1.6
Net asset retirement obligations at December 31 (2)	$	34.8		$	28.1

(1) Relates to the Jackalope Acquisition, which is further discussed in Note 3.

(2) Includes $1.5 million and $0.5 million of current ARO liabilities at December 31, 2019 and 2018.

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Note 6 - Investments in Unconsolidated Affiliates

Net Investments and Earnings (Loss)

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

	Ownership Percentage			Investment				Earnings (Loss) from Unconsolidated Affiliates
	December 31,			December 31,				Year Ended December 31,
	2019			2019		2018		2019			2018		2017
Stagecoach Gas Services LLC	50.00	%		$	814.4	$	830.4	$	34.2		$	29.3	$	25.3
Jackalope Gas Gathering Services, L.L.C.(1)	—	%	(1)	—		210.2		3.7			18.1		10.5
Crestwood Permian Basin Holdings LLC(2)	50.00	%		121.8		104.3		(5.8		)	4.4		8.4
Tres Palacios Holdings LLC	50.01	%		35.9		35.0		0.9			—		2.2
Powder River Basin Industrial Complex, LLC	50.01	%		8.3		8.3		(0.2		)	1.5		1.4
Total				$	980.4	$	1,188.2	$	32.8		$	53.3	$	47.8

(1) On April 9, 2019, Crestwood Niobrara acquired Williams’ 50% equity interest in Jackalope and, as a result, Crestwood Niobrara controls and owns 100% of the equity interests in Jackalope. See Note 3 for a further discussion of this acquisition.

(2) Pursuant to the Crestwood Permian limited liability company agreement, we were allocated 100% of Crestwood New Mexico’s earnings through June 30, 2018. Effective July 1, 2018, our equity earnings from Crestwood New Mexico is based on our ownership percentage of Crestwood Permian, which is currently 50%.

Description of Investments

Stagecoach Gas Services LLC

Crestwood Pipeline and Storage Northeast LLC, our wholly-owned subsidiary, owns a 50% equity interest in Stagecoach Gas Services LLC (Stagecoach Gas), and Con Edison Gas Pipeline and Storage Northeast, LLC (CEGP) owns the remaining 50% equity interest in Stagecoach Gas. We account for our 50% equity interest in Stagecoach Gas under the equity method of accounting. Our Stagecoach Gas investment is included in our storage and transportation segment.

Pursuant to the Stagecoach Gas limited liability company agreement, we may be required to make payments of up to $57 million to CEGP after December 31, 2020 if certain criteria are not met by Stagecoach Gas by December 31, 2020, including achieving certain performance targets on growth capital projects. These growth capital projects depend on the construction of other third-party expansion projects, and during 2017, those third-party projects experienced regulatory and other delays that caused Stagecoach Gas to delay its growth capital projects. As a result, our consolidated balance sheets reflect an other long-term liability of $57 million at December 31, 2019 and 2018, and our consolidated income statement for the year ended December 31, 2017 reflects a $57 million loss on contingent consideration related to this obligation.

Jackalope Gas Gathering Services, L.L.C.

On April 9, 2019, Crestwood Niobrara, our consolidated subsidiary, acquired Williams’ 50% equity interest in Jackalope and, as a result, Crestwood Niobrara controls and owns 100% of the equity interests in Jackalope. As a result of this transaction, we eliminated our historical equity investment in Jackalope of approximately $226.7 million as of April 9, 2019 and began consolidating Jackalope’s operations. Our Jackalope investment was included in our gathering and processing segment.

On January 1, 2018, Jackalope adopted the provisions of Topic 606, and we recorded a $9.5 million decrease to our equity method investment and a corresponding decrease to our partners’ capital to reflect our proportionate share of the cumulative effect of accounting change recorded by Jackalope related to the new standard. In addition, our earnings from unconsolidated affiliates decreased by approximately $9.7 million during the year ended December 31, 2018 to reflect our proportionate share of Jackalope’s deferred revenues related to the new standard.

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Crestwood Permian Basin Holdings LLC

Crestwood Infrastructure, our wholly-owned subsidiary, owns a 50% equity interest in Crestwood Permian and an affiliate of First Reserve owns the remaining 50% equity interest in Crestwood Permian. We manage and account for our 50% ownership interest in Crestwood Permian, which is a VIE, under the equity method of accounting as we exercise significant influence, but do not control Crestwood Permian and we are not its primary beneficiary due to First Reserve’s rights to exercise control over the entity. Our Crestwood Permian investment is included in our gathering and processing segment.

Prior to October 2017, Crestwood Permian owned 100% of the equity interest of Crestwood Permian Basin LLC (Crestwood Permian Basin). Crestwood Permian Basin has a long-term agreement with SWEPI LP (SWEPI), a subsidiary of Royal Dutch Shell plc, to construct, own and operate a natural gas gathering system (the Nautilus gathering system) in SWEPI’s operated position in the Delaware Permian. In conjunction with the Crestwood Permian Basin’s agreement with SWEPI, Crestwood Permian granted Shell Midstream Partners L.P. (Shell Midstream), a subsidiary of Royal Dutch Shell plc, an option to purchase up to 50% equity interest in Crestwood Permian Basin. In October 2017, Shell Midstream exercised its option and purchased a 50% equity interest in Crestwood Permian Basin from Crestwood Permian for approximately $37.9 million in cash. Crestwood Permian distributed to us approximately $18.9 million of the cash proceeds received.

CEQP issued a guarantee in conjunction with the Crestwood Permian Basin gas gathering agreement with SWEPI described above, under which CEQP agreed to fund 100% of the costs to build the Nautilus gathering system if Crestwood Permian failed to do so. In conjunction with the expiration of that guarantee during 2019, a guarantee became effective that would require CEQP to pay up to $10 million if Crestwood Permian fails to honor its obligations to Crestwood Permian Basin in the event Crestwood Permian Basin fails to satisfy its obligations under its gas gathering agreement with SWEPI. We do not believe this guarantee is probable of resulting in future losses based on our assessment of the nature of the guarantee, the financial condition of the guaranteed party and the period of time that the guarantee has been outstanding, and as a result, we have not recorded a liability on our balance sheet at December 31, 2019 and 2018.

Tres Palacios Holdings LLC

Crestwood Midstream owns a 50.01% ownership interest in Tres Palacios Holdings LLC (Tres Holdings) and is the operator of Tres Palacios Gas Storage LLC (Tres Palacios) and its assets. Brookfield Infrastructure Group owns the remaining 49.99% ownership interest in Tres Holdings. We account for our investment in Tres Holdings under the equity method of accounting. Our Tres Holdings investment is included in our storage and transportation segment.

Powder River Basin Industrial Complex, LLC

Crestwood Crude Logistics LLC, our wholly-owned subsidiary, owns a 50% ownership interest in PRBIC which we account for under the equity method of accounting. Twin Eagle Powder River Basin, LLC owns the remaining 50% ownership interest in PRBIC. Our PRBIC investment is included in our storage and transportation segment

Summarized Financial Information of Unconsolidated Affiliates

Below is summarized financial information for our significant unconsolidated affiliates (in millions; amounts represent 100% of unconsolidated affiliate information):

Financial Position Data

	December 31,
	2019										2018
	Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity		Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity
Stagecoach(1)	$	50.6	$	1,686.3	$	3.9	$	1.5	$	1,731.5	$	50.1	$	1,725.1	$	4.2	$	0.9	$	1,770.1
Crestwood    Permian(2)	15.9		386.8		16.3		72.1		314.3		17.7		372.6		16.8		94.7		278.8
Other(3)	11.7		277.9		21.0		121.1		147.5		59.3		658.0		17.4		129.6		570.3
Total	$	78.2	$	2,351.0	$	41.2	$	194.7	$	2,193.3	$	127.1	$	2,755.7	$	38.4	$	225.2	$	2,619.2

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(1) As of December 31, 2019, our equity in the underlying net assets of Stagecoach Gas exceeded our investment balance by approximately $51.3 million. This excess amount is entirely attributable to goodwill and, as such, is not subject to amortization.

(2) As of December 31, 2019, the difference of approximately $11.5 million between our equity in Crestwood Permian’s net assets and our investment balance is not subject to amortization.

(3) Includes our Tres Holdings and PRBIC equity investments at December 31, 2019 and 2018, and our Jackalope equity investment at December 31, 2018. As of December 31, 2019, our equity in the underlying net assets of Tres Holdings and PRBIC exceeded our investment balance by approximately $24.0 million and $5.5 million, respectively.

Operating Results Data

	Year Ended December 31,
	2019							2018						2017
	Operating Revenues		Operating Expenses		Net  Income (Loss)			Operating Revenues		Operating Expenses		Net  Income		Operating Revenues		Operating Expenses		Net  Income
Stagecoach	$	163.8	$	83.6	$	80.6		$	171.4	$	79.3	$	92.1	$	168.6	$	77.7	$	91.1
Crestwood Permian	64.8		76.0		(11.1		)	82.2		81.3		5.7		87.3		74.1		14.1
Other(1)	55.1		49.9		5.1			116.9		81.5		35.6		94.5		69.5		24.8
Total	$	283.7	$	209.5	$	74.6		$	370.5	$	242.1	$	133.4	$	350.4	$	221.3	$	130.0

(1) Includes our Jackalope (prior to the acquisition of the remaining 50% interest from Williams in April 2019), Tres Holdings and PRBIC equity investments. We amortize the excess basis in certain of our equity investments as an increase in our earnings from unconsolidated affiliates. We recorded amortization of the excess basis in our Jackalope equity investment of less than $0.1 million for each of the years ended December 31, 2019, 2018 and 2017, which we amortized over the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake). We recorded amortization of the excess basis in our Tres Holdings equity investment of approximately $1.3 million for each of the years ended December 31, 2019, 2018 and 2017, which we amortize over the life of Tres Palacios’ sublease agreement. We recorded amortization of the excess basis in our PRBIC equity investment of approximately $0.4 million, $0.5 million and $0.6 million for the years ended December 31, 2019, 2018 and 2017, which we amortize over the life of PRBIC’s property, plant and equipment.

Distributions and Contributions

	Distributions						Contributions
	Year Ended December 31,						Year Ended December 31,
	2019		2018		2017		2019		2018		2017
Stagecoach Gas	$	52.3	$	48.7	$	47.3	$	2.1	$	—	$	0.8
Jackalope	11.6		32.4		26.3		24.4		49.1		3.5
Crestwood Permian(1)	5.0		14.7		23.4		28.3		12.6		117.5
Tres Holdings(2)	6.3		5.3		9.0		6.3		2.5		5.6
PRBIC(3)	—		1.9		1.6		0.2		0.2		—
Total	$	75.2	$	103.0	$	107.6	$	61.3	$	64.4	$	127.4

(1) On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico Pipeline LLC (Crestwood New Mexico) at our historical book value of approximately $69.4 million. This contribution was treated as a non-cash transaction between entities under common control.

(2) Tres Holdings is required, within 30 days following the end of each quarter, to make quarterly distributions of its available cash (as defined in its limited

liability company agreement) to its members based on their respective ownership percentage.

(3) PRBIC is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage.

Stagecoach Gas. Stagecoach Gas is required, within 30 days following the end of each quarter, to distribute its available cash (as defined in its limited liability company agreement) to its members. Pursuant to the Stagecoach limited liability company agreement, our share of Stagecoach’s available cash increased from 40% to 50% effective July 1, 2019. Prior to July 1, 2019, Stagecoach Gas distributed 40% of its available cash to us and prior to July 1, 2018, Stagecoach Gas distributed 35% of its available cash to us. Because our ownership and distribution percentages differed prior to July 1, 2019, equity earnings from Stagecoach Gas were determined using the Hypothetical Liquidation at Book Value (HLBV) method. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount of cash an equity investment would distribute to its members if the equity investment were to liquidate all of its assets, as valued in accordance with GAAP. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is the members’ share of the earnings or losses from the equity investment

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for the period, which approximates how earnings are allocated under the terms of the limited liability company agreement. In January 2020, we received a cash distribution from Stagecoach Gas of approximately $15.5 million.

Crestwood Permian. Crestwood Permian is required, within 30 days following the end of each quarter to distribute 100% of its available cash (as defined in its limited liability company agreement) to its members based on their respective ownership percentages. Pursuant to Crestwood Permian's limited liability company agreement, we received 100% of Crestwood New Mexico's available cash (as defined in the limited liability company agreement) through June 30, 2018, and subsequent to June 30, 2018, our distributions are based on the members respective ownership percentages. Because our ownership and distribution percentages differed prior to June 30, 2018, equity earnings from Crestwood Permian were determined using the HLBV method discussed above. In January 2020, we received a cash distribution from Crestwood Permian of approximately $3.8 million.

Note 7 – Risk Management

We are exposed to certain market risks related to our ongoing business operations. These risks include exposure to changing commodity prices. We utilize derivative instruments to manage our exposure to fluctuations in commodity prices, which is discussed below. Additional information related to our derivatives is discussed in Note 2 and Note 8.

Commodity Derivative Instruments and Price Risk Management

Risk Management Activities

We sell NGLs (such as propane, ethane, butane and heating oil), crude oil and natural gas to energy-related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of NGLs, crude oil and natural gas. We periodically enter into offsetting positions to economically hedge against the exposure our customer contracts create. Certain of these contracts and positions are derivative instruments. We do not designate any of our commodity-based derivatives as hedging instruments for accounting purposes. Our commodity-based derivatives are reflected at fair value in the consolidated balance sheets, and changes in the fair value of these derivatives that impact the consolidated statements of operations are reflected in costs of product/services sold. Our commodity-based derivatives that are settled with physical commodities are reflected as an increase to product revenues, and the commodity inventory that is utilized to satisfy those physical obligations is reflected as an increase to costs of product sold in our consolidated statements of operations. The following table summarizes the impact to our consolidated statements of operations related to our commodity-based derivatives reflected in operating revenues and costs of product/services sold during the years ended December 31, 2019, 2018 and 2017 (in millions):

	December 31,
	2019		2018		2017
Product revenues	$	252.3	$	343.3	$	234.1
Gain (loss) reflected in costs of product/services sold	$	19.5	$	29.6	$	(31.2	)

We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. This balance in the contractual portfolio significantly reduces the volatility in costs of product/services sold related to these instruments.

Commodity Price and Credit Risk

Notional Amounts and Terms

The notional amounts and terms of our derivative financial instruments include the following:

	December 31, 2019		December 31, 2018
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, ethane, butane, heating oil and crude oil (MMBbls)	33.5	36.6	27.8	30.1
Natural gas (Bcf)	3.7	8.7	1.8	1.8

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Notional amounts reflect the volume of transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not reflect our monetary exposure to market or credit risks. All contracts subject to price risk had a maturity of 37 months or less; however, 85% of the contracted volumes will be delivered or settled within 12 months.

Credit Risk

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

Certain of our derivative instruments have credit limits that require us to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as our established credit limit with the respective counterparty. If our credit rating were to change, the counterparties could require us to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as well as the requirements of the individual counterparty. In addition, we have margin requirements with a New York Mercantile Exchange (NYMEX) broker related to our net asset or liability position with such broker. All collateral amounts have been netted against the asset or liability with the respective counterparty and are reflected in our consolidated balance sheets as assets and liabilities from price risk management activities.

The following table presents the fair value of our commodity derivative instruments with credit-risk-related contingent features and their associated collateral (in millions):

	December 31,
	2019		2018
Aggregate fair value of derivative instruments with credit-risk-related    contingent features(1)	$	1.6	$	2.2
NYMEX-related net derivative liability position	$	28.8	$	9.4
NYMEX-related cash collateral posted	$	40.4	$	21.7
Cash collateral received, net	$	16.9	$	14.2

(1) At December 31, 2019 and 2018, we posted less than $0.1 million of collateral associated with these derivatives.

Note 8 – Fair Value Measurements

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

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

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

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Instruments in this category include non-exchange-traded derivatives such as over the counter (OTC) forwards, options and physical exchanges.

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

Cash, Accounts Receivable and Accounts Payable

As of December 31, 2019 and 2018, the carrying amounts of cash, accounts receivable and accounts payable approximate fair value based on the short-term nature of these instruments.

Credit Facility

The fair value of the amounts outstanding under our Crestwood Midstream credit facility approximates the carrying amounts as of December 31, 2019 and 2018, due primarily to the variable nature of the interest rate of the instrument, which is considered a Level 2 fair value measurement.

Senior Notes

We estimate the fair value of our senior notes primarily based on quoted market prices for the same or similar issuances (representing a Level 2 fair value measurement). The following table represents the carrying amount (reduced for deferred financing costs associated with the respective notes) and fair value of our senior notes (in millions):

	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2023 Senior Notes	$	695.1	$	714.0	$	693.6	$	668.1
2025 Senior Notes	$	494.4	$	514.4	$	493.4	$	466.2
2027 Senior Notes	$	592.1	$	610.1	$	—	$	—

Financial Assets and Liabilities

As of December 31, 2019 and 2018, we held certain assets and liabilities that are required to be measured at fair value on a recurring basis, which include our derivative instruments related to heating oil, crude oil, and NGLs. Our derivative instruments consist of forwards, swaps, futures, physical exchanges and options.

Our derivative instruments that are traded on the NYMEX have been categorized as Level 1.

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

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

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

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The following tables set forth by level within the fair value hierarchy, our financial instruments that were accounted for at fair value on a recurring basis at December 31, 2019 and 2018 (in millions):

	December 31, 2019
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Fair Value
Assets
Assets from price risk management	$	3.7	$	164.0	$	—	$	167.7	$	(122.3	)	$	(2.2	)	$	43.2
Suburban Propane Partners, L.P. units(2)	3.1		—		—		3.1		—			—			3.1
Total assets at fair value	$	6.8	$	164.0	$	—	$	170.8	$	(122.3	)	$	(2.2	)	$	46.3
Liabilities
Liabilities from price risk management	$	2.8	$	151.9	$	—	$	154.7	$	(122.3	)	$	(25.7	)	$	6.7
Total liabilities at fair value	$	2.8	$	151.9	$	—	$	154.7	$	(122.3	)	$	(25.7	)	$	6.7
	December 31, 2018
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Fair Value
Assets
Assets from price risk management	$	12.4	$	160.7	$	—	$	173.1	$	(140.3	)	$	1.9		$	34.7
Suburban Propane Partners, L.P. units(2)	2.8		—		—		2.8		—			—			2.8
Total assets at fair value	$	15.2	$	160.7	$	—	$	175.9	$	(140.3	)	$	1.9		$	37.5
Liabilities
Liabilities from price risk management	$	7.0	$	144.7	$	—	$	151.7	$	(140.3	)	$	(5.6	)	$	5.8
Total liabilities at fair value	$	7.0	$	144.7	$	—	$	151.7	$	(140.3	)	$	(5.6	)	$	5.8

(1) Amounts represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.

(2) Amount is reflected in other assets on CEQP’s consolidated balance sheets.

Note 9 – Long-Term Debt

Long-term debt consisted of the following at December 31, 2019 and 2018, (in millions):

	December 31,
	2019		2018
Credit Facility	$	557.0	$	578.2
2023 Senior Notes	700.0		700.0
2025 Senior Notes	500.0		500.0
2027 Senior Notes	600.0		—
Other	0.6		1.5
Less: deferred financing costs, net	29.1		26.4
Total debt	2,328.5		1,753.3
Less: current portion	0.2		0.9
Total long-term debt, less current portion	$	2,328.3	$	1,752.4

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Credit Facility

In October 2018, Crestwood Midstream entered into a Second Amended and Restated Agreement (the CMLP Credit Agreement). The CMLP Credit Agreement provides for a five-year $1.25 billion revolving credit facility (the CMLP Credit Facility), which expires in October 2023 and is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The CMLP Credit Facility allows Crestwood Midstream to increase its available borrowings under the facility by $350.0 million, subject to lender approval and the satisfaction of certain other conditions, as described in the CMLP Credit Agreement. The CMLP Credit Facility also includes a sub-limit of up to $25.0 million for same-day swing line advances and a sub-limit up to $350.0 million for letters of credit. Subject to limited exception, the CMLP Credit Facility is guaranteed and secured by substantially all of the equity interests and assets of Crestwood Midstream’s subsidiaries, except for Crestwood Infrastructure, Crestwood Niobrara, Crestwood Northeast, PRBIC and Tres Holdings and their respective subsidiaries. The Company also guarantees Crestwood Midstream’s payment obligations under its $1.25 billion credit agreement.

Prior to amending and restating its credit agreement in October 2018, Crestwood Midstream had a five-year $1.5 billion senior secured revolving credit facility, which would have expired September 2020 (2020 Credit Facility). We recognized a loss on modification of debt of approximately $0.9 million for the year ended December 31, 2018 in conjunction with amending and restating the CMLP Credit Agreement.

Borrowings under the CMLP Credit Facility (other than the swing line loans) bear interest at either:

• the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) Wells Fargo Bank’s prime rate; or (iii) the Eurodollar Rate adjusted for certain reserve requirements plus 1%; plus a margin varying from 0.50% to 1.50% at December 31, 2019 depending on Crestwood Midstream’s most recent consolidated total leverage ratio; or

• the Eurodollar Rate, adjusted for certain reserve requirements plus a margin varying from 1.50% to 2.50% at December 31, 2019 depending on Crestwood Midstream’s most recent consolidated total leverage ratio.

Swing line loans bear interest at the Alternate Base Rate as described above. The unused portion of the CMLP Credit Facility is subject to a commitment fee ranging from 0.25% to 0.45% according to its most recent consolidated total leverage ratio. Interest on the Alternate Base Rate loans is payable quarterly, or if the adjusted Eurodollar Rate applies, interest is payable at certain intervals selected by Crestwood Midstream.

At December 31, 2019, Crestwood Midstream had $661.3 million of available capacity under its credit facility considering the most restrictive covenants in its credit agreement. At December 31, 2019 and 2018, Crestwood Midstream’s outstanding standby letters of credit were $31.7 million and $68.0 million. Borrowings under the credit facility accrue interest at prime or Eurodollar based rates plus applicable spreads, which resulted in interest rates between 3.96% and 6.00% at December 31, 2019 and 4.63% and 6.75% at December 31, 2018. The weighted-average interest rates on outstanding borrowings as of December 31, 2019 and 2018 was 4.00% and 4.79%.

In April 2019, Crestwood Niobrara acquired the remaining 50% equity interest in Jackalope and funded approximately $250 million of the total purchase price through borrowings under Crestwood Midstream’s credit facility. Contemporaneously with the acquisition of the remaining interest in Jackalope, Crestwood Midstream entered into the First Amendment to the CMLP Credit Agreement to modify certain defined terms and calculations, among other things, to account for the Jackalope Acquisition. The CMLP Credit Facility contains various covenants and restrictive provisions that limit our ability to, among other things, (i) incur additional debt; (ii) make distributions on or redeem or repurchase units; (iii) make certain investments and acquisitions; (iv) incur or permit certain liens to exist; (v) merge, consolidate or amalgamate with another company; (vi) transfer or dispose of assets; and (vii) incur a change in control at either Crestwood Equity or Crestwood Midstream, including an acquisition of Crestwood Holdings’ ownership of Crestwood Equity’s general partner by any third party, including Crestwood Holdings’ debtors under an event of default of their debt since Crestwood Equity’s non-economic general partner interest is pledged as collateral under that debt.

Crestwood Midstream is required under its credit agreement to maintain a net debt to consolidated EBITDA ratio (as defined in its credit agreement) of not more than 5.50 to 1.0, a consolidated EBITDA to consolidated interest expense ratio (as defined in its credit agreement) of not less than 2.50 to 1.0, and a senior secured leverage ratio (as defined in its credit agreement) of not more than 3.75 to 1.0. At December 31, 2019, the net debt to consolidated EBITDA was approximately 4.13 to 1.0, the

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consolidated EBITDA to consolidated interest expense was approximately 4.47 to 1.0, and the senior secured leverage ratio was 0.98 to 1.0.

If Crestwood Midstream fails to perform its obligations under these and other covenants, the lenders’ credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the CMLP Credit Facility could be declared immediately due and payable. The CMLP Credit Facility also has cross default provisions that apply to any of its other material indebtedness.

Senior Notes

2023 Senior Notes. The 6.25% Senior Notes due 2023 (the 2023 Senior Notes) mature on April 1, 2023, and interest is payable semi-annually in arrears on April 1 and October 1 of each year.

2025 Senior Notes. The 5.75% Senior Notes due 2025 (the 2025 Senior Notes) mature on April 1, 2025, and interest is payable semi-annually in arrears on April 1 and October 1 of each year. The net proceeds from the private offering of approximately $492 million were used to repay amounts previously outstanding under CMLP’s senior notes due in 2020 and 2022 as discussed below.

2027 Senior Notes. In April, 2019, Crestwood Midstream issued $600 million of 5.625% unsecured senior notes due 2027 (the 2027 Senior Notes). The 2027 Senior Notes mature on May 1, 2027, and interest is payable semi-annually in arrears on May 1 and November 1 of each year, beginning November 1, 2019. The net proceeds from this offering of approximately $591.1 million were used to fund the acquisition of the remaining 50% equity interest in Jackalope.

In general, each series of Crestwood Midstream’s senior notes are fully and unconditionally guaranteed, joint and severally, on a senior unsecured basis by Crestwood Midstream’s domestic restricted subsidiaries (other than Crestwood Midstream Finance Corp., which has no assets). The indentures contain customary release provisions, such as (i) disposition of all or substantially all the assets of, or the capital stock of, a guarantor subsidiary to a third person if the disposition complies with the indentures; (ii) designation of a guarantor subsidiary as an unrestricted subsidiary in accordance with its indentures; (iii) legal or covenant defeasance of a series of senior notes, or satisfaction and discharge of the related indenture; and (iv) guarantor subsidiary ceases to guarantee any other indebtedness of Crestwood Midstream or any other guarantor subsidiary, provided it no longer guarantees indebtedness under the CMLP Credit Facility.

The indentures restricts the ability of Crestwood Midstream and its restricted subsidiaries to, among other things, sell assets; redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; create or incur certain liens; enter into agreements that restrict distributions or other payments to Crestwood Midstream from its restricted subsidiaries; consolidate, merge or transfer all or substantially all of their assets; engage in affiliate transactions; create unrestricted subsidiaries; and incur a change in control at either Crestwood Equity or Crestwood Midstream, including an acquisition of Crestwood Holdings’ ownership of Crestwood Equity’s general partner by any third party including Crestwood Holdings’ debtors under an event of default of their debt since Crestwood Equity’s non-economic general partner interest is pledged as collateral under that debt. These restrictions are subject to a number of exceptions and qualifications, and many of these restrictions will terminate when the senior notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Rating Services and no default or event of default (each as defined in the respective indentures) under the indentures has occurred and is continuing.

At December 31, 2019, Crestwood Midstream was in compliance with the debt covenants and restrictions in each of its credit agreements discussed above.

Crestwood Midstream’s Credit Facility and senior notes are secured by the net assets of its guarantor subsidiaries. Accordingly, such assets are only available to the creditors of Crestwood Midstream. Crestwood Equity had restricted net assets of approximately $2,099.3 million as of December 31, 2019.

Repayments. During the year ended December 31, 2017, Crestwood Midstream paid approximately $349.9 million and $457.8 million to purchase, redeem and/or cancel all of the principal amounts previously outstanding under CMLP’s senior notes due in 2020 and 2022, respectively. Crestwood Midstream funded the repayments with a combination of net proceeds from the issuance of the 2025 Senior Notes described above and borrowings under the 2020 Credit Facility. In conjunction with these note repayments, Crestwood Midstream (i) recognized a loss on extinguishment of debt of approximately $37.7 million during the year ended December 31, 2017 (including the write off of approximately $6.8 million of deferred financing costs associated

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with the senior notes due in 2022); and (ii) paid $5.1 million and $1.0 million of accrued interest on CMLP’s senior notes due in 2020 and 2022, respectively, on the date they were tendered.

Other Obligations

Our non-interest bearing obligations due under noncompetition agreements consist of agreements between Crestwood Midstream and sellers of certain companies acquired in 2014 with payments due through 2022 and imputed interest ranging from 5.02% to 6.75%. Non-interest bearing obligations at December 31, 2019 and 2018 consisted of $0.7 million and $1.7 million in total payments due under these agreements, less unamortized discount based on imputed interest of $0.1 million and $0.2 million, respectively.

Maturities

The aggregate maturities of principal amounts on our outstanding long-term debt and other notes payable as of December 31, 2019 for the next five years and in total thereafter are as follows (in millions):

2020	$	0.2
2021	0.2
2022	0.2
2023	1,257.0
2024	—
Thereafter	1,100.0
Total debt	$	2,357.6

Note 10 - Earnings Per Limited Partner Unit

Our net income (loss) attributable to Crestwood Equity Partners is allocated to the subordinated and limited partner unitholders based on their ownership percentage after giving effect to net income attributable to the preferred units. We calculate basic net income per limited partner unit using the two-class method. Diluted net income per limited partner unit is computed using the treasury stock method, which considers the impact to net income or loss attributable to Crestwood Equity Partners and limited partner units from the potential issuance of limited partner units.

We exclude potentially dilutive securities from the determination of diluted earnings per unit (as well as their related income statement impacts) when their impact on net income attributable to Crestwood Equity Partners per limited partner unit is anti-dilutive. The following table summarizes information regarding the weighted-average of common units excluded during the years ended December 31, 2019, 2018 and 2017 (in millions):

	Year Ended December 31,
	2019	2018	2017
Preferred units (1)	7.1	7.1	7.0
Crestwood Niobrara’s preferred units(1)	—	6.5	7.1
Subordinated units(2)	—	0.4	0.4
Stock-based compensation performance units(2)	—	0.4	0.3

(1) See Note 12 for additional information regarding the potential conversion of our preferred units and Crestwood Niobrara’s preferred units to common units.

(2) For a description of our subordinated and stock-based compensation performance units, see Note 12 and Note 13, respectively.

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The table below shows CEQP’s net income (loss) per limited partner unit based on the number of basic and diluted limited partner units outstanding for the year ended December 31, 2019, 2018 and 2017 (in millions, except per unit data):

	Year Ended December 31,
	2019		2018			2017
Common unitholders’ interest in net income (loss)	$	223.6	$	(9.3	)	$	(254.4	)
Net income attributable to subordinated units	1.4		—			—
Diluted net income (loss)	$	225.0	$	(9.3	)	$	(254.4	)
Weighted-average limited partners’ units outstanding - basic	71.8		71.2			69.8
Dilutive effect of Crestwood Niobrara preferred units	4.3		—			—
Dilutive effect of stock-based compensation performance units	0.4		—			—
Dilutive effect of subordinated units	0.4		—			—
Weighted-average limited partners’ units outstanding - diluted	76.9		71.2			69.8
Basic earnings per unit:
Net income (loss) per limited partner unit	$	3.11	$	(0.13	)	$	(3.64	)
Diluted earnings per unit:
Net income (loss) per limited partner unit	$	2.93	$	(0.13	)	$	(3.64	)

Note 11 - Income Taxes

The (provision) benefit for income taxes for the years ended December 31, 2019, 2018, and 2017 consisted of the following (in millions):

	CEQP									CMLP
	Year Ended December 31,									Year Ended December 31,
	2019			2018			2017			2019			2018			2017 (1)
Current:
Federal	$	(0.1	)	$	(0.5	)	$	(1.1	)	$	0.1		$	0.1		$	—
State	(0.2		)	(0.3		)	(0.2		)	(0.2		)	(0.2		)	—
Total current	(0.3		)	(0.8		)	(1.3		)	(0.1		)	(0.1		)	—
Deferred:
Federal	0.1			0.5			2.1			—			—			—
State	(0.1		)	0.2			—			(0.2		)	0.1			—
Total deferred	—			0.7			2.1			(0.2		)	0.1			—
(Provision) benefit for income taxes	$	(0.3	)	$	(0.1	)	$	0.8		$	(0.3	)	$	—		$	—

(1) For the year ended December 31, 2017, our benefit for income taxes was not material to CMLP’s consolidated statement of operations.

The effective rate differs from the statutory rate for the years ended December 31, 2019, 2018 and 2017, primarily due to the partnerships not being treated as a corporation for federal income tax purposes as discussed in Note 2.

Deferred income taxes related to CEQP’s wholly owned subsidiaries, IPCH Acquisition Corp. and Crestwood Gas Services GP LLC, and our Texas Margin tax which reflects the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

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Components of our deferred income taxes at December 31, 2019 and 2018 are as follows (in millions).

	CEQP						CMLP
	December 31,						December 31,
	2019			2018			2019			2018
Total deferred tax asset(1)	$	0.2		$	0.2		$	—		$	—
Total deferred tax liability(1)	(2.8		)	(2.8		)	(0.7		)	(0.6		)
Net deferred tax liability	$	(2.6	)	$	(2.6	)	$	(0.7	)	$	(0.6	)

(1) Relates to the basis difference in the stock of a company.

Uncertain Tax Positions. We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Such tax positions, if any, would be recorded as a tax benefit or expense in the current year. We believe that there were no uncertain tax positions that would impact our results of operations for the years ended December 31, 2019, 2018 and 2017 and that no provision for income tax was required for these consolidated financial statements. However, our conclusions regarding the evaluation of uncertain tax positions are subject to review and may change based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof.

Note 12 – Partners’ Capital

Preferred Units

Subject to certain conditions, the holders of the preferred units will have the right to convert preferred units into (i) common units on a 1-for-10 basis, or (ii) a number of common units determined pursuant to a conversion ratio set forth in Crestwood Equity’s partnership agreement upon the occurrence of certain events, such as a change in control. The preferred units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each preferred units entitled to one vote for each common unit into which such preferred unit is convertible, except that the preferred units are entitled to vote as a separate class on any matter on which all unitholders are entitled to vote that adversely affects the rights, powers, privileges or preferences of the preferred units in relation to CEQP’s other securities outstanding.

In 2018, Crestwood Equity registered 71,257,445 preferred units under a shelf registration statement filed with the SEC under which holders of the preferred units may sell their preferred units. The preferred units representing limited partner interests are listed on the NYSE under the symbol “CEQP-P.”

Common Units

On August 4, 2017, we entered into an equity distribution agreement with certain financial institutions (each, a Manager), under which we may offer and sell from time to time through one or more of the Managers, common units having an aggregate offering price of up to $250 million. Common units sold pursuant to this at-the-market (ATM) equity distribution program are issued under a registration statement that became effective on April 12, 2017. We are required to pay the Managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under our ATM equity distribution program. There were no units issued under our ATM equity distribution program during the years ended December 31, 2019 and 2018. During the year ended December 31, 2017, we issued 633,271 common units under the ATM equity distribution program for net proceeds of approximately $15.2 million and we paid a manager fee of approximately $0.3 million related to the sale of these common units.

Subordinated Units

In conjunction with Crestwood Holdings’ acquisition of Crestwood Equity’s general partner, Crestwood Equity issued 438,789 subordinated units, which are considered limited partnership interests, and have the same rights and obligations as its common units, except that the subordinated units are entitled to receive distributions of available cash for a particular quarter only after each of our common units has received a distribution of at least $1.30 for that quarter. The subordinated units convert to common units after (i) CEQP’s common units have received a cumulative distribution in excess of $5.20 during a consecutive four quarter period; and (ii) its Adjusted Operating Surplus (as defined in the agreement) exceeds the distribution on a fully dilutive basis.

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Distributions

Crestwood Equity

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

• provide for the proper conduct of its business;

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

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

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. The amount of cash CEQP has available for distribution depends primarily upon its cash flow (which consists of the cash distributions it receives in connection with its ownership of Crestwood Midstream).

A summary of CEQP’s limited partner quarterly cash distributions for the years ended December 31, 2019, 2018 and 2017 is presented below:

Record Date	Payment Date	Per Unit Rate		Cash Distributions  (in millions)
2019
February 7, 2019	February 14, 2019	$	0.60	$	43.1
May 8, 2019	May 15, 2019	0.60		43.1
August 7, 2019	August 14, 2019	0.60		43.1
November 7, 2019	November 14, 2019	0.60		43.1
				$	172.4
2018
February 7, 2018	February 14, 2018	$	0.60	$	42.7
May 8, 2018	May 15, 2018	0.60		42.7
August 7, 2018	August 14, 2018	0.60		42.7
November 7, 2018	November 14, 2018	0.60		42.7
				$	170.8
2017
February 7, 2017	February 14, 2017	$	0.60	$	41.8
May 8, 2017	May 15, 2017	0.60		41.8
August 7, 2017	August 14, 2017	0.60		41.8
November 7, 2017	November 14, 2017	0.60		42.2
				$	167.6

On February 14, 2020, we paid a distribution of $0.625 per limited partner unit to unitholders of record on February 7, 2020 with respect to the fourth quarter of 2019.

Preferred Unitholders. The holders of our preferred units are entitled to receive fixed quarterly distributions of $0.2111 per unit. Through the quarters ending September 30, 2017 (the Initial Distribution Period), distributions on the preferred units could be made in additional preferred units, cash, or a combination thereof, at our election. We paid distributions on our preferred units through the issuance of additional preferred units through and for the quarter ended June 30, 2017. The number of units distributed was calculated as the fixed quarterly distribution of $0.2111 per unit divided by the cash purchase price of $9.13 per unit. We accrued the fair value of such distribution at the end of the quarterly period and adjusted the fair value of the distribution on the date the additional preferred units were distributed. Distributions on the preferred units following the Initial Distribution Period will be paid in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units; and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to

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our preferred unitholders. If we fail to pay the full amount payable to our preferred unitholders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the preferred units will increase to $0.2567 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the preferred units have been paid in full in cash. In addition, if we fail to pay in full any Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

During the year ended December 31, 2019 and 2018, we made cash distributions to our preferred unitholders of approximately $60.1 million in both periods. In November 2017, we made a cash distribution to our preferred unitholders of approximately $15.0 million for the quarter ended September 30, 2017. During the year ended December 31, 2017, we issued 4,724,030 preferred units to our preferred unitholders in lieu of paying quarterly cash distributions of $43.1 million. On February 14, 2020, we made a cash distribution of approximately $15.0 million to our preferred unitholders for the quarter ended December 31, 2019.

Crestwood Midstream

In accordance with the partnership agreement, Crestwood Midstream’s general partner may, from time to time, cause Crestwood Midstream to make cash distributions at the sole discretion of the general partner. During the years ended December 31, 2019, 2018 and 2017, Crestwood Midstream made distributions of $235.8 million, $238.4 million and $174.0 million, which represented net amounts due to Crestwood Midstream related to cash advances to CEQP for its general corporate activities.

Non-Controlling Partner

Crestwood Niobrara, our consolidated subsidiary, issued a preferred interest (Series A Preferred Units) to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE) in conjunction with the acquisition of its initial 50% equity interest in Jackalope. In December 2017, Crestwood Niobrara redeemed 100% of the outstanding Series A Preferred Units from GE for an aggregate purchase price of approximately $202.7 million and issued $175 million in new Series A-2 Preferred Units to CN Jackalope Holdings LLC (Jackalope Holdings), which is reflected as interest of non-controlling partner in subsidiary and a component of total partners’ capital on our consolidated balance sheet at December 31, 2018. In April 2019, Crestwood Niobrara issued $235 million in new Series A-3 Preferred Units (collectively with the Series A-2 Preferred Units defined as the Crestwood Niobrara Preferred Units) to Jackalope Holdings in conjunction with Crestwood Niobrara’s acquisition of the remaining 50% equity interest in Jackalope from Williams. In connection with the issuance of the Series A-3 Preferred Units, we entered into a Third Amended and Restated Limited Liability Company Agreement (Crestwood Niobrara Amended Agreement) with Jackalope Holdings, pursuant to which we serve as managing member of Crestwood Niobrara. The Crestwood Niobrara Amended Agreement modified certain provisions under the previous limited liability company agreement related to the conversion and redemption of the Series A-2 Preferred Units, as follows:

• The Crestwood Niobrara Preferred Units are convertible by the preferred interest holder starting on January 1, 2021 into Crestwood Niobrara common units. The preferred interest holder has the option to contribute additional capital to Crestwood Niobrara to increase their common ownership percentage in Crestwood Niobrara to 50% upon the conversion.

• The Crestwood Niobrara Preferred Units are redeemable by the preferred interest holder starting on December 31, 2023 for an amount equal to the Liquidation Preference (as defined in the Crestwood Niobrara Amended Agreement). If redemption is elected by the preferred interest holder, we have the option to elect to give consideration equal to the Liquidation Preference in either (i) unregistered CEQP common units (subject to a Registration Rights Agreement) with a total value of up to $100 million and/or cash; or (ii) proceeds from a full liquidation of Crestwood Niobrara’s assets and unregistered CEQP common units (subject to a Registration Rights Agreement).

• The Crestwood Niobrara Preferred Units are redeemable by us starting on January 1, 2023 for either (i) unregistered CEQP common units (subject to a Registration Rights Agreement) with a total value of up to $100 million and/or cash; or (ii) proceeds from a full liquidation of Crestwood Niobrara’s assets and registered CEQP common units (subject to a Registration Rights Agreement).

As a result of the modification of the conversion and redemption provisions of the Crestwood Niobrara Preferred Units, we continue to consolidate Crestwood Niobrara and have reflected these preferred interests as a non-controlling interest in

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subsidiary apart from partners’ capital (i.e., temporary equity) on our consolidated balance sheet at December 31, 2019. The following table shows the change in our non-controlling interest in subsidiary at December 31, 2019 (in millions):

Balance at April 9, 2019(1)	$	—
Reclassification of Series A-2 Preferred Units	178.8
Issuance of Series A-3 Preferred Units	235.0
Distributions to non-controlling partner	(18.4		)
Net income attributable to non-controlling partner(2)	30.8
Balance at December 31, 2019	$	426.2

(1) For further detail related to our non-controlling interest in subsidiary for the period December 31, 2018 to April 8, 2019, see our consolidated statements of partners’ capital.

(2) We adjust the carrying amount of our non-controlling interest to its redemption value each period through net income attributable to non-controlling partner.

Crestwood Niobrara is required to make quarterly cash distributions on its preferred interest within 30 days after the end of each quarter. During the years ended December 31, 2019, 2018 and 2017, Crestwood Niobrara paid cash distributions of $25.0 million, $9.9 million and $15.2 million to its preferred interest owners. In January 2020, Crestwood Niobrara paid a cash distribution of $9.2 million to Jackalope Holdings for the quarter ended December 31, 2019.

Note 13 - Equity Plans

Long-term incentive awards are granted under the Crestwood Equity Partners LP Long Term Incentive Plan (Crestwood LTIP) in order to align the economic interests of key employees and directors with those of CEQP’s common unitholders and to provide an incentive for continuous employment. Long-term incentive compensation consist of grants of restricted, phantom and performance units which vest based upon continued service.

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The following table summarizes information regarding restricted, phantom and performance unit activity during the years ended December 31, 2019, 2018 and 2017.

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2017	1,292,330		$	24.67
Granted - restricted units	919,411		$	25.69
Granted - phantom units	15,849		$	25.02
Granted - performance units	405,620		$	30.21
Vested - restricted units	(607,115	)	$	28.00
Vested - performance units	(31,106	)	$	30.27
Forfeited - restricted units	(140,137	)	$	23.73
Forfeited - performance units	(24,756	)	$	30.45
Unvested - December 31, 2017	1,830,096		$	25.21
Granted - restricted units	1,144,017		$	25.80
Granted - phantom units	7,750		$	26.10
Granted - performance units	901		$	25.60
Vested - restricted units	(617,807	)	$	23.73
Vested - phantom units	(105,809	)	$	49.45
Vested - performance units	(11,772	)	$	28.87
Forfeited - restricted units	(53,530	)	$	23.36
Forfeited - phantom units	(6	)	$	49.45
Forfeited - performance units	(5,870	)	$	30.45
Unvested - December 31, 2018	2,187,970		$	24.78
Granted - restricted units	988,096		$	31.48
Granted - phantom units	7,164		$	29.03
Granted - performance units	238,263		$	34.21
Vested - restricted units	(985,751	)	$	23.39
Vested - performance units	(32,246	)	$	34.21
Forfeited - restricted units	(47,547	)	$	27.85
Unvested - December 31, 2019	2,355,949		$	28.94

As of December 31, 2019 and 2018, we had total unamortized compensation expense of approximately $34.6 million and $28.0 million related to restricted, phantom, and performance units, which will be amortized during the next three years (or sooner in certain cases, which generally represents the original vesting period of these instruments), except for grants to non-employee directors of our general partner, which vest over one year.  We recognized compensation expense of approximately $45.1 million, $24.3 million and $22.4 million under the Crestwood LTIP during the years ended December 31, 2019, 2018 and 2017, which is included in general and administrative expenses on our consolidated statements of operations.  During the year ended December 31, 2019, compensation expense includes approximately $4.6 million related to equity awards under the Crestwood LTIP that was included in accrued expenses and other liabilities on our consolidated balance sheet. As of February 10, 2020, we had 2,593,885 units available for issuance under the Crestwood LTIP.

Restricted Units. Under the Crestwood LTIP, participants who have been granted restricted units may elect to have us withhold common units to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-vested common units. Any such common units withheld are returned to the Crestwood LTIP on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When we withhold these common units, we are required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. During the years ended December 31, 2019, 2018, and 2017, we withheld 336,548, 221,576 and 206,600 common units to satisfy employee tax withholding obligations.

Phantom Units. The Crestwood LTIP permits grants of phantom units that entitle the holder thereof to receive upon vesting one CEQP common unit granted pursuant to the Crestwood LTIP and a phantom unit award agreement (the Crestwood Equity

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Phantom Unit Agreement). The Crestwood Equity Phantom Unit Agreement provides for vesting to occur at the end of three years following the grant date or, if earlier, upon the named executive officer’s termination without cause or due to death or disability or the named executive officer’s resignation for employee cause (each, as defined in the Crestwood Equity Phantom Unit Agreement). In addition, the Crestwood Equity Phantom Unit Agreement provides for distribution equivalent rights with respect to each phantom unit which are paid in additional phantom units and settled in common units upon vesting of the underlying phantom units.

Performance Units. The Crestwood LTIP permits grants of performance units that are designed to provide an incentive for continuous employment to certain key employees. Performance units vest over a three-year performance period and the number of units issued are based on a performance multiplier ranging between 50% and 200%, determined based on the actual performance in the third year of the performance period compared to pre-established performance goals. The performance goals are based on achieving a specified level of distributable cash flow per unit, Adjusted EBITDA, return on capital invested, and three-year relative total shareholder return. The vesting of performance units is subject to the attainment of certain performance and market goals over a three-year period and entitle a participant to receive common units of Crestwood Equity without payment of an exercise price upon vesting.

Employee Unit Purchase Plan

In August 2018, the board of directors of our general partner approved 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, not to exceed $25,000 for any calendar year. Under the plan, we anticipate purchasing our common units on the open market for the benefit of participating employees based on their payroll deductions. In addition, we may match up to 10% of participating employees’ payroll deductions to purchase additional Crestwood common units for participating employees. The board of directors of our general partner authorized 1,500,000 common units (subject to adjustment as provided in the employee unit purchase plan) to be available for purchase. During the year ended December 31, 2019, 6,341 common units were purchased under the plan. There were no common units purchased under the employee unit purchase plan in 2018.

Note 14 - Employee Benefit Plan

A 401(k) plan is available to all of our employees after meeting certain requirements. The plan permits employees to make contributions up to 90% of their salary, up to statutory limits, which was $19,000 in 2019, $18,500 in 2018 and $18,000 in 2017. We match 100% of participants basic contribution up to 6% of eligible compensation. Employees may participate in the plans immediately and certain employees are not eligible for matching contributions until after a 90-day waiting period. Aggregate matching contributions made by us were $4.7 million, $4.6 million and $4.0 million during the years ended December 31, 2019, 2018 and 2017.

Note 15 – Commitments and Contingencies

Legal Proceedings

Linde Lawsuit. On December 23, 2019, Linde Engineering North America Inc. (Linde) filed a lawsuit in Harris County, Texas alleging that Arrow Field Services, LLC, our consolidated subsidiary, and Crestwood Midstream breached a contract entered into in March 2018 under which Linde was to provide engineering, procurement and construction services to us related to the completion of the construction of the Bear Den II cryogenic processing plant. Linde claims damages of $55 million in unpaid invoices and other damages. This matter is not an insurable event based on our insurance policies and, we are unable to predict the outcome for this matter.

General. We are periodically involved in litigation proceedings. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, then we accrue the estimated amount. The results of litigation proceedings cannot be predicted with certainty. We could incur judgments, enter into settlements or revise our expectations regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations or cash flows in the period in which the amounts are paid and/or accrued. As of December 31, 2019 and 2018, both CEQP and CMLP had approximately $10.7 million and $0.1 million accrued for outstanding legal matters. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures for which we can estimate will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn

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new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.

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

Regulatory Compliance

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

Environmental Compliance

Our operations are subject to stringent and complex laws and regulations pertaining to worker health, safety, and the environment. We are subject to laws and regulations at the federal, state, regional and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures.

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

In August 2015, we received a notice of violation from the Three Affiliated Tribes’ Environmental Division related to our 2014 produced water releases on the Fort Berthold Indian Reservation. The notice of violation imposes fines and requests reimbursements exceeding $1.1 million; however, the notice of violation was stayed on September 15, 2015. Our discussions regarding the notice of violation continue with the Three Affiliated Tribes.

During September 2019, we experienced two produced water releases totaling approximately 5,000 barrels on our Arrow system located on the Fort Berthold Indian Reservation in North Dakota. We immediately notified the National Response Center, the State of North Dakota, the Three Affiliated Tribes, affected landowners and numerous other regulatory authorities. We are substantially complete with the remediation efforts and continue to monitor the impact of both spills.

In response to the water releases on our Arrow system, we removed approximately 30 miles of water gathering pipeline from service and incurred a $4.3 million impairment charge during the three months ended December 31, 2019 related to idling those facilities. In addition, we are currently in the process of replacing approximately 12 miles of water gathering pipeline with pipeline composed of higher capacity material that is more suitable to the environment and climate conditions in the Bakken, which will increase water gathering capacity on the Arrow system and further our commitment to sustainability and environmental stewardship in the areas where we live and operate.

We will continue our remediation efforts to ensure the impacted lands are restored to their prior state. We believe these releases are insurable events under our policies, and we have notified our carriers of these events. We have not recorded an insurance receivable as of December 31, 2019.

At December 31, 2019 and 2018, our accrual of approximately $6.7 million and $1.8 million was based on our undiscounted estimate of amounts we will spend on compliance with environmental and other regulations, and any associated fines or penalties. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures could range from approximately $6.7 million to $11.1 million at December 31, 2019.

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Self-Insurance

We utilize third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims and general, product, vehicle and environmental liability. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Our self insurance reserves could be affected if future claim developments differ from the historical trends. We believe changes in health care costs, trends in health care claims of our employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. We continually monitor changes in employee demographics, incident and claim type and evaluate our insurance accruals and adjust our accruals based on our evaluation of these qualitative data points. We are liable for the development of claims for our disposed retail propane operations, provided they were reported prior to August 1, 2012. The following table summarizes CEQP’s and CMLP’s self-insurance reserves at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Self-insurance reserves(1)	$	9.7	$	11.3	$	8.3	$	9.6

(1) At December 31, 2019, CEQP and CMLP classified approximately $6.2 million and $5.2 million, respectively of these reserves as other long-term liabilities on their consolidated balance sheets.

Leases

The following table summarizes the balance sheet information related to our operating and finance leases at December 31, 2019 (in millions):

Operating Leases
Operating lease right-of-use assets, net	$	53.8
Accrued expenses and other liabilities	$	18.1
Other long-term liabilities	41.5
Total operating lease liabilities	$	59.6
Finance Leases
Property, plant and equipment	$	14.9
Less: accumulated depreciation	5.4
Property, plant and equipment, net	$	9.5
Accrued expenses and other liabilities	$	3.2
Other long-term liabilities	5.2
Total finance lease liabilities	$	8.4

The following table presents the weighted-average remaining lease term and the weighted-average discount rate associated with our operating and finance leases as of December 31, 2019:

Weighted-average remaining lease term (in years):
Operating leases(1)	4.4
Finance leases(2)	2.6
Weighted-average discount rate:
Operating leases(3)	5.9	%
Finance leases(3)	7.3	%

(1) Remaining terms vary from one year to 20 years.

(2) Remaining terms vary from one year to four years.

(3) We utilized discount rates ranging from 3.5% to 8.3% to estimate the discounted cash flows used in estimating our right-of-use assets and lease liabilities as of December 31, 2019, which were primarily based on our credit-adjusted collateralized incremental borrowing rate.

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The estimation of our right-of-use assets and lease liabilities requires us to make significant assumptions and judgments about the terms of the leases, variable payments, and discount rates. Our operating leases have renewal options to extend the leases from one year to 10 years at the end of each lease term, or terminate the leases at our sole discretion. In addition, our finance leases have options to purchase the lease property by the end of the lease term. We make significant assumptions on the likelihood on whether we will renew our leases or purchase the property at the end of the lease terms in determining the discounted cash flows to measure our right-of-use assets and lease liabilities. The estimation of variable lease payments in determining discounted cash flows, including those with usage-based costs, also requires us to make significant assumptions on the timing and nature of the variability of those payments based on the lease terms.

We recognize operating lease expense and amortize our right-of-use assets for our finance leases on a straight-line basis over the term of the respective leases. We have applied the practical expedient of not separating the lease and non-lease components for our leases where the predominant consideration paid related to the underlying operating and finance lease contracts relate to the lease component. The following table presents the costs and sublease income associated with our operating and finance leases for the year ended December 31, 2019 (in millions):

Operating leases:
Operating lease expense(1)(2)	$	28.3
Sublease income(3)	(1.0		)
Total operating lease expense, net	$	27.3
Finance leases:
Amortization of right-of-use assets(4)	$	3.6
Interest on lease liabilities(5)	0.7
Total finance lease expense	$	4.3

(1) Approximately $17.5 million is included in costs of product/services sold and $10.8 million is included in operations and maintenance expense on our consolidated statements of operations for the year ended December 31, 2019.

(2) Includes short-term and variable lease costs of approximately $3.7 million for the year ended December 31, 2019.

(3) Included in marketing, supply and logistics service revenues on our consolidated statements of operations.

(4) Included in depreciation, amortization and accretion expense on our consolidated statements of operations.

(5) Included in interest and debt expense, net on our consolidated statements of operations.

The following table presents supplemental cash flow information for our operating and finance leases for the year ended December 31, 2019 (in millions):

Cash paid for lease liabilities:
Operating cash flows from operating leases	$	22.9
Operating cash flows from finance leases	$	0.7
Financing cash flows from finance leases	$	3.5
Right-of-use assets obtained in exchange for lease obligations:
Operating leases(1)	$	4.2
Finance leases	$	1.8

(1) Includes approximately $2.9 million of operating leases obtained from the Jackalope Acquisition, which is further discussed in Note 3.

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The following table presents the future minimum lease liabilities under Topic 842 for our leases as of December 31, 2019 for the next five years and in total thereafter (in millions):

Year Ending December 31,	Operating Leases		Finance Leases		Total
2020	$	20.9	$	3.6	$	24.5
2021	16.3		3.6		19.9
2022	11.1		1.9		13.0
2023	6.7		0.1		6.8
2024	6.0		—		6.0
Thereafter	7.5		—		7.5
Total lease payments	68.5		9.2		77.7
Less: Interest	8.9		0.8		9.7
Present value of lease liabilities	$	59.6	$	8.4	$	68.0

Purchase Commitments

We periodically enter into agreements with suppliers to purchase fixed quantities of NGLs, distillates, crude oil and natural gas at fixed prices. At December 31, 2019, the total of these firm purchase commitments was $792.4 million, of which approximately $712.3 million will occur over the course of the next twelve months. We also enter into non-binding agreements with suppliers to purchase quantities of NGLs, distillates and natural gas at variable prices at future dates at the then prevailing market prices.

We have entered into certain purchase commitments primarily related to our gathering and processing segment. At December 31, 2019, our total purchase commitments were approximately $126.6 million, which primarily relate to future growth projects and maintenance obligations in our gathering and processing segment. The purchases associated with these commitments are expected to occur over the next twelve months.

Guarantees and Indemnifications

We are involved in various joint ventures that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. For a further description of our guarantees associated with our joint ventures, see Note 6.

Our potential exposure under guarantee and indemnification arrangements can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim, specificity as to duration, and the particular transaction. As of December 31, 2019, we have no amounts accrued for these guarantees.

Note 16 – Related Party Transactions

Crestwood Holdings indirectly owns both CEQP’s and CMLP’s general partner. The affiliates of Crestwood Holdings and its owners are considered CEQP’s and CMLP’s related parties. We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including gas gathering and processing services under long-term contracts, product purchases, marketing and various operating agreements. We also enter into transactions with our affiliates related to services provided on our expansion projects. During the years ended December 31, 2019 and 2018, we paid approximately $9.9 million and $7.2 million of capital expenditures to Applied Consultants, Inc., an affiliate of Crestwood Holdings. Below is a discussion of certain of our related party agreements.

Shared Services. CMLP shares common management, general and administrative and overhead costs with CEQP. CEQP grants long-term incentive awards under the Crestwood LTIP as discussed in Note 13 and, as such, CEQP allocates a portion of its unit-based compensation costs to CMLP.

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Stagecoach Gas Management Agreement. In May 2016, Crestwood Midstream Operations, LLC (Crestwood Midstream Operations), our wholly-owned subsidiary and Stagecoach Gas entered into a management agreement under which Crestwood Midstream Operations provides the management and operating services required by Stagecoach Gas’ facilities. The initial term of the agreement will expire in May 2021, and is automatically extended for three-year periods unless otherwise terminated pursuant to the terms of the agreement. Reimbursements received from Stagecoach Gas under this agreement are reflected as operations and maintenance expenses at CEQP and CMLP in the table below.

Tres Palacios Operating Agreement. A consolidated subsidiary of Crestwood Midstream entered into an operating agreement with Tres Palacios, pursuant to which we assumed the responsibility of operating and maintaining the facilities as well as certain administrative and other general services identified in the agreement. Under the operating agreement, Tres Palacios reimburses us for all costs incurred on its behalf. These reimbursements are reflected as operations and maintenance expenses at CEQP and CMLP in the table below.

Crestwood Permian Operating Agreement. In October 2016, Crestwood Midstream Operations entered into an operating agreement with Crestwood Permian, pursuant to which we provide operating services for Crestwood Permian’s facilities, as well as certain administrative and other general services identified in the agreement. Under this operating agreement, Crestwood Permian reimburses us for all costs incurred on its behalf. These reimbursements are reflected as operations and maintenance expenses at CEQP and CMLP in the table below.

Jackalope Gas Gathering Services, L.L.C. On April 9, 2019, Crestwood Niobrara, our consolidated subsidiary, acquired Williams’ 50% equity interest in Jackalope, and as a result, Crestwood Niobrara controls and owns 100% of the equity interests in Jackalope. Prior to the acquisition of the remaining interest in Jackalope, a consolidated subsidiary of Crestwood Midstream entered into a marketing services agreement with Jackalope under which we provided marketing services for Jackalope as well as certain administrative and other general services identified in the agreement. Under this marketing services agreement, Jackalope reimbursed us for all costs incurred on its behalf. These reimbursements are reflected as operations and maintenance expenses at CEQP and CMLP in the table below.

The following table shows transactions with our affiliates which are reflected in our consolidated statements of operations for the years December 31, 2019, 2018 and 2017 (in millions):

	Year Ended December 31,
	2019			2018			2017
Revenues at CEQP and CMLP	$	2.9		$	1.0		$	1.8
Costs of product/services sold at CEQP and CMLP(1)	$	45.4		$	134.7		$	15.3
Operations and maintenance expenses at CEQP and CMLP(2)	$	25.9		$	28.7		$	22.3
General and administrative expenses charged by CEQP to CMLP, net(3)	$	41.4		$	20.7		$	19.4
General and administrative expenses at CEQP charged from Crestwood Holdings, net(4)	$	(0.6	)	$	(2.7	)	$	(1.7	)

(1) Includes (i) $19.0 million and $56.1 million during the years ended December 31, 2019 and 2018 related to purchases of NGLs from a subsidiary of Crestwood Permian; (ii) $23.9 million and $78.6 million during the years ended December 31, 2019 and 2018 related to an agency marketing agreement with Ascent Resources - Utica, LLC (Ascent); (iii) $0.2 million during the year ended December 31, 2019 related to an agreement with Blue Racer Midstream, LLC (Blue Racer); (iv) $2.3 million during the year ended December 31, 2019 related to purchases of natural gas from a subsidiary of Stagecoach Gas; and (v) $15.3 million during the year ended December 31, 2017 related to natural gas purchases from Sabine Oil and Gas (Sabine). Ascent, Blue Racer and Sabine are affiliates of Crestwood Holdings for the respective periods presented.

(2) We have operating agreements with certain of our unconsolidated affiliates pursuant to which we charge them operations and maintenance expenses in accordance with their respective agreements, and these charges are reflected as a reduction of operations and maintenance expenses in our consolidated statements of operations. During the year ended December 31, 2019, we charged $7.5 million to Stagecoach Gas, $4.4 million to Tres Palacios, $13.5 million to Crestwood Permian and $0.5 million to Jackalope. During the year ended December 31, 2018, we charged $7.9 million to Stagecoach Gas, $3.8 million to Tres Palacios, $15.9 million to Crestwood Permian and $1.1 million to Jackalope. During the year ended December 31, 2017, we charged $8.4 million to Stagecoach Gas, $3.5 million to Tres Palacios, $10.0 million to Crestwood Permian and $0.4 million to Jackalope.

(3) Includes $45.1 million, $24.3 million and $22.4 million of net unit-based compensation charges allocated from CEQP to CMLP for the years ended December 31, 2019, 2018 and 2017. In addition, includes $3.7 million, $3.6 million and $3.0 million of CMLP’s general and administrative costs allocated to CEQP during the years ended December 31, 2019, 2018 and 2017.

(4) Includes $1.9 million, $4.2 million and $3.1 million of unit-based compensation charges allocated from Crestwood Holdings to CEQP and CMLP during the years ended December 31, 2019, 2018 and 2017.

157

The following table shows accounts receivable and accounts payable from our affiliates as of December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Accounts receivable at CEQP and CMLP	$	7.3	$	4.1
Accounts payable at CEQP	$	15.6	$	16.1
Accounts payable at CMLP	$	13.1	$	13.6

Note 17 – Segments

Financial Information

We have three operating and reportable segments: (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) marketing, supply and logistics operations. Our corporate operations include all general and administrative expenses that are not allocated to our reportable segments. For a further description of our operating and reporting segments, see Note 1. We assess the performance of our operating segments based on EBITDA, which is defined as income before income taxes, plus debt-related costs (net interest and debt expense and loss on modification/extinguishment of debt) and depreciation, amortization and accretion expense.

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

	Year Ended December 31,
	2019		2018		2017
Net income (loss)	$	319.9	$	67.0	$	(166.6	)
Add:
Interest and debt expense, net	115.4		99.2		99.4
Loss on modification/extinguishment of debt	—		0.9		37.7
Provision (benefit) for income taxes	0.3		0.1		(0.8		)
Depreciation, amortization and accretion	195.8		168.7		191.7
EBITDA	$	631.4	$	335.9	$	161.4

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

	Year Ended December 31,
	2019		2018		2017
Net income (loss)	$	310.6	$	58.6	$	(175.5	)
Add:
Interest and debt expense, net	115.4		99.2		99.4
Loss on modification/extinguishment of debt	—		0.9		37.7
Provision for income taxes	0.3		—		—
Depreciation, amortization and accretion	209.9		181.4		202.7
EBITDA	$	636.2	$	340.1	$	164.3

The following tables summarize CEQP’s and CMLP’s reportable segment data for the years ended December 31, 2019, 2018 and 2017 (in millions). Intersegment revenues included in the following tables are accounted for as arms-length transactions that apply our revenue recognition policy described in Note 2. Included in earnings from unconsolidated affiliates below was approximately $42.1 million, $42.3 million and $32.5 million of our proportionate share of interest expense, depreciation and amortization expense and gains (losses) on long-lived assets, net recorded by our equity investments for the years ended December 31, 2019, 2018 and 2017, respectively.

158

Crestwood Equity

	Year Ended December 31, 2019
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	835.8		$	20.4	$	2,325.7		$	—		$	3,181.9
Intersegment revenues	175.0			14.2		(189.2		)	—			—
Costs of product/services sold	526.1			0.2		2,018.6			—			2,544.9
Operations and maintenance expense	98.7			4.0		36.1			—			138.8
General and administrative expense	—			—		—			103.4			103.4
Gain (loss) on long-lived assets, net	(6.2		)	—		(0.2		)	0.2			(6.2		)
Gain on acquisition	209.4			—		—			—			209.4
Earnings (loss) from unconsolidated affiliates, net	(2.1		)	34.9		—			—			32.8
Other income, net	—			—		—			0.6			0.6
EBITDA	$	587.1		$	65.3	$	81.6		$	(102.6	)	$	631.4
Goodwill	$	126.2		$	—	$	92.7		$	—		$	218.9
Total assets	$	3,715.3		$	980.2	$	624.7		$	29.1		$	5,349.3
Purchases of property, plant and equipment	$	447.7		$	0.1	$	5.8		$	1.9		$	455.5

	Year Ended December 31, 2018
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	946.7		$	17.1	$	2,690.3		$	—		$	3,654.1
Intersegment revenues	192.4			10.5		(202.9		)	—			—
Costs of product/services sold	767.0			0.2		2,362.2			—			3,129.4
Operations and maintenance expense	71.7			3.3		50.8			—			125.8
General and administrative expense	—			—		—			88.1			88.1
Gain (loss) on long-lived assets, net	(3.0		)	—		(27.3		)	1.7			(28.6		)
Earnings from unconsolidated affiliates, net	22.5			30.8		—			—			53.3
Other income, net	—			—		—			0.4			0.4
EBITDA	$	319.9		$	54.9	$	47.1		$	(86.0	)	$	335.9
Goodwill	$	45.9		$	—	$	92.7		$	—		$	138.6
Total assets	$	2,633.4		$	1,004.4	$	612.5		$	44.2		$	4,294.5
Purchases of property, plant and equipment	$	294.7		$	0.6	$	5.6		$	4.6		$	305.5

159

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			96.5			96.5
Loss on long-lived assets	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			0.5			1.3
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(99.0	)	$	161.4
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

Crestwood Midstream

	Year Ended December 31, 2019
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	835.8		$	20.4	$	2,325.7		$	—		$	3,181.9
Intersegment revenues	175.0			14.2		(189.2		)	—			—
Costs of product/services sold	526.1			0.2		2,018.6			—			2,544.9
Operations and maintenance expense	98.7			4.0		36.1			—			138.8
General and administrative expense	—			—		—			98.2			98.2
Gain (loss) on long-lived assets, net	(6.2		)	—		(0.2		)	0.2			(6.2		)
Gain on acquisition	209.4			—		—			—			209.4
Earnings (loss) from unconsolidated affiliates, net	(2.1		)	34.9		—			—			32.8
Other income, net	—			—		—			0.2			0.2
EBITDA	$	587.1		$	65.3	$	81.6		$	(97.8	)	$	636.2
Goodwill	$	126.2		$	—	$	92.7		$	—		$	218.9
Total assets	$	3,874.7		$	980.2	$	624.7		$	24.4		$	5,504.0
Purchases of property, plant and equipment	$	447.7		$	0.1	$	5.8		$	1.9		$	455.5

160

	Year Ended December 31, 2018
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	946.7		$	17.1	$	2,690.3		$	—		$	3,654.1
Intersegment revenues	192.4			10.5		(202.9		)	—			—
Costs of product/services sold	767.0			0.2		2,362.2			—			3,129.4
Operations and maintenance expense	71.7			3.3		50.8			—			125.8
General and administrative expense	—			—		—			83.5			83.5
Gain (loss) on long-lived assets, net	(3.0		)	—		(27.3		)	1.7			(28.6		)
Earnings from unconsolidated affiliates, net	22.5			30.8		—			—			53.3
EBITDA	$	319.9		$	54.9	$	47.1		$	(81.8	)	$	340.1
Goodwill	$	45.9		$	—	$	92.7		$	—		$	138.6
Total assets	$	2,807.1		$	1,004.4	$	612.5		$	38.0		$	4,462.0
Purchases of property, plant and equipment	$	294.7		$	0.6	$	5.6		$	4.6		$	305.5

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			93.1			93.1
Loss on long-lived assets, net	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			—			0.8
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(96.1	)	$	164.3
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

Major Customers

For the year ended December 31, 2019, we had revenues from British Petroleum and its affiliates of approximately $333.9 million, reflected primarily in our Marketing, Supply and Logistics segment, which exceeded 10% of the total consolidated revenues at CEQP and CMLP. No customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2018 or 2017 at CEQP or CMLP.

Note 18 - Revenues

Contract Assets and Contract Liabilities

Our contract assets and contract liabilities are reported in a net position on a contract-by-contract basis at the end of each reporting period. Our receivables related to our revenue contracts accounted for under Topic 606 totaled $225.0 million and $209.7 million for both CEQP and CMLP at December 31, 2019 and 2018, and are included in accounts receivable on our consolidated balance sheets. Our contract assets are included in other non-current assets on our consolidated balance sheets. Our contract liabilities primarily consist of current and non-current deferred revenues. On our consolidated balance sheets, our current deferred revenues are included in accrued expenses and other liabilities and our non-current deferred revenues are included in other long-term liabilities. The majority of revenues associated with our deferred revenues is expected to be recognized as the performance obligations under the related contracts are satisfied over the next 17 years.

161

The following table provides a summary of the opening and closing balances of our contract assets and contract liabilities (in millions):

	December 31,
	2019		2018
Contract assets (non-current)	$	1.2	$	1.0
Contract liabilities (current)(1)	$	8.8	$	12.0
Contract liabilities (non-current)(1)	$	144.7	$	65.4

(1) During the year ended December 31, 2019, we recognized revenues of approximately $13.3 million that were previously included in contract liabilities (current) at December 31, 2018. The remaining change in our contract liabilities during the year ended December 31, 2019 partially related to approximately $21.5 million of deferred revenues recorded in the purchase price allocation for the Jackalope Acquisition described in more detail in Note 3, and the remainder related primarily to capital reimbursements associated with our revenue contracts and revenue deferrals associated with our contracts with increasing (decreasing) rates.

The following table summarizes the transaction price allocated to our remaining performance obligations under certain contracts that have not been recognized as of December 31, 2019 (in millions):

2020	$	99.4
2021	86.2
2022	79.3
2023	7.4
2024	3.3
Total	$	275.6

Our remaining performance obligations presented in the table above exclude estimates of variable rate escalation clauses in our contracts with customers, and is generally limited to fixed-fee and percentage-of-proceeds service contracts which have fixed pricing and minimum volume terms and conditions. Our remaining performance obligations generally exclude, based on the following practical expedients that we elected to apply, disclosures for (i) variable consideration allocated to a wholly-unsatisfied promise to transfer a distinct service that forms part of the identified single performance obligation; (ii) unsatisfied performance obligations where the contract term is one year or less; and (iii) contracts for which we recognize revenues as amounts are invoiced.

162

Disaggregation of Revenues

The following tables summarize our revenues from contracts with customers disaggregated by type of product/service sold and by commodity type for each of our segments for the years ended December 31, 2019 and 2018 (in millions). We believe this summary best depicts how the nature, amount, timing and uncertainty of our revenues and cash flows are affected by economic factors.

	Year Ended December 31, 2019
	Gathering and Processing		Storage and Transportation		Marketing, Supply and Logistics		Intersegment Elimination			Total
Revenues:
Topic 606 revenues
Gathering
Natural gas	$	163.2	$	—	$	—	$	—		$	163.2
Crude oil	75.0		—		—		—			75.0
Water	79.6		—		—		—			79.6
Processing
Natural gas	28.9		—		—		—			28.9
Compression
Natural gas	24.9		—		—		—			24.9
Storage
Crude oil	1.9		5.4		—		(2.3		)	5.0
NGLs	—		—		6.3		—			6.3
Pipeline
Crude oil	—		7.9		—		(2.7		)	5.2
Transportation
Crude oil	7.0		—		5.8		(0.1		)	12.7
NGLs	—		—		11.7		—			11.7
Water	—		—		0.2		—			0.2
Rail Loading
Crude oil	—		16.7		—		(5.7		)	11.0
Product Sales
Natural gas	56.8		—		72.3		(33.4		)	95.7
Crude oil	532.1		—		1,315.6		(121.1		)	1,726.6
NGLs	41.4		—		659.3		(20.0		)	680.7
Other	—		4.6		1.2		(3.9		)	1.9
Total Topic 606 revenues	1,010.8		34.6		2,072.4		(189.2		)	2,928.6
Non-Topic 606 revenues(1)	—		—		253.3		—			253.3
Total revenues	$	1,010.8	$	34.6	$	2,325.7	$	(189.2	)	$	3,181.9

(1) Represents revenues primarily related to our commodity-based derivatives. See Note 7 for additional information related to our price risk management activities.

163

	Year Ended December 31, 2018
	Gathering and Processing		Storage and Transportation		Marketing, Supply and Logistics		Intersegment Elimination			Total
Revenues:
Topic 606 revenues
Gathering
Natural gas	$	134.9	$	—	$	—	$	—		$	134.9
Crude oil	38.8		—		—		—			38.8
Water	58.0		—		—		—			58.0
Processing
Natural gas	10.7		—		—		—			10.7
NGLs	—		—		6.1		—			6.1
Compression
Natural gas	29.1		—		—		—			29.1
Storage
Crude oil	1.8		4.2		—		(1.5		)	4.5
NGLs	—		—		8.6		—			8.6
Pipeline
Crude oil	—		7.1		—		(2.3		)	4.8
Transportation
Crude oil	2.9		—		5.9		—			8.8
NGLs	—		—		26.9		—			26.9
Water	—		—		0.3		—			0.3
Rail Loading
Crude oil	—		14.3		0.2		(5.2		)	9.3
NGLs	—		—		3.1		—			3.1
Product Sales
Natural gas	55.8		—		70.9		(16.6		)	110.1
Crude oil	722.9		—		978.0		(151.3		)	1,549.6
NGLs	84.2		—		1,247.0		(24.5		)	1,306.7
Other	—		2.0		—		(1.5		)	0.5
Total Topic 606 revenues	1,139.1		27.6		2,347.0		(202.9		)	3,310.8
Non-Topic 606 revenues(1)	—		—		343.3		—			343.3
Total revenues	$	1,139.1	$	27.6	$	2,690.3	$	(202.9	)	$	3,654.1

(1) Represents revenues related to our commodity-based derivatives. See Note 7 for additional information related to our price risk management activities.

Note 19 – Crestwood Midstream Condensed Consolidating Financial Information

Crestwood Midstream is a holding company (Parent) and owns no operating assets and has no significant operations independent of its subsidiaries. Obligations under Crestwood Midstream’s senior notes and its credit facility are jointly and severally guaranteed by substantially all of its subsidiaries, except for Crestwood Infrastructure, Crestwood Niobrara, Crestwood Northeast, PRBIC and Tres Holdings and their respective subsidiaries (collectively, Non-Guarantor Subsidiaries). Crestwood Midstream Finance Corp., the co-issuer of the senior notes, is Crestwood Midstream’s 100% owned subsidiary and has no material assets, operations, revenues or cash flows other than those related to its service as co-issuer of the Crestwood Midstream senior notes.

The tables below present condensed consolidating financial statements for Crestwood Midstream as Parent on a stand-alone, unconsolidated basis, and Crestwood Midstream’s combined guarantor and combined non-guarantor subsidiaries as of and for the years ended December 31, 2019, 2018 and 2017. The financial information may not necessarily be indicative of the results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

164

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2019
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	1.8	$	—	$	23.6	$	—		$	25.4
Accounts receivable	—		229.1		12.8		—			241.9
Inventory	—		53.7		—		—			53.7
Other current assets	—		54.6		0.2		—			54.8
Total current assets	1.8		337.4		36.6		—			375.8
Property, plant and equipment, net	—		2,331.3		736.2		—			3,067.5
Goodwill and intangible assets, net	—		650.7		373.4		—			1,024.1
Operating lease right-of-use assets, net	—		51.0		2.8		—			53.8
Investments in consolidated affiliates	4,451.6		—		—		(4,451.6		)	—
Investments in unconsolidated affiliates	—		—		980.4		—			980.4
Other non-current assets	—		1.9		0.5		—			2.4
Total assets	$	4,453.4	$	3,372.3	$	2,129.9	$	(4,451.6	)	$	5,504.0
Liabilities and capital
Current liabilities:
Accounts payable	$	—	$	175.9	$	10.7	$	—		$	186.6
Other current liabilities	25.8		123.9		17.6		—			167.3
Total current liabilities	25.8		299.8		28.3		—			353.9
Long-term liabilities:
Long-term debt, less current portion	2,328.3		—		—		—			2,328.3
Other long-term liabilities	—		174.8		120.8		—			295.6
Deferred income taxes	—		0.7		—		—			0.7
Total liabilities	2,354.1		475.3		149.1		—			2,978.5
Interest of non-controlling partner in subsidiary	—		—		426.2		—			426.2
Partners’ capital	2,099.3		2,897.0		1,554.6		(4,451.6		)	2,099.3
Total liabilities and capital	$	4,453.4	$	3,372.3	$	2,129.9	$	(4,451.6	)	$	5,504.0

165

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2018
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	0.2	$	—	$	—	$	—		$	0.2
Restricted cash	16.3		—		—		—			16.3
Accounts receivable	—		246.3		19.9		(16.3		)	249.9
Inventory	—		64.6		—		—			64.6
Other current assets	—		46.0		—		—			46.0
Total current assets	16.5		356.9		19.9		(16.3		)	377.0
Property, plant and equipment, net	—		2,202.3		—		—			2,202.3
Goodwill and intangible assets, net	—		692.4		—		—			692.4
Investments in consolidated affiliates	3,800.4		—		—		(3,800.4		)	—
Investments in unconsolidated affiliates	—		—		1,188.2		—			1,188.2
Other non-current assets	—		2.1		—		—			2.1
Total assets	$	3,816.9	$	3,253.7	$	1,208.1	$	(3,816.7	)	$	4,462.0
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	16.3	$	210.5	$	—	$	(16.3	)	$	210.5
Other current liabilities	20.0		81.8		16.2		—			118.0
Total current liabilities	36.3		292.3		16.2		(16.3		)	328.5
Long-term liabilities:
Long-term debt, less current portion	1,752.4		—		—		—			1,752.4
Other long-term liabilities	—		114.0		57.0		—			171.0
Deferred income taxes	—		0.6		—		—			0.6
Total liabilities	1,788.7		406.9		73.2		(16.3		)	2,252.5
Partners’ capital	2,028.2		2,846.8		953.6		(3,800.4		)	2,028.2
Interest of non-controlling partner in subsidiary	—		—		181.3		—			181.3
Total partners’ capital	2,028.2		2,846.8		1,134.9		(3,800.4		)	2,209.5
Total liabilities and partners’ capital	$	3,816.9	$	3,253.7	$	1,208.1	$	(3,816.7	)	$	4,462.0

166

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2019
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,111.8		$	70.1		$	—		$	3,181.9
Costs of product/services sold	—			2,544.9			—			—			2,544.9
Operating expenses and other:
Operations and maintenance	—			120.0			18.8			—			138.8
General and administrative	51.2			47.0			—			—			98.2
Depreciation, amortization and accretion	—			179.4			30.5			—			209.9
Loss on long-lived assets, net	—			6.2			—			—			6.2
Gain on acquisition	—			—			(209.4		)	—			(209.4		)
	51.2			352.6			(160.1		)	—			243.7
Operating income (loss)	(51.2		)	214.3			230.2			—			393.3
Earnings from unconsolidated affiliates, net	—			—			32.8			—			32.8
Interest and debt income (expense), net	(115.5		)	—			0.1			—			(115.4		)
Other income, net	—			0.2			—			—			0.2
Equity in net income (loss) of subsidiaries	442.5			—			—			(442.5		)	—
Income (loss) before income taxes	275.8			214.5			263.1			(442.5		)	310.9
Provision for income taxes	—			(0.3		)	—			—			(0.3		)
Net income (loss)	275.8			214.2			263.1			(442.5		)	310.6
Net income attributable to non-controlling partner	—			—			34.8			—			34.8
Net income (loss) attributable to Crestwood Midstream Partners LP	$	275.8		$	214.2		$	228.3		$	(442.5	)	$	275.8

167

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2018
(in millions)
	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Revenues	$	—		$	3,654.1	$	—	$	—		$	3,654.1
Costs of product/services sold	—			3,129.4		—		—			3,129.4
Operating expenses and other:
Operations and maintenance	—			125.8		—		—			125.8
General and administrative	55.1			28.4		—		—			83.5
Depreciation, amortization and accretion	—			181.4		—		—			181.4
Loss on long-lived assets, net	—			28.6		—		—			28.6
	55.1			364.2		—		—			419.3
Operating income (loss)	(55.1		)	160.5		—		—			105.4
Earnings from unconsolidated affiliates, net	—			—		53.3		—			53.3
Interest and debt expense, net	(99.2		)	—		—		—			(99.2		)
Loss on modification/extinguishment of debt	(0.9		)	—		—		—			(0.9		)
Equity in net income (loss) of subsidiaries	197.6			—		—		(197.6		)	—
Net income (loss)	42.4			160.5		53.3		(197.6		)	58.6
Net income attributable to non-controlling partner	—			—		16.2		—			16.2
Net income (loss) attributable to Crestwood Midstream Partners LP	$	42.4		$	160.5	$	37.1	$	(197.6	)	$	42.4

168

Crestwood Midstream Partners
Condensed Consolidating Statements of Operations
Year Ended December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,880.9	$	—		$	—		$	3,880.9
Costs of product/services sold	—			3,374.7		—			—			3,374.7
Operating expenses and other:
Operations and maintenance	—			136.0		—			—			136.0
General and administrative	67.6			25.5		—			—			93.1
Depreciation, amortization and accretion	—			202.7		—			—			202.7
Loss on long-lived assets, net	—			65.6		—			—			65.6
Goodwill impairment	—			38.8		—			—			38.8
Loss on contingent consideration	—			—		57.0			—			57.0
	67.6			468.6		57.0			—			593.2
Operating income (loss)	(67.6		)	37.6		(57.0		)	—			(87.0		)
Earnings from unconsolidated affiliates, net	—			—		47.8			—			47.8
Interest and debt expense, net	(99.4		)	—		—			—			(99.4		)
Loss on modification/extinguishment of debt	(37.7		)	—		—			—			(37.7		)
Other income, net	—			0.8		—			—			0.8
Equity in net income (loss) of subsidiaries	3.9			—		—			(3.9		)	—
Net income (loss)	(200.8		)	38.4		(9.2		)	(3.9		)	(175.5		)
Net income attributable to non-controlling partner	—			—		25.3			—			25.3
Net income (loss) attributable to Crestwood Midstream Partners LP	$	(200.8	)	$	38.4	$	(34.5	)	$	(3.9	)	$	(200.8	)

169

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2019
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(171.0	)	$	469.1		$	126.0		$	—		$	424.1
Cash flows from investing activities:
Acquisition, net of cash acquired	—			—			(462.1		)	—			(462.1		)
Purchases of property, plant and equipment	—			(258.1		)	(197.4		)	—			(455.5		)
Investment in unconsolidated affiliates	—			—			(61.3		)	—			(61.3		)
Capital distributions from unconsolidated affiliates	—			—			35.5			—			35.5
Net proceeds from sale of assets	—			0.8			—			—			0.8
Other	—			(1.1		)	—			—			(1.1		)
Capital contributions to consolidated affiliates	(203.8		)	—			—			203.8			—
Net cash provided by (used in) investing activities	(203.8		)	(258.4		)	(685.3		)	203.8			(943.7		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,307.3			—			—			—			2,307.3
Payments on long-term debt	(1,728.6		)	(0.9		)	—			—			(1,729.5		)
Payments on finance leases	—			(3.5		)	—			—			(3.5		)
Payments for debt-related deferred costs	(9.0		)	—			—			—			(9.0		)
Net proceeds from the issuance of     non-controlling interest	—			—			235.0			—			235.0
Distributions to partners	(235.8		)	—			(25.0		)	—			(260.8		)
Contributions from parent	—			—			203.8			(203.8		)	—
Taxes paid for unit-based compensation vesting	—			(11.0		)	—			—			(11.0		)
Change in intercompany balances	26.2			(195.3		)	169.1			—			—
Net cash provided by (used in) financing activities	360.1			(210.7		)	582.9			(203.8		)	528.5
Net change in cash and restricted cash	(14.7		)	—			23.6			—			8.9
Cash and restricted cash at beginning of period	16.5			—			—			—			16.5
Cash and restricted cash at end of period	$	1.8		$	—		$	23.6		$	—		$	25.4

170

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2018
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(131.7	)	$	339.2		$	53.0		$	—		$	260.5
Cash flows from investing activities:
Purchases of property, plant and equipment	—			(305.5		)	—			—			(305.5		)
Investment in unconsolidated affiliates	—			—			(64.4		)	—			(64.4		)
Capital distributions from unconsolidated affiliates	—			—			49.2			—			49.2
Net proceeds from sale of assets	—			79.5			—			—			79.5
Capital distributions from consolidated affiliates	27.9			—			—			(27.9		)	—
Net cash provided by (used in) investing activities	27.9			(226.0		)	(15.2		)	(27.9		)	(241.2		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,274.8			—			—			—			2,274.8
Payments on long-term debt	(2,014.8		)	(0.9		)	—			—			(2,015.7		)
Payments on capital leases	—			(1.6		)	—			—			(1.6		)
Payments for deferred financing costs	(5.7		)	—			—			—			(5.7		)
Distributions to partners	(238.4		)	—			(9.9		)	—			(248.3		)
Distributions to parent	—			—			(27.9		)	27.9			—
Taxes paid for unit-based compensation vesting	—			(7.4		)	—			—			(7.4		)
Change in intercompany balances	103.4			(103.4		)	—			—			—
Other	—			0.1			—			—			0.1
Net cash provided by (used in) financing activities	119.3			(113.2		)	(37.8		)	27.9			(3.8		)
Net change in cash and restricted cash	15.5			—			—			—			15.5
Cash and restricted cash at beginning of period	1.0			—			—			—			1.0
Cash and restricted cash at end of period	$	16.5		$	—		$	—		$	—		$	16.5

171

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(162.3	)	$	379.2		$	45.3		$	—		$	262.2
Cash flows from investing activities:
Purchases of property, plant and equipment	—			(188.4		)	—			—			(188.4		)
Investment in unconsolidated affiliates	—			—			(58.0		)	—			(58.0		)
Capital distributions from unconsolidated affiliates	—			—			59.9			—			59.9
Net proceeds from sale of assets	—			225.2			—			—			225.2
Capital contributions to consolidated affiliates	4.3			—			—			(4.3		)	—
Net cash provided by (used in) investing activities	4.3			36.8			1.9			(4.3		)	38.7
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,838.6			—			—			—			2,838.6
Payments on long-term debt	(2,912.6		)	(1.3		)	—			—			(2,913.9		)
Payments on capital leases	—			(2.7		)	—			—			(2.7		)
Payments for deferred financing costs	(1.0		)	—			—			—			(1.0		)
Redemption of non-controlling interest	—			—			(202.7		)	—			(202.7		)
Net proceeds from issuance of non-controlling      interest	—			—			175.0			—			175.0
Distributions to partners	(174.0		)	—			(15.2		)	—			(189.2		)
Distributions to parent	—			—			(4.3		)	4.3			—
Taxes paid for unit-based compensation vesting	—			(5.5		)	—			—			(5.5		)
Change in intercompany balances	406.7			(406.7		)	—			—			—
Other	—			0.2			—			—			0.2
Net cash provided by (used in) financing activities	157.7			(416.0		)	(47.2		)	4.3			(301.2		)
Net change in cash and restricted cash	(0.3		)	—			—			—			(0.3		)
Cash and restricted cash at beginning of period	1.3			—			—			—			1.3
Cash and restricted cash at end of period	$	1.0		$	—		$	—		$	—		$	1.0

172

Supplemental Selected Quarterly Financial Information (Unaudited)

Summarized unaudited quarterly financial data is presented below (in millions, except per unit information):

Crestwood Equity	Quarter Ended
	March 31			June 30			September 30			December 31
2019
Revenues	$	835.2		$	683.4		$	823.6		$	839.7
Operating income(1)	32.0			249.3			53.7			67.2
Earnings from unconsolidated affiliates, net	6.9			3.7			10.4			11.8
Net income	14.1			225.0			33.6			47.2
Net income (loss) attributable to partners	(4.9		)	199.4			8.7			21.8
Net income (loss) per limited partner unit:
Basic	$	(0.07	)	$	2.76		$	0.12		$	0.30
Diluted	$	(0.07	)	$	2.58		$	0.12		$	0.28
2018
Revenues	$	1,115.0		$	840.5		$	930.2		$	768.4
Operating income (loss)(2)	46.0			(9.1		)	4.8			71.8
Loss on modification/extinguishment of debt	—			—			—			(0.9		)
Earnings from unconsolidated affiliates, net	12.4			12.0			15.1			13.8
Net income (loss)	34.1			(21.5		)	(5.2		)	59.6
Net income (loss) attributable to partners	15.1			(40.6		)	(24.3		)	40.5
Net income (loss) per limited partner unit:
Basic and Diluted	$	0.21		$	(0.57	)	$	(0.34	)	$	0.57

Crestwood Midstream	Quarter Ended
	March 31		June 30			September 30			December 31
2019
Revenues	$	835.2	$	683.4		$	823.6		$	839.7
Operating income(1)	29.6		247.3			51.3			65.1
Earnings from unconsolidated affiliates, net	6.9		3.7			10.4			11.8
Net income	11.6		222.9			31.2			44.9
Net income attributable to partner	7.6		212.3			21.3			34.6
2018
Revenues	$	1,115.0	$	840.5		$	930.2		$	768.4
Operating income (loss)(2)	44.4		(11.1		)	2.2			69.9
Loss on modification/extinguishment of debt	—		—			—			(0.9		)
Earnings from unconsolidated affiliates, net	12.4		12.0			15.1			13.8
Net income (loss)	32.4		(23.5		)	(7.8		)	57.5
Net income (loss) attributable to partner	28.4		(27.5		)	(11.9		)	53.4

(1) Amount for the three months ended June 30, 2019 includes a gain on acquisition of $209.4 million related to the acquisition of the remaining 50% equity interest in Jackalope from Williams. See Note 3 for further discussion of this transaction.

(2) Amount for the three months ended June 30, 2018 and September 30, 2018 includes a loss on long-lived assets of $24.5 million and $2.4 million related to the sale of our West Coast facilities.

173

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

		CRESTWOOD EQUITY PARTNERS LP
		By Crestwood Equity GP, LLC
		(its general partner)
		CRESTWOOD MIDSTREAM PARTNERS LP
		By Crestwood Midstream GP LLC
		(its general partner)
Dated:	February 21, 2020	By	/s/    ROBERT G. PHILLIPS
			Robert G. Phillips
			President, Chief Executive Officer and Director

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following officers of Crestwood Equity GP, LLC, as general partner of Crestwood Equity Partners LP, and Crestwood Midstream GP LLC, as general partner of Crestwood Midstream Partners LP, and the following directors of Crestwood Equity GP LLC in the capacities and on the dates indicated.

Date	Signature and Title
February 21, 2020	/s/    ROBERT G. PHILLIPS Robert G. Phillips, President, Chief Executive Officer and Director (Principal Executive Officer)
February 21, 2020	/s/    ROBERT T. HALPIN Robert T. Halpin, Executive Vice President and Chief Financial Officer (Principal Financial Officer)
February 21, 2020	/s/    STEVEN M. DOUGHERTY Steven M. Dougherty, Executive Vice President and Chief Accounting Officer (Principal Accounting Officer)
February 21, 2020	/s/    ALVIN BLEDSOE Alvin Bledsoe, Director
February 21, 2020	/s/    WILLIAM BROWN William Brown, Director
February 21, 2020	/s/    GARY D. REAVES Gary D. Reaves, Director
February 21, 2020	/s/    WARREN H. GFELLER Warren H. Gfeller, Director
February 21, 2020	/s/    JANEEN S. JUDAH Janeen S. Judah, Director
February 21, 2020	/s/    DAVID LUMPKINS David Lumpkins, Director
February 21, 2020	/s/    JOHN J. SHERMAN John J. Sherman, Director

174

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Balance Sheets

(in millions)

	December 31,
	2019		2018
Assets
Current assets:
Cash	$	0.2	$	0.2
Total current assets	0.2		0.2
Property, plant and equipment, net	1.0		1.1
Investments in subsidiaries	1,935.9		1,854.7
Other assets	3.1		2.8
Total assets	$	1,940.2	$	1,858.8
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	0.1	$	2.6
Accrued expenses	1.3		1.1
Total current liabilities	1.4		3.7
Other long-term liabilities	6.0		2.6
Total partners’ capital	1,932.8		1,852.5
Total liabilities and partners’ capital	$	1,940.2	$	1,858.8

See accompanying notes.

175

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Operations

(in millions)

	Year Ended December 31,
	2019			2018			2017
Revenues	$	—		$	—		$	—
Expenses	5.3			6.1			6.7
Operating loss	(5.3		)	(6.1		)	(6.7		)
Equity in net income (loss) of subsidiaries	290.0			56.5			(185.7		)
Other income, net	0.4			0.4			0.5
Net income (loss) attributable to Crestwood Equity Partners LP	$	285.1		$	50.8		$	(191.9	)

See accompanying notes.

176

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Comprehensive Income

(in millions)

	Year Ended December 31,
	2019		2018			2017
Net income (loss) attributable to Crestwood Equity Partners LP	$	285.1	$	50.8		$	(191.9	)
Change in fair value of Suburban Propane Partners, LP units	0.3		(0.7		)	(0.8		)
Comprehensive income (loss) attributable to Crestwood Equity Partners LP	$	285.4	$	50.1		$	(192.7	)

See accompanying notes.

177

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Cash Flows

(in millions)

	Year Ended December 31,
	2019			2018			2017
Cash flows from operating activities	$	(3.7	)	$	(3.8	)	$	(3.6	)
Cash flows from investing activities	235.8			238.4			174.0
Cash flows from financing activities:
Distributions paid to partners	(232.5		)	(230.9		)	(182.6		)
Proceeds from issuance of common units	—			—			15.2
Change in intercompany balances	0.4			(3.8		)	(3.0		)
Net cash used in financing activities	(232.1		)	(234.7		)	(170.4		)
Net change in cash	—			(0.1		)	—
Cash at beginning of period	0.2			0.3			0.3
Cash at end of period	$	0.2		$	0.2		$	0.3

See accompanying notes.

178

Schedule I

Crestwood Equity Partners LP

Parent Only

Notes to Condensed Financial Statements

Note 1. Basis of Presentation

In the parent-only financial statements, our investment in subsidiaries is stated at cost plus equity in undistributed earnings of subsidiaries since the date of acquisition.  Our share of net income of our unconsolidated subsidiaries is included in consolidated income using the equity method.  The parent-only financial statements should be read in conjunction with our consolidated financial statements. 

The condensed statements of operations for the years ended December 31, 2018 and 2017 include reclassifications

that were made to conform to the current year presentation, none of which impacted previously reported net income (loss) attributable to Crestwood Equity Partners LP or partners’ capital.

Note 2. Distributions    

During the years ended December 31, 2019, 2018 and 2017, we received cash distributions from Crestwood Midstream Partners LP of approximately $235.8 million, $238.4 million and $174.0 million.

179

Schedule II

Crestwood Equity Partners LP

Crestwood Midstream Partners LP

Valuation and Qualifying Accounts

For the Years Ended December 31, 2019, 2018 and 2017

(in millions)

	Balance at beginning of period		Charged to costs and expenses		Other Additions		Deductions (write-offs)			Balance at end of period
Allowance for doubtful accounts
2019	$	0.3	$	0.1	$	—	$	(0.1	)	$	0.3
2018	$	2.4	$	0.2	$	—	$	(2.3	)	$	0.3
2017	$	1.9	$	1.5	$	—	$	(1.0	)	$	2.4

180

EX-4.16

Exhibit 4.16

DESCRIPTION OF THE REGISTRANT’S SECURITIES

REGISTERED PURSUANT TO SECTION 12 OF THE

SECURITIES EXCHANGE ACT OF 1934

The following description of the common and preferred units representing limited partner interests in Crestwood Equity Partners LP, a Delaware limited partnership (the “Partnership,” “we,” “us,” and “our”), is based on our Fifth Amended and Restated Agreement of Limited Partnership, as amended, which we refer to as our “partnership agreement,” and applicable provisions of law. The following summary does not purport to be complete and is qualified in its entirety by reference to the provisions of applicable law and to our partnership agreement. References to our “general partner” refer to Crestwood Equity GP LLC, a Delaware limited liability company.

The Common Units

The common units represent limited partner interests in us. The holders of common units are entitled to participate in partnership distributions and exercise the rights or privileges available to limited partners under our partnership agreement. For a description of the relative rights and preferences of holders of common units in and to partnership distributions, please read this section and “Provisions of Our Partnership Agreement Relating to Cash Distributions.” For a description of voting rights, rights of distribution upon liquidation and other rights and privileges of limited partners, including our common units under our partnership agreement, please read “Our Partnership Agreement.”

Transfers of Common Units

Upon the transfer of a common unit in accordance with our partnership agreement, the transferee of the common unit will be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Each transferee:

• represents that the transferee has the capacity, power and authority to become bound by our partnership agreement;

• automatically becomes bound by the terms and conditions of, and is deemed to have executed, our partnership agreement; and

• gives the consents, waivers and approvals contained in our partnership agreement.

In addition to other rights acquired upon transfer, the transferor gives the transferee the right to become a substituted limited partner in our partnership for the transferred common units. A transferee will become a substituted limited partner of our partnership for the transferred common units automatically upon the recording of the transfer on our books and records. Our general partner will cause any transfers to be recorded on our books and records no less frequently than quarterly.

Until a common unit has been transferred on our books, we and the transfer agent may treat the record holder of the common unit as the absolute owner for all purposes, except as otherwise required by law or stock exchange regulations.

We may, at our discretion, treat the nominee holder of a common unit as the absolute owner. In that case, the beneficial holder’s rights are limited solely to those that it has against the nominee holder as a result of any agreement between the beneficial owner and the nominee holder.

Common units are securities, and any transfers of common units are subject to the laws governing the transfer of securities.

The Preferred Units

The preferred units represent a separate class of our limited partnership interests. For a description of the relative rights and preferences of holders of preferred units in and to partnership distributions, please read this section and

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“Provisions of Our Partnership Agreement Relating to Cash Distributions.” For a description of voting rights, rights of distribution upon liquidation and other rights and privileges of limited partners, including our preferred units under our partnership agreement, please read “Our Partnership Agreement.”

Conversion

One or more preferred unitholders may elect, each in its own discretion, (i) to convert all or any portion of the preferred units held by such preferred unitholders, in an aggregate amount equaling or exceeding the Minimum Conversion Amount (as defined in Amendment No. 1 to our partnership agreement (the “Partnership Agreement Amendment”)), into common units, at the then applicable Conversion Ratio (as defined in the Partnership Agreement Amendment), subject to payment of any accrued but unpaid distributions to the date of conversion and (ii) in the event of our voluntary liquidation, dissolution or winding up, to convert all or any portion of their preferred units into common units, at the then applicable Conversion Ratio, subject to payment of any accrued but unpaid distributions to the date of conversion.

At any time, subject to certain liquidity requirements set forth in the Partnership Agreement Amendment, if the volume-weighted average trading price of the common units on the national securities exchange on which the common units are then listed (the “VWAP Price”) for 20 trading days over the 30-trading day period ending on the close of trading on the day immediately preceding the date notice is given by us of election of our conversion right is greater than the quotient of (i) $13.69095 divided by (ii) the then applicable Conversion Ratio, our general partner, in its sole discretion, may convert all or a portion of the outstanding preferred units into common units, at the then applicable Conversion Ratio, subject to the payment of any accrued but unpaid distributions to the date of conversion. Also, subject to certain liquidity requirements set forth in the Partnership Agreement Amendment, if the VWAP Price of the common units for 20 trading days over the 30-trading day period ending on the close of trading on the day immediately preceding the date notice is given by us of the exercise of our conversion right is greater than the quotient of (i) $9.1273 divided by (ii) the then applicable Conversion Ratio, our general partner, in its sole discretion, may convert all, but not less than all, of the outstanding preferred units into a number of common units equal to the Adjusted Conversion Amount.

Rights upon a Change of Control

In the event of a Cash COC Event (as defined in the Partnership Agreement Amendment), the preferred unitholders shall convert the outstanding preferred units into common units immediately prior to the closing of such Cash COC Event at a conversion ratio equal to the greater of (i) the then applicable Conversion Ratio and (ii) the quotient of (1) the product of (a) $9.1273 multiplied by (b) the Cash COC Conversion Premium (as defined in the Partnership Agreement Amendment), divided by (2) the VWAP Price of the common units for the 10 consecutive trading days ending immediately prior to the date of closing of the Cash COC Event, subject to a $10.00 per unit floor on common units received, subject to the payment of any accrued but unpaid distributions to the date of conversion.

If a Change of Control (as defined in the Partnership Agreement Amendment) (other than a Cash COC Event) occurs, then each preferred unitholder shall, at its sole discretion:

(i) convert its preferred units into common units, at the then applicable Conversion Ratio, subject to the payment of any accrued but unpaid distributions to the date of conversion;

(ii) if (1) either (x) we are not the surviving entity or (y) we are the surviving entity but the common units are no longer listed on the New York Stock Exchange or another national securities exchange and (2) the consideration per common unit exceeds $10.00, require us to use our best efforts to deliver to such preferred unitholders a mirror security to the preferred units in the surviving entity, which security shall have substantially similar terms, including with respect to economics and structural protections, as the preferred units, provided, that if we are not able to deliver such a mirror security, such preferred unitholders shall be entitled to (a) take any action otherwise permitted by clause (i) above or clauses (iii) or (iv) below or (b) convert the preferred units held by such preferred unitholders into a number of common units based on a conversion ratio described in the Partnership Agreement Amendment;

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(iii) if we are the surviving entity and the consideration per common unit exceeds $10.00, continue to hold its preferred units; or

(iv) require us to redeem its preferred units at a price of $9.218573 per preferred unit, plus accrued and unpaid distributions to the date of such redemption (which redemption may be paid, in the sole discretion of the general partner, in cash or in common units, in accordance with the terms of the Partnership Agreement Amendment).

Class A Units

Class A units represent limited partner interests in us (the “Class A units”). The rights and obligations of Class A units are identical to the rights and obligations of common units except that the Class A units generally do not have voting rights and do not share in certain distributions. For a description of the relative rights and preferences of holders of Class A units in and to partnership distributions, please read “Provisions of Our Partnership Agreement Relating to Cash Distributions.” For a description of voting rights, rights of distribution upon liquidation and other rights and privileges of limited partners, including our Class A units under our partnership agreement, please read “Our Partnership Agreement.”

Subordinated Units

The subordinated units represent limited partner interests in us. In connection with Crestwood Holdings’ acquisition of our general partner, and prior to the reverse unit split, we issued 4,387,889 subordinated units to Crestwood Gas Services Holdings LLC. The rights and obligations of the subordinated units are identical to the rights and obligations of common units except that the subordinated units are subordinate to common units with respect to distribution. Please read “Provisions of Our Partnership Agreement Relating to Cash Distributions—Subordinated Units.”

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PROVISIONS OF OUR PARTNERSHIP AGREEMENT RELATING TO CASH DISTRIBUTIONS

Set forth below is a summary of the significant provisions of our partnership agreement that relate to cash distributions.

Distributions to Preferred Units

The preferred units are entitled to a cumulative distribution (the “Preferred Distribution”) of $0.2111 per quarter in respect of each preferred unit, subject to certain adjustments described in the Partnership Agreement Amendment. For each quarter beginning with the first quarter ending after the effective time of the Merger through and including the quarter ending September 30, 2017 (the “Initial Distribution Period”), the Preferred Distribution was paid, in the sole discretion of our general partner, in additional preferred units, in cash, or in a combination of additional preferred units and cash (any such distributions paid in additional preferred units (“PIK Distributions”)).

Following the Initial Distribution Period, each Preferred Distribution is paid in cash at the Preferred Distribution Amount unless, subject to certain exceptions, (i) there is no distribution being paid on Parity Securities and Junior Securities (including the common units) (each as defined in the Partnership Agreement Amendment) and (ii) the Partnership’s Available Cash (as defined in our partnership agreement), excluding any deductions to provide funds for distributions of Available Cash to our common unitholders in respect of any one or more of the next four quarters, is insufficient to pay the Preferred Distribution. If we fail to pay the Preferred Distribution in full in cash for any quarter after the Initial Distribution Period, then until such time as all accrued and unpaid Preferred Distributions are paid in full in cash (i) the Distribution Amount will increase to $0.2567 per quarter, (ii) we will not be permitted to declare or make (a) any distributions in respect of any Junior Securities (including the common units) and (b) subject to certain exceptions, any distributions in respect of any Parity Securities, and (iii) certain preferred unitholders shall receive the right to designate a person to serve on the board of directors of our general partner.

If we fail to pay in full any Preferred Distribution, 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. Any accrued and unpaid distributions will increase at a rate of 2.8125% per quarter.

Distributions of Available Cash

General

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash to unitholders of record on the applicable record date.

Definition of Available Cash

Available cash, for any quarter, consists of all cash and cash equivalents on hand at the end of that quarter:

• less, the amount of cash reserves that is necessary or appropriate in the reasonable discretion of our general partner 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 future distributions to our partners for any one or more of the next four quarters;

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

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provided, however, that available cash does not include any IPCH/Crestwood Partners Available Cash (as defined in our partnership agreement).

General Partner Interest

Our general partner is not entitled to distributions on its non-economic interest.

Class A Units

Class A units generally share in distributions of available cash, except Class A units do not share in (i) any income, gains, losses, deductions and credits which are attributable to our ownership of, or sale or other disposition of, the shares of common stock of IPCH and the membership interests of Crestwood Partners or (ii) any cash and cash equivalents on hand derived from or attributable to our ownership of, or sale or other disposition of, the shares of common stock of IPCH and the membership interests of Crestwood Partners. For each of the first ten quarters ending on or after March 31, 2014 after the end of the subordination period, Class A Units are entitled to a distribution equal to $10.00 per Class A unit prior to the quarterly distributions of available cash to all unitholders.

Subordinated Units

The subordinated units are entitled to receive distributions of available cash for a particular quarter only after each of our common units has received a distribution of at least $1.30 for that quarter. Our subordinated units convert to common units after our common units have received a cumulative distribution in excess of $5.20 during a consecutive four quarter period and its Adjusted Operating Surplus (as defined in the partnership agreement) exceeds the distribution on a fully dilutive basis.

Distributions of Cash Upon Liquidation

If we dissolve in accordance with the partnership agreement, we will sell or otherwise dispose of our assets in a process called liquidation. We will first apply the proceeds of liquidation to the payment of our creditors. We will distribute any remaining proceeds to our unitholders, in accordance with their capital account balances, as adjusted to reflect any gain or loss upon the sale or other disposition of our assets in liquidation.

If the sale of our assets in liquidation would be impracticable or would cause undue loss, the sale may be deferred for a reasonable amount of time or the assets (except those necessary to satisfy liabilities) may be distributed to our limited partners in lieu of cash in the same manner as cash or proceeds of a sale would have been distributed.

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OUR PARTNERSHIP AGREEMENT

The following is a summary of certain material provisions of our partnership agreement that relate to ownership of our common units.

Capital Contributions

Our unitholders are not obligated to make additional capital contributions, except as described below under “—Limited Liability.”

Limited Voting Rights

Common Units and Preferred Units

The following is a summary of the unitholder vote required for each of the matters specified below. Matters that require the approval of a “unit majority” require the approval of a majority of the common units and preferred units voting on an as-if converted basis.

In voting their common units, our general partner and its affiliates will have no fiduciary duty or obligation whatsoever to us or the limited partners, including any duty to act in good faith or in the best interests of us or the limited partners.

Issuance of additional units Creation of any class of Senior Securities (as defined in the Partnership Agreement Amendment) requires super-majority approval of the preferred unitholders. Please read “—Issuance of Additional Interests.”

Amendment of the partnership agreement Certain amendments may be made by our general partner without the approval of the unitholders. Other amendments generally require the approval of a majority of outstanding units. Certain other amendments require the approval of a super-majority of outstanding units. Certain amendments that impact the preferred units require approval of a super-majority of the preferred unitholders. Please read “—Amendment of the Partnership Agreement.”

Merger of our partnership or the sale of

all or substantially all of our assets Majority of outstanding units. A Change of Control in which consideration to be received by the common unitholders has a value of less than $10.00 per common unit requires approval of the majority of the outstanding preferred units (the “Voting Threshold”). Please read “—Merger, Sale or Other Disposition of Assets.”

Dissolution of our partnership Majority of outstanding units. Please read “—Termination and Dissolution.”

Continuation of our business upon dissolution Majority of outstanding units. Please read “—Termination and Dissolution.”

Election to be treated as a corporation

for U.S. federal tax law Super-majority approval of the holders of the preferred units. Please read “—Amendment of the Partnership Agreement—Opinion of Counsel and Unitholder Approval.”

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Withdrawal of our general partner No approval right. Please read “—Withdrawal or Removal of Our General Partner.”

Removal of our general partner Not less than 66 2∕3% of the outstanding common units, including common units held by our general partner and its affiliates. Please read “—Withdrawal or Removal of Our General Partner.”

Transfer of our general partner interest No approval right.

If any person or group other than our general partner and its affiliates acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply to (i) (A) any person or group that acquires the units from our general partner or its affiliates and (B) any transferees of that person or group approved by our general partner or to (C) any person or group who acquires the units with the specific prior approval of our general partner, or (ii) (A) with respect to matters as to which the preferred units vote as a separate class and (B) with respect to matters as to which the preferred units vote together with the common units as a single class, provided that, such preferred unitholder would not beneficially own 20% or more of the common units, determined on an as-converted basis at the then-applicable Conversion Ratio. Notwithstanding anything to the contrary, with respect to any matter as to which the preferred units vote as a separate class, if at any time First Reserve Management, L.P. and its affiliates (“First Reserve”) acquires beneficial ownership of 20% or more the then outstanding preferred units, then none of such preferred units beneficially owned by First Reserve may be voted on such matter or be considered outstanding when calculating required votes or determining presence for a quorum.

Class A Units

Holders of Class A units do not have the right to vote on, approve or disapprove, or otherwise consent or not consent with respect to any matter (including mergers, share exchanges and similar statutory authorizations) except as otherwise required by any non-waivable provision of law.

Limited Liability

Assuming that a limited partner does not participate in the control of our business within the meaning of the Delaware Revised Uniform Limited Partnership Act, as amended (the “Delaware Act”), and that it otherwise acts in conformity with the provisions of our partnership agreement, such limited partner’s liability under the Delaware Act will be limited, subject to possible exceptions, to the amount of capital such limited partner is obligated to contribute to us for its common units plus its share of any undistributed profits and assets. If it were determined, however, that the right, or exercise of the right, by our limited partners as a group:

• to remove or replace our general partner;

• to approve some amendments to our partnership agreement; or

• to take other action under our partnership agreement;

constituted “participation in the control” of our business for the purposes of the Delaware Act, then our limited partners could 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. While this does not mean that a limited partner could not seek legal recourse, we know of no precedent for this type of a claim in Delaware case law.

Under the Delaware Act, a limited partnership may not make a distribution to a partner if, after the distribution, all liabilities of the limited partnership, other than liabilities to partners on account of their partnership interests and liabilities for which the recourse of creditors is limited to specific property of the partnership, would exceed the fair value of the assets of the limited partnership. For the purpose of determining the fair value of the assets of a limited

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partnership, the Delaware Act provides that the fair value of property subject to liability for which recourse of creditors is limited shall be included in the assets of the limited partnership only to the extent that the fair value of that property exceeds the nonrecourse liability. The Delaware Act provides that a limited partner who receives a distribution and knew at the time of the distribution that the distribution was in violation of the Delaware Act shall be liable to the limited partnership for the amount of the distribution for three years.

Limitations on the liability of members or limited partners for the obligations of a limited liability company or limited partnership have not been clearly established in many jurisdictions. If, by virtue of our ownership interest in our subsidiaries or otherwise, it were determined that we were conducting business in any jurisdiction without compliance with the applicable limited liability company or limited partnership statute, or that the right or exercise of the right by our limited partners as a group to remove or replace our general partner, to approve some amendments to our partnership agreement, or to take other action under our partnership agreement constituted “participation in the control” of our business for purposes of the statutes of any relevant jurisdiction, then our limited partners could be held personally liable for our obligations under the law of that jurisdiction to the same extent as our general partner under the circumstances. We will operate in a manner that our general partner considers reasonable and necessary or appropriate to preserve the limited liability of our limited partners.

Issuance of Additional Interests

Our partnership agreement authorizes us to issue an unlimited number of additional partnership interests for the consideration and on the terms and conditions determined by our general partner without the approval of the common unitholders. However, the affirmative vote of a super-majority of the preferred unitholders is required prior to the creation of any class of Senior Securities.

It is possible that we will fund acquisitions through the issuance of additional common units or other partnership interests. Holders of any additional common units we issue will be entitled to share equally with the then-existing common unitholders in our distributions of available cash. In addition, the issuance of additional common units or other partnership interests may dilute the value of the interests of the then-existing common unitholders in our net assets.

In accordance with Delaware law and the provisions of our partnership agreement, we may also issue additional partnership interests that, as determined by our general partner, may have special voting rights to which the common units are not entitled. In addition, our partnership agreement does not prohibit our subsidiaries from issuing equity interests, which may effectively rank senior to the common units.

The common unitholders will not have preemptive rights under our partnership agreement to acquire additional common units or other partnership interests. The preferred unitholders, however, do have preemptive rights with respect to any Parity Securities (as defined in the Partnership Agreement Amendment).

Amendment of the Partnership Agreement

General

Amendments to our partnership agreement may be proposed only by or with the consent our general partner, which consent may be given or withheld in its sole discretion. To adopt a proposed amendment, other than certain amendments discussed below, our general partner must seek written approval of the holders of the number of units required to approve the amendment or call a meeting of the limited partners to consider and vote upon the proposed amendment. Except as otherwise described below, an amendment must be approved by a unit majority. In addition, the affirmative vote of a super-majority of the preferred unitholders is required prior to amending the partnership agreement in any manner that (i) alters or changes the rights, powers, privileges or preferences or duties and obligations of the preferred units in any material respect, (ii) subject to certain exceptions, increases or decreases the authorized number of preferred units, or (iii) otherwise adversely affects the preferred units, including the creation of any class of Senior Securities.

No Unitholder Approval

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Our general partner may generally make amendments to our partnership agreement without the approval of any limited partner to reflect:

• a change in our name, the location of our principal place of business, our registered agent or our registered office;

• the admission, substitution, withdrawal or removal of partners in accordance with our partnership agreement;

• a change that, in the sole discretion of our general partner, is necessary or advisable to qualify or continue our qualification as a limited partnership or a partnership in which the limited partners have limited liability under the laws of any state or to ensure that we will not be treated as an association taxable as a corporation or otherwise taxed as an entity for U.S. federal income tax purposes;

• an amendment that is necessary, in the opinion of our counsel, to prevent us or our general partner or its directors, officers, agents or trustees from in any manner being subjected to the provisions of the Investment Company Act of 1940, the Investment Advisers Act of 1940 or “plan asset” regulations adopted under the Employee Retirement Income Security Act of 1974, or ERISA, whether or not substantially similar to plan asset regulations currently applied or proposed;

• an amendment that, in the discretion of our general partner, is necessary or advisable in connection with the authorization of issuance of any class or series of partnership interests;

• any amendment expressly permitted in our partnership agreement to be made by our general partner acting alone;

• an amendment effected, necessitated or contemplated by a merger agreement that has been approved under the terms of our partnership agreement;

• any amendment that, in the discretion of our general partner, is necessary or advisable to reflect, account for and deal with appropriately the formation by us of, or our investment in, any corporation, partnership, joint venture, limited liability company or other entity, as otherwise permitted by our partnership agreement;

• a change in our fiscal year or taxable year and any changes that, in the discretion of our general partner, are necessary or advisable as a result of a change in our fiscal year or taxable year including, if our general partner shall so determine, a change in the definition of “Quarter” and the dates on which distributions are to be made by us;

• a merger or conveyance pursuant to which (i) our general partner has received an opinion of counsel that the merger or conveyance would not result in the loss of the limited liability of any limited partner or cause our partnership to be treated as an association taxable as a corporation or otherwise to be taxed as an entity for federal income tax purposes (to the extent not previously treated as such), (ii) the sole purpose of such merger or conveyance is to effect a mere change in the legal form of our partnership into another limited liability entity and (iii) the governing instruments of the new entity provide the limited partners and our general partner with the same rights and obligations as are contained in the partnership agreement; or

• any other amendments substantially similar to any of the matters described in the clauses above.

In addition, our general partner may make amendments to our partnership agreement, without the approval of any limited partner, if our general partner determines that those amendments:

• do not adversely affect the limited partners (including any particular class of partnership interests as compared to other classes of partnership interests) in any material respect;

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• are necessary or advisable to satisfy any requirements, conditions or guidelines contained in any opinion, directive, order, ruling or regulation of any federal or state agency or judicial authority or contained in any federal or state statute;

• are necessary or advisable to facilitate the trading of limited partner interests (including the division of any class or classes of outstanding limited partner interests into different classes to facilitate uniformity of tax consequences within such classes of limited partner interests) or to comply with any rule, regulation, guideline or requirement of any national securities exchange on which the limited partner interests are or will be listed for trading , compliance with any of which our general partner determines in its discretion to be in the best interests of our partnership and our limited partners;

• are necessary or advisable in connection with any action taken by our general partner relating to a split, distribution, subdivision or combination of partnership securities; or

• are required to effect the intent of the provisions of our partnership agreement or are otherwise contemplated by our partnership agreement.

No Reduction of Voting Percentage Required to Take Action

Any amendment to the partnership agreement that reduces the voting percentage required to take any action must be approved by the affirmative vote of our limited partners constituting not less than the voting requirement sought to be reduced.

No Enlargement of Obligations

No amendment to our partnership agreement may (i) enlarge the obligations of any limited partner without its consent, unless such is deemed to have occurred as a result of an amendment approved by the holders of not less than a majority of the outstanding partnership interests of the class affected, (ii) enlarge the obligations of, restrict in any way any action by or rights of, or reduce in any way the amounts distributable, reimbursable or otherwise payable to, our general partner or any of its affiliates without the consent of general partner, which consent may be given or withheld in its sole discretion, (iii) change the provision of the partnership agreement that provides for the dissolution of our partnership upon the election to dissolve our partnership by our general partner that is approved by the holders of a unit majority (the “Elective Dissolution Provision”) or (iv) change the term of our partnership or, except as set forth in the Elective Dissolution Provision, give any person the right to dissolve our partnership.

No Material Adverse Effect on Rights and Preferences

Except for certain amendments in connection with the merger or consolidation of our partnership and except for those amendments that may be effected by our general partner without the consent of limited partners as described above, any amendment that would have a material adverse effect on the rights or preferences of any class of partnership interests in relation to other classes of partnership interests must be approved by the holders of not less than a majority of the outstanding partnership interests of the class affected, and to the extent such amendment would adversely affect any preferred unitholder in a disproportionate manner, consent of such preferred unitholder would also be required.

Opinion of Counsel and Unitholder Approval

Except as for those amendments that may be effected by our general partner without the consent of limited partners as described above, no amendments shall become effective without the approval of the holders of at least 90% of the outstanding units voting as a single class unless we obtain an opinion of counsel to the effect that such amendment will not affect the limited liability of any limited partner under applicable law. However, unanimous approval of the holders of the preferred units is required prior to our making an election to be treated as a taxable entity for federal income tax purposes.

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Further Restrictions on Amendments.

Except as for those amendments that may be effected by our general partner without the consent of limited partners as described above, the foregoing provisions described above relating to the amendment of our partnership agreement may only be amended with the approval of the holders of at least 90% of the outstanding units (provided that the approval rights of the preferred unitholders may only be amended with the super-majority approval of the preferred unitholders).

Merger, Sale or Other Disposition of Assets

Our partnership agreement generally prohibits our general partner, without the prior approval of a unit majority, from causing us to, among other things, sell, exchange or otherwise dispose of all or substantially all of the consolidated assets we and our operating subsidiaries own in a single transaction or a series of related transactions (including by way of merger, consolidation or other combination). Our general partner may, however, mortgage, pledge, hypothecate or grant a security interest in all or substantially all of our consolidated assets without the approval of a unit majority. Our partnership agreement generally prohibits our general partner from causing us to merge or consolidate with another entity without the approval of a unit majority.

If certain conditions specified in the partnership agreement are satisfied, our general partner may merge our partnership or any of our subsidiaries into, or convey some or all of our assets to, a newly formed entity if the sole purpose of that merger or conveyance is to change our legal form into another limited liability entity.

A Change of Control in which consideration to be received by the common unitholders has a value of less than $10.00 per common unit requires approval of the preferred unitholders at the then-applicable Voting Threshold.

Termination and Dissolution

We will continue as a limited partnership until dissolved under our partnership agreement. We will dissolve upon:

• the election of our general partner to dissolve us, if approved by the holders of units representing a unit majority;

• the sale of all or substantially all of the assets and properties of our partnership and its subsidiaries, treated as a single consolidated entity;

• the entry of a decree of judicial dissolution of our partnership pursuant to the provisions of the Delaware Act; or

• the withdrawal, removal, bankruptcy or dissolution of our general partner, unless a successor general partner is elected prior to or on the effective date of such withdrawal, removal, bankruptcy or dissolution and we receive a withdrawal opinion of counsel.

Upon (a) dissolution of our partnership following the withdrawal or removal of our general partner and the failure of the partners to select a successor general partner, then within 90 days thereafter, or (b) dissolution of our partnership upon the bankruptcy or dissolution of our general partner, then, to the maximum extent permitted by law, within 180 days thereafter, the holders of a unit majority may elect to reconstitute our partnership and continue its business on the same terms and conditions set forth in our partnership agreement by forming a new limited partnership on terms identical to those set forth in our partnership agreement and having as the successor general partner a person approved by the holders of a unit majority. Unless such an election is made within the applicable time period as set forth above, we shall conduct only activities necessary to wind up its affairs.

Liquidation and Distribution of Proceeds

Upon our dissolution, unless our business is continued, the liquidator authorized to wind up our affairs will, acting with all of the powers of our general partner that are necessary or appropriate, liquidate our assets and apply

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the proceeds of the liquidation as described in “Provisions of Our Partnership Agreement Relating to Cash Distributions—Distributions of Cash Upon Liquidation.” The liquidator may defer liquidation or distribution of our assets for a reasonable period of time or distribute assets to partners in kind if it determines that a sale would be impractical or would cause undue loss to our partners.

Withdrawal or Removal of Our General Partner

Our general partner may withdraw as our general partner by giving at least 90 days’ advance notice to the unitholders, such withdrawal to take effect on the date specified in such notice. Our general partner may voluntarily withdraw at any time by giving at least 90 days’ advance notice of its intention to withdraw to the limited partners, such withdrawal to take effect on the date specified in the notice, if at the time such notice is given one person and its affiliates (other than our general partner and its affiliates) own beneficially or of record or control at least 50% of the outstanding units.

If our general partner gives a notice of withdrawal, the holders of a unit majority may, prior to the effective date of such withdrawal, elect a successor general partner. The person so elected as successor general partner will automatically become the successor general partner. If, prior to the effective date of our general partner’s withdrawal, a successor is not selected by the unitholders or we do not receive a withdrawal opinion of counsel, we will be dissolved in accordance with our partnership agreement.

Our general partner may be removed if such removal is approved by the unitholders holding at least 66 2∕3% of the outstanding units (including units held by our general partner and its affiliates). Any such action by such holders for removal of our general partner must also provide for the election of a successor general partner by the unitholders holding a unit majority (including units held by our general partner and its affiliates). Such removal will be effective immediately following the admission of a successor general partner pursuant to our partnership agreement. The right of the holders of outstanding units to remove the general partner will not exist or be exercised unless we have received a withdrawal opinion of counsel.

If our general partner withdraws or is removed, we are required to reimburse the departing general partner for all amounts due the departing general partner.

Change of Management Provisions

Our partnership agreement contains specific provisions that are intended to discourage a person or group from attempting to remove CEQP GP as our general partner or from otherwise changing our management. Please read “—Withdrawal or Removal of Our General Partner” for a discussion of certain consequences of the removal of our general partner. If any person or group, other than our general partner and its affiliates, acquires beneficial ownership of 20% or more of any class of units, that person or group loses voting rights on all of its units. This loss of voting rights does not apply in certain circumstances. Please read “—Meetings; Voting.”

Limited Call Right

If at any time our general partner and its affiliates own more than 80% of our then-issued and outstanding limited partner interests of any class, our general partner will have the right, but not the obligation, to purchase all, but not less than all, of the remaining limited partners interests of the class at a price not less than the then current market price.

As a result of our general partner’s right to purchase outstanding limited partner interests, a holder of limited partner interests may have its limited partner interests purchased at an undesirable time or at a price that may be lower than market prices at various times prior to such purchase or lower than a unitholder may anticipate the market price to be in the future. The U.S. federal income tax consequences to a common unitholder of the exercise of this call right are the same as a sale by that unitholder of its common units in the market. Please read “Material U.S. Federal Income Tax Consequences—Disposition of Units.” In the event that our general partner or any affiliate of our general partner exercises its right to purchase all of the outstanding common units, it will result in the occurrence of a Cash COC Event (as defined in the Partnership Agreement Amendment).

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Meetings; Voting

For purposes of determining the limited partners entitled to notice of or to vote at a meeting of limited partners or to give approvals without a meeting, our general partner may set a record date, which shall not be less than 10 nor more than 60 days before (i) the date of the meeting (unless such requirement conflicts with any rule, regulation, guideline or requirement of any national securities exchange on which the limited partner interests are listed for trading, in which case the rule, regulation, guideline or requirement of such exchange shall govern) or (ii) in the event that approvals are sought without a meeting, the date by which limited partners are requested in writing by our general partner to give such approvals. Except as described below regarding a person or group owning 20% or more of any class of units then outstanding, record holders of units on the record date will be entitled to notice of, and to vote at, meetings of our limited partners and to act upon matters for which approvals may be solicited.

If authorized by our general partner, any action that may be taken at a meeting of the limited partners may be taken without a meeting if an approval in writing setting forth the action so taken is signed by limited partners owning not less than the minimum percentage of the outstanding limited partner interests (including limited partner interests deemed owned by our general partner) that would be necessary to authorize or take such action at a meeting at which all the limited partners were present and voted (unless such provision conflicts with any rule, regulation, guideline or requirement of any national securities exchange on which the limited partner interests are listed for trading, in which case the rule, regulation, guideline or requirement of such exchange shall govern). Special meetings of limited partners may be called by our general partner or by limited partners owning at least 20% of the outstanding partnership securities of the class or classes for which a meeting is proposed. Limited partners may vote either in person or by proxy at meetings. The holders of a majority of the outstanding partnership securities of the class or classes for which a meeting has been called (including limited partner interests deemed owned by our general partner), represented in person or by proxy, will constitute a quorum.

Each record holder of a unit has a vote according to its percentage interest in us, although additional limited partner interests having special voting rights could be issued. Please read “—Issuance of Additional Interests.” For a description of the voting rights of the Class A units, please read “—Limited Voting Rights.” However, if at any time any person or group, other than our general partner and its affiliates, or a direct or subsequently approved transferee of our general partner or its affiliates and purchasers specifically approved by our general partner, acquires, in the aggregate, beneficial ownership of 20% or more of any class of units then outstanding, that person or group will lose voting rights on all of its units and the units may not be voted on any matter and will not be considered to be outstanding when sending notices of a meeting of common unitholders, calculating required votes, determining the presence of a quorum or for other similar purposes. Units held in nominee or street name account will be voted by the broker or other nominee in accordance with the instruction of the beneficial owner unless the arrangement between the beneficial owner and its nominee provides otherwise. This loss of voting rights does not apply (i) (A) to any person or group that acquires the units directly from our general partner or its affiliates, (B) to any transferees of that person or group approved by our general partner or (C) to any person or group who acquires the units with the specific prior approval of our general partner, or (ii) (A) with respect to matters as to which the preferred units vote as a separate class and (B) with respect to matters as to which the preferred units vote together with the common units as a single class, provided that, such preferred unitholder would not beneficially own 20% or more of the common units, determined on an as-converted basis at the then-applicable Conversion Ratio. Notwithstanding anything to the contrary, with respect to any matter as to which the preferred units vote as a separate class, if at any time First Reserve acquires beneficial ownership of 20% or more the then outstanding preferred units, then none of such preferred units beneficially owned by First Reserve may be voted on such matter or be considered outstanding when calculating required votes or determining presence for a quorum; provided, however, that such restrictions shall no longer apply when First Reserve ceases to directly or indirectly, control our general partner.

Any notice, demand, request, report or proxy material required or permitted to be given or made to record common unitholders under our partnership agreement will be delivered to the record holder by us or by the transfer agent.

13

Status as Limited Partner

By transfer of common units in accordance with our partnership agreement, each transferee of common units shall be admitted as a limited partner with respect to the common units transferred when such transfer and admission are reflected in our books and records. Except as described above under “—Limited Liability,” the common units and preferred units will be fully paid, and common unitholders and preferred unitholders will not be required to make additional contributions.

14

EX-21.1

Exhibit 21.1

List of Subsidiaries of CRESTWOOD EQUITY PARTNERS LP AS OF FEBRUARY 10, 2020

Name	Jurisdiction
Arlington Storage Company, LLC	Delaware
Arrow Field Services, LLC	Delaware
Arrow Midstream Holdings, LLC	Delaware
Arrow Pipeline, LLC	Delaware
Arrow Water, LLC	Delaware
Arrow Water Services LLC	Delaware
Crestwood Corporation	Delaware
CMLP Tres Manager LLC	Delaware
CMLP Tres Operator LLC	Delaware
Cowtown Gas Processing Partners L.P.	Texas
Cowtown Pipeline Partners L.P.	Texas
CPB Bowser SWD #1 LLC	Delaware
CPB Bowser SWD #2 LLC	Delaware
CPB Member LLC	Delaware
CPB Operator LLC	Delaware
CPB Subsidiary Holdings LLC	Delaware
CPB Transportation & Marketing LLC	Delaware
CPB Water LLC	Delaware
Crestwood Appalachia Pipeline LLC	Texas
Crestwood Arkansas Pipeline LLC	Texas
Crestwood Canada Company	Nova Scotia
Crestwood Crude Logistics LLC	Delaware
Crestwood Crude Services LLC	Delaware
Crestwood Crude Terminals LLC	Delaware
Crestwood Crude Transportation LLC	Delaware
Crestwood Dakota Pipelines LLC	Delaware
Crestwood Delaware Basin LLC	Delaware
Crestwood Energy Services LLC	Delaware
Crestwood Gas Marketing LLC	Delaware
Crestwood Gas Services GP LLC	Delaware
Crestwood Gas Services Operating GP LLC	Delaware
Crestwood Gas Services Operating LLC	Delaware
Crestwood Infrastructure Holdings LLC	Delaware
Crestwood Marcellus Midstream LLC	Delaware
Crestwood Marcellus Pipeline LLC	Delaware
Crestwood Midstream Finance Corp.	Delaware
Crestwood Midstream GP LLC	Delaware
Crestwood Midstream Operations LLC	Delaware
Crestwood Midstream Partners LP	Delaware

Crestwood New Mexico Pipeline LLC	Texas
Crestwood Niobrara LLC	Delaware
Crestwood Ohio Midstream Pipeline LLC	Delaware
Crestwood Operations LLC	Delaware
Crestwood Panhandle Pipeline LLC	Texas
Crestwood Partners LLC	Delaware
Crestwood Permian Basin Holdings LLC	Delaware
Crestwood Permian Basin LLC	Delaware
Crestwood Pipeline and Storage Northeast LLC	Delaware
Crestwood Pipeline East LLC	Delaware
Crestwood Pipeline LLC	Texas
Crestwood Sales & Service Inc.	Delaware
Crestwood Services LLC	Delaware
Crestwood Storage Inc.	Delaware
Crestwood Transportation LLC	Delaware
E. Marcellus Asset Company, LLC	Delaware
Finger Lakes LPG Storage, LLC	Delaware
FR-Crestwood Management Co-Investment LLC	Delaware
IPCH Acquisition Corp.	Delaware
Jackalope Gas Gathering Services, L.L.C.	Oklahoma
Powder River Basin Industrial Complex, LLC	Delaware
PRB HoldCo LLC	Delaware
Stagecoach Gas Services LLC	Delaware
Stagecoach Operating Services LLC	Delaware
Stagecoach Pipeline & Storage Company LLC	New York
Stellar Propane Service, LLC	Delaware
Tres Palacios Gas Storage LLC	Delaware
Tres Palacios Holdings LLC	Delaware
Tres Palacios Midstream, LLC	Delaware

EX-23.1

Exhibit 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-8 No. 333-201534);

(2) Registration Statement (Form S-8 No. 333-148619);

(3) Registration Statement (Form S-8 No. 333-131767);

(4) Registration Statement (Form S-8 No. 333-83872);

(5) Registration Statement (Form S-3 No. 333-210146);

(6) Registration Statement (Form S-3 No.  333-217062);

(7) Registration Statement (Form S-3ASR No. 333-217061);

(8) Registration Statement (Form S-3 No. 333-223892); and

(9) Registration Statement (Form S-8 No. 333-227017).

of our reports dated February 21, 2020, with respect to the consolidated financial statements and schedules of Crestwood Equity Partners LP and the effectiveness of internal control over financial reporting of Crestwood Equity Partners LP included in this combined Annual Report (Form 10-K) of Crestwood Equity Partners LP and Crestwood Midstream Partners LP for the year ended December 31, 2019.

/s/ Ernst & Young LLP

Houston, Texas

February 21, 2020

EX-23.2

Exhibit 23.2

Consent of Independent Auditors

We consent to the incorporation by reference in the following Registration Statements:

(1) Registration Statement (Form S-8 No. 333-201534);

(2) Registration Statement (Form S-8 No. 333-148619);

(3) Registration Statement (Form S-8 No. 333-131767);

(4) Registration Statement (Form S-8 No. 333-83872);

(5) Registration Statement (Form S-3 No. 333-210146);

(6) Registration Statement (Form S-3 No.  333-217062);

(7) Registration Statement (Form S-3ASR No. 333-217061);

(8) Registration Statement (Form S-3 No. 333-223892); and

(9) Registration Statement (Form S-8 No. 333-227017).

of our report dated February 14, 2020, with respect to the consolidated financial statements of Stagecoach Gas Services LLC included in this combined Annual Report (Form 10-K) of Crestwood Equity Partners LP and Crestwood Midstream Partners LP for the year ended December 31, 2019.

/s/ Ernst & Young LLP

Houston, Texas

February 21, 2020

EX-31.1

Exhibit 31.1

CERTIFICATIONS

I, Robert G. Phillips, certify that:

1. I have reviewed this annual report on Form 10-K of Crestwood Equity Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 21, 2020

/s/ Robert G. Phillips

Robert G. Phillips

Chairman, President and Chief Executive Officer

EX-31.2

Exhibit 31.2

CERTIFICATIONS

I, Robert T. Halpin, certify that:

1. I have reviewed this annual report on Form 10-K of Crestwood Equity Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 21, 2020

/s/ Robert T. Halpin

Robert T. Halpin

Executive Vice President and Chief Financial Officer

EX-31.3

Exhibit 31.3

CERTIFICATIONS

I, Robert G. Phillips, certify that:

1. I have reviewed this annual report on Form 10-K of Crestwood Midstream Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 21, 2020

/s/ Robert G. Phillips

Robert G. Phillips

Chairman, President and Chief Executive Officer

EX-31.4

Exhibit 31.4

CERTIFICATIONS

I, Robert T. Halpin, certify that:

1. I have reviewed this annual report on Form 10-K of Crestwood Midstream Partners LP (the “registrant”);

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c. Evaluated the effectiveness of the registrant's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant's internal control over financial reporting that occurred during the registrant's most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant's internal control over financial reporting; and

5. The registrant's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant's auditors and the audit committee of the registrant's board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant's ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant's internal control over financial reporting.

Date: February 21, 2020

/s/ Robert T. Halpin

Robert T. Halpin

Executive Vice President and Chief Financial Officer

EX-32.1

Exhibit 32.1

Certification of the Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Crestwood Equity Partners LP (the “Company”) on Form 10-K for the period ended December 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert G. Phillips, Chief Executive Officer of Crestwood Equity Partners LP, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Robert G. Phillips
February 21, 2020	Robert G. Phillips Chief Executive Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

Exhibit 32.2

Certification of the Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Crestwood Equity Partners LP (the “Company”) on Form 10-K for the period ended December 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert T. Halpin, Chief Financial Officer of Crestwood Equity Partners LP, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Robert T. Halpin
February 21, 2020	Robert T. Halpin Chief Financial Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.3

Exhibit 32.3

Certification of the Chief Executive Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Crestwood Midstream Partners LP (the “Company”) on Form 10-K for the period ended December 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert G. Phillips, Chief Executive Officer of Crestwood Midstream Partners LP, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Robert G. Phillips
February 21, 2020	Robert G. Phillips Chief Executive Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.4

Exhibit 32.4

Certification of the Chief Financial Officer

Pursuant to 18 U.S.C. Section 1350

As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

In connection with the Annual Report of Crestwood Midstream Partners LP (the “Company”) on Form 10-K for the period ended December 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Robert T. Halpin, Chief Financial Officer of Crestwood Equity Partners LP, certify, pursuant to 18 U.S.C. § 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to his knowledge:

(1) The Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

(2) The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

	/s/ Robert T. Halpin
February 21, 2020	Robert T. Halpin Chief Financial Officer

A signed original of this written statement required by Section 906, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to the Company and will be retained by the Company and furnished to the Securities and Exchange Commission or its staff upon request.

EX-99.1

Exhibit 99.1

Stagecoach Gas Services LLC

Consolidated Financial Statements

As of December 31, 2019 and 2018 and

For the Years Ended December 31, 2019, 2018 and 2017

Exhibit 99.1

STAGECOACH GAS SERVICES LLC

TABLE OF CONTENTS

Report of Independent Auditors	3
Consolidated Financial Statements:
Consolidated Balance Sheets	4
Consolidated Statements of Operations	5
Consolidated Statements of Members' Equity	6
Consolidated Statements of Cash Flows	7
Notes to Consolidated Financial Statements	8

2

Exhibit 99.1

Report of Independent Auditors

The Management Committee

Stagecoach Gas Services LLC

We have audited the accompanying consolidated financial statements of Stagecoach Gas Services LLC, which comprise the consolidated balance sheets as of December 31, 2019 and 2018, and the related consolidated statements of operations, members’ equity and cash flows for each of the three years in the period ended December 31, 2019 and the related notes to the consolidated financial statements.

Management’s Responsibility for the Financial Statements

Management is responsible for the preparation and fair presentation of these financial statements in conformity with U.S. generally accepted accounting principles; this includes the design, implementation and maintenance of internal control relevant to the preparation and fair presentation of financial statements that are free of material misstatement, whether due to fraud or error.

Auditor’s Responsibility

Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the 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 involves performing procedures to obtain audit evidence about the amounts and disclosures in the financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the entity’s preparation and fair presentation of the financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the entity’s internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the financial statements referred to above present fairly, in all material respects, the consolidated financial position of Stagecoach Gas Services LLC at December 31, 2019 and 2018, and the consolidated results of its operations and its cash flows for each of the three years in the period ended December 31, 2019 in conformity with U.S. generally accepted accounting principles.

/s/ Ernst & Young LLP

Houston, TX  

February 14, 2020

3

Exhibit 99.1

STAGECOACH GAS SERVICES LLC CONSOLIDATED BALANCE SHEETS (in millions)
	December 31,
	2019		2018
Assets
Current assets:
Cash	$	32.1	$	31.9
Accounts receivable	11.0		11.2
Accounts receivable - related party	2.8		2.6
Inventory	1.7		1.5
Prepaid expenses	3.0		2.9
Total current assets	50.6		50.1
Property, plant and equipment	1,137.6		1,132.6
Less: accumulated depreciation	126.7		90.8
Property, plant and equipment, net	1,010.9		1,041.8
Intangible assets	53.3		53.4
Less: accumulated amortization	34.7		26.6
Intangible assets, net	18.6		26.8
Operating lease right-of-use assets, net	0.3		—
Goodwill	656.5		656.5
Total assets	$	1,736.9	$	1,775.2
Liabilities and members' equity
Current liabilities:
Accounts payable	$	0.7	$	1.3
Accounts payable - related party	0.1		0.7
Accrued expenses and other liabilities	3.1		2.2
Total current liabilities	3.9		4.2
Long-term operating lease liabilities	0.3		—
Other long-term liabilities	1.2		0.9
Members' equity	1,731.5		1,770.1
Total liabilities and members' equity	$	1,736.9	$	1,775.2

See accompanying notes.

4

Exhibit 99.1

STAGECOACH GAS SERVICES LLC CONSOLIDATED STATEMENTS OF OPERATIONS (in millions)
	Year Ended December 31,
	2019		2018		2017
Revenues:
Storage and transportation	$	128.6	$	140.1	$	134.7
Storage and transportation - related party	35.2		31.3		33.9
	163.8		171.4		168.6
Operating expenses:
Costs of services sold	11.5		9.9		6.5
Costs of services sold - related party	0.3		—		3.7
Operations and maintenance	20.5		18.6		17.2
Operations and maintenance - related party	3.4		3.4		3.4
General and administrative	0.2		0.2		0.2
General and administrative - related party	3.2		3.2		3.6
Depreciation and amortization	44.4		44.0		43.1
Loss on long-lived assets	0.1		—		—
	83.6		79.3		77.7
Other income, net	0.4		—		0.2
Net income	$	80.6	$	92.1	$	91.1

See accompanying notes.

5

Exhibit 99.1

STAGECOACH GAS SERVICES LLC CONSOLIDATED STATEMENTS OF MEMBERS' EQUITY (in millions)
	Crestwood Pipeline and Storage Northeast LLC			Con Edison Gas Pipeline and Storage Northeast, LLC			Total
Balance at December 31, 2016	$	922.3		$	932.2		$	1,854.5
Contributions from members	0.8			0.8			1.6
Distributions to members	(47.3		)	(87.8		)	(135.1		)
Net income	25.3			65.8			91.1
Balance at December 31, 2017	901.1			911.0			1,812.1
Distributions to members	(48.7		)	(85.4		)	(134.1		)
Net income	29.3			62.8			92.1
Balance at December 31, 2018	881.7			888.4			1,770.1
Contributions from members	2.1			2.1			4.2
Distributions to members	(52.3		)	(71.1		)	(123.4		)
Net income	34.2			46.4			80.6
Balance at December 31, 2019	$	865.7		$	865.8		$	1,731.5

See accompanying notes.

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Exhibit 99.1

STAGECOACH GAS SERVICES LLC CONSOLIDATED STATEMENTS OF CASH FLOWS (in millions)
	Year Ended December 31,
	2019			2018			2017
Operating activities
Net income	$	80.6		$	92.1		$	91.1
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	44.4			44.0			43.1
Loss on long-lived assets	0.1			—			—
Other	1.1			(0.2		)	(0.8		)
Changes in operating assets and liabilities:
Accounts receivable	—			0.6			(0.1		)
Inventory	(1.2		)	—			—
Prepaid expenses	(0.1		)	(0.2		)	0.1
Accounts payable	(1.4		)	1.5			(0.6		)
Accrued expenses and other liabilities	1.3			(3.3		)	1.1
Net cash provided by operating activities	124.8			134.5			133.9
Investing activities
Purchases of property, plant and equipment	(5.5		)	(4.5		)	(2.2		)
Net proceeds from sale of assets	0.1			—			—
Net cash used in investing activities	(5.4		)	(4.5		)	(2.2		)
Financing activities
Contributions from members	4.2			—			1.6
Distributions to members	(123.4		)	(134.1		)	(135.1		)
Net cash used in financing activities	(119.2		)	(134.1		)	(133.5		)
Net change in cash and restricted cash	0.2			(4.1		)	(1.8		)
Cash and restricted cash at beginning of period	31.9			36.0			37.8
Cash and restricted cash at end of period	$	32.1		$	31.9		$	36.0

See accompanying notes.

7

Exhibit 99.1

STAGECOACH GAS SERVICES LLC

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note 1 – Organization and Description of Business

Organization

Stagecoach Gas Services LLC (Stagecoach Gas or the Company) is a Delaware limited liability company owned equally by Crestwood Pipeline and Storage Northeast LLC (Crestwood Northeast), and Con Edison Gas Pipeline and Storage Northeast LLC (CEGP), a wholly-owned subsidiary of Consolidated Edison, Inc (Consolidated Edison). Crestwood Northeast is a wholly-owned subsidiary of Crestwood Midstream Partners LP (CMLP). Crestwood Equity Partners LP owns a 99.9% limited partnership interest in CMLP and its wholly-owned subsidiary owns the remaining 0.1% limited partnership interest as well as a non-economic general partnership interest in CMLP. Our members and their affiliates are not liable for the obligations of the Company.

Unless otherwise indicated, references in this report to “we,” “us,” or “our” and similar terms refer to either Stagecoach Gas itself or Stagecoach Gas and its consolidated subsidiaries, as the context requires.

Description of Business

We are a joint venture primarily engaged in the storage and transportation of natural gas for producers, utilities and other customers. Below is a description of our storage and transportation facilities located in New York and Pennsylvania.

Storage Facilities. We own and operate four storage facilities which are located near major shale plays and demand markets, have low maintenance costs and long useful lives. Our storage facilities have comparatively high cycle capabilities and their interconnectivity with interstate pipelines offer significant flexibility to our customers. Our natural gas storage facilities, each of which generates fee-based revenues and has a contracted capacity of 33.8 billion cubic feet of natural gas as of December 31, 2019, include:

• Stagecoach - a Federal Energy Regulatory Commission (FERC) certificated 26.2 Bcf multi-cycle, depleted reservoir storage facility.

• Thomas Corners - a FERC-certificated 7.0 Bcf multi-cycle, depleted reservoir storage facility.

• Seneca Lake - a FERC-certificated 1.5 Bcf multi-cycle, bedded salt storage facility.

• Steuben - a FERC-certificated 6.2 Bcf single-cycle, depleted reservoir storage facility.

Transportation Facilities. Our natural gas transportation facilities include:

• North-South Facilities - bi-directional interstate facilities which include compression and appurtenant facilities installed to expand transportation capacity on the Stagecoach north and south pipeline laterals. The North-South Facilities generate fee-based revenues under a negotiated rate structure authorized by the FERC.

• MARC I Pipeline - bi-directional intrastate natural gas pipeline that connects the North-South Facilities and Tennessee Gas Pipeline Company, LLC's 300 Line in Bradford County, Pennsylvania, with UGI Energy Services LLC's Sunbury Pipeline and Transcontinental Gas Pipeline Company LLC's Leidy Line both in Lycoming County, Pennsylvania. The MARC I Pipeline generates fee-based revenues under a negotiated rate structure authorized by the FERC.

• Twin Tier Pipeline (formerly East Pipeline) - an intrastate natural gas pipeline located in New York, which transports natural gas from Dominion Transmission Inc. to the Binghamton, New York city gate. The Twin Tier Pipeline generates fee-based revenues under a negotiated rate structure authorized by the New York State Public Service Commission.

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

Basis of Presentation

Our consolidated financial statements are prepared in accordance with United States generally accepted accounting principles (GAAP) and include the accounts of all consolidated subsidiaries after the elimination of all intercompany accounts and

8

transactions. In management’s opinion, all necessary adjustments to fairly present our results of operations, financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and recurring nature. We have evaluated subsequent events through the date our financial statements were available to be issued on February 14, 2020.

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.

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 storage and transportation operations consists primarily of spare parts. Our inventory is stated at the lower of cost or net realizable value and cost is computed predominantly using the average cost method.

Property, Plant and Equipment

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

	Years
Pipelines	20
Facilities and equipment	3 – 20
Buildings and other	20 – 40
Office furniture and fixtures	5 – 10
Vehicles	5

Included in our property, plant and equipment are storage rights, base gas and land, which are not subject to depreciation.

We evaluate our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset, which is typically based on discounted cash flow projections using assumptions as to revenues, costs and discount rates typical of third party market participants.

We have various obligations to remove property, plant and equipment on rights-of-way and leases for which we cannot currently estimate the fair value of those obligations because the associated assets have indeterminate lives. An asset retirement obligation liability (and related asset), if any, will be recorded for these obligations once sufficient information is available to reasonably estimate the fair value of the obligation.

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Identifiable Intangible Assets and Liabilities

Our identifiable intangible assets and liabilities consist of storage and transportation contracts contributed at the formation of the Company. We amortize these storage and transportation contracts based on the projected cash flows associated with the contracts if the projected cash flows are reliably determinable. We recognize intangible assets or liabilities separately if the benefit of the intangible asset or liability is obtained through contractual or other legal rights, or if the intangible asset or liability can be sold, transferred, licensed, rented or exchanged, regardless of the intent to do so. The weighted-average remaining life of our intangible assets and liabilities is approximately three years.

At December 31, 2019 and 2018, our net intangible asset related to our storage and transportation contracts was approximately $18.6 million and $26.8 million. Amortization expense related to our intangible assets for the years ended December 31, 2019, 2018 and 2017, was approximately $8.2 million, $8.7 million and $10.1 million. Our storage and transportation contracts which represent intangible liabilities were approximately $0.1 million as of December 31, 2018, and are included in other long-term liabilities on our consolidated balance sheet. During 2019, the intangible liabilities associated with our transportation contracts were fully amortized. For the years ended December 31, 2019, 2018 and 2017, we recorded a reduction of our depreciation and amortization expense of approximately $0.1 million, $0.5 million and $2.4 million related to our intangible liabilities.

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

Year Ending December 31,
2020	$	7.1
2021	$	6.1
2022	$	5.4
2023	$	—	(1)
2024	$	—	(1)

(1) Amount is less than $0.1 million.

Goodwill

Our goodwill represents the excess of the fair value of the Company over the fair value of the net assets contributed at the formation of the Company. We evaluate goodwill for impairment annually on December 31, and whenever events indicate that it is more likely than not that the fair value of the Company could be less than its carrying amount. This evaluation requires us to compare the fair value to the carrying value (including goodwill). If the fair value exceeds the carrying amount, goodwill is not considered impaired.

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

Leases

We have an agreement to lease a storage facility from a third-party. We do not have any other material leases where we are the lessee or the lessor. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants.

Prior to January 1, 2019, we classified our lease as an operating lease under Accounting Standards Codification (ASC) Topic 840, Leases (Topic 840), under which we did not recognize assets or liabilities on our consolidated balance sheets, but rather recognized lease payments on our consolidated statements of operations as operations and maintenance expense on a straight-line basis over the lease term.

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On January 1, 2019, we early adopted the provisions of ASC Topic 842, Leases (Topic 842), which revises the accounting for leases by requiring certain leases to be recognized as assets and liabilities on the balance sheet, and requiring companies to disclose additional information about their leasing arrangements. We adopted the standard using the modified retrospective method. Based on the practical expedients allowed for in the standard, we did not reassess the current GAAP classification of leases, easements and rights of way that existed as of January 1, 2019, and we did not utilize the hindsight method in determining the assets and liabilities to be recorded for our existing leases on January 1, 2019. The adoption of this standard required us to make significant judgments on whether our revenue and expenditure-related contracts were considered to be leases (or contain leases) under Topic 842, and if contracts were considered to be leases whether they should be considered operating leases or finance leases under the new standard. We do not have any material revenue contracts that are considered leases under Topic 842.

Upon the adoption of this standard, on January 1, 2019, we recorded a $0.3 million increase to our operating lease right-of-use

assets, a less than $0.1 million increase to our accrued expenses and other liabilities and a $0.3 million increase to our long-term operating lease liabilities, related to reflecting our operating lease on our consolidated balance sheet as a result of adopting the new standard.

Revenue Recognition

We provide transportation and storage services under various long-term capacity contracts and short-term hub service contracts. Under these contracts, we do not take title to the underlying natural gas but charge a fixed-fee for the services we provide based on the volumes transported and/or stored.

On January 1, 2018, we early adopted the provisions of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. We adopted the standard using the modified retrospective method for all revenue contracts that involve revenue generating activities that occur after January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under the new standard, while amounts prior to January 1, 2018 continue to be reported in accordance with our historic accounting under Revenue Recognition (Topic 605). The adoption of Topic 606 did not have a material impact to our consolidated financial statements.

Prior to January 1, 2018, we recognized revenues for services when all of the following criteria were met under Topic 605: (i) storage, transportation and storage-related services had been rendered; (ii) persuasive evidence of an exchange arrangement existed; (iii) the price for services was fixed or determinable; and (iv) collectability was reasonably assured. We recorded deferred revenue when we received amounts from our customer but had not yet met the criteria listed above. We recognized deferred revenue in our consolidated statement of operations when the criteria had been met and all services had been rendered.

Beginning January 1, 2018, we recognize revenues for services under our revenue contracts as our obligations to perform services under the contracts are satisfied. A contract’s transaction price is allocated to each performance obligation in the contract and recognized as revenue when, or as, the performance obligation is satisfied. Our fixed-fee contracts primarily have a single performance obligation to deliver a series of distinct services that are substantially the same and have the same pattern of transfer to our customers. For performance obligations associated with these contracts, we recognize revenues over time utilizing the output method based on the actual volumes of services performed, because the single performance obligation is satisfied over time using the same performance measure of progress toward satisfaction of the performance obligation. The transaction price under certain of our fixed-price contracts includes variable consideration that varies primarily based on actual volumes that are delivered under the contracts. Because the variable consideration specifically relates to our efforts to transfer the services under the contracts, we allocate the variable consideration entirely to the distinct service utilizing the allocation exception guidance under Topic 606, and accordingly recognize the variable consideration as revenues at the time the service is performed for the customers.

The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our performance obligations requires significant judgment and assumptions, including our evaluation of the timing of when control of the underlying service has transferred to our customers. Actual results can significantly vary from those judgments and assumptions. Our contracts do not contain multiple performance obligations and we did not receive any material non-cash consideration during the years ended December 31, 2019 and 2018.

Income Taxes

Stagecoach Gas is a limited liability company. A limited liability company can be treated as a partnership for income tax purposes and therefore, is generally not subject to federal income tax. In addition, federal and state income taxes are provided

11

on the earnings of subsidiaries incorporated as taxable entities. For 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.

Net earnings for financial statement purposes may differ significantly from taxable income reportable to members as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the limited liability company agreement.

Uncertain Tax Positions. We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Such tax positions, if any, would be recorded as a tax benefit or expense in the current year. We believe that there were no uncertain tax positions that would impact our results of operations for the years ended December 31, 2019, 2018 and 2017. However, our conclusions regarding the evaluation are subject to review and may change based on factors including, but not limited to, ongoing analysis of tax laws, regulations and interpretations thereof.

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 sheet 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. At December 31, 2019 and 2018, we had no amounts accrued for environmental or other contingencies.

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.

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.

The following table represents customers which accounted for more than 10% of our total consolidated revenues for the years ended December 31, 2019, 2018 and 2017:

	Year Ended December 31,
	2019		2018		2017
Customer:
Consolidated Edison	20	%	18	%	20	%
Southwestern Energy Services Company	12	%	13	%	12	%
Chesapeake Energy Marketing Inc.	11	%	10	%	10	%
Alta Energy Marketing (1)	11	%	11	%	—	%

(1) For the year ended December 31, 2017, Alta Energy Marketing did not account for more than 10% of our total consolidated revenues.

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New Accounting Pronouncement Issued But Not Yet Adopted

In June 2016, the Financial Accounting Standards Board issued Accounting Standards Update (ASU) 2016-13, Financial Instruments - Credit Losses (Topic 326), which provides guidance on how companies should evaluate their accounts and notes receivable and other financial instruments for impairment. The standard requires companies to evaluate their financial instruments for impairment by recording an allowance for doubtful accounts and/or bad debt expense based on certain categories of instruments rather than a specific identification approach. We do not anticipate that the adoption of this standard will have a material impact on our consolidated financial statements.

Note 3 – Certain Balance Sheet Information

Property, Plant and Equipment

Property, plant and equipment consisted of the following at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Pipelines	$	460.8	$	460.2
Facilities and equipment	172.8		170.9
Buildings, land and storage rights	479.6		479.2
Construction in process	3.0		3.6
Base gas	18.0		16.7
Other (1)	3.4		2.0
	1,137.6		1,132.6
Less: accumulated depreciation	126.7		90.8
Total property, plant and equipment, net	$	1,010.9	$	1,041.8

(1) Includes office furniture and fixtures and vehicles.

Depreciation expense totaled $36.3 million, $35.8 million and $35.5 million at December 31, 2019, 2018 and 2017.

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Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Accrued expenses	$	2.5	$	1.5
Customer deposits	0.6		0.6
Deferred revenue	—		0.1
Total accrued expenses and other liabilities	$	3.1	$	2.2

Note 4 - Commitments and Contingencies

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. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures for which we can estimate would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning contingencies, we reassess our position with respect to both 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. At December 31, 2019 and 2018, we had no amounts accrued for outstanding legal matters.

Note Payable. Our non-interest bearing obligation consists of a noncompetition agreement between us and the seller of a business we acquired in 2007, with payments due through 2027 and imputed interest of 8.00%. At December 31, 2019 and 2018, our non-interest bearing obligation was approximately $0.8 million and $0.9 million, less an unamortized discount based on imputed interest of $0.2 million for both periods. The aggregate maturity of the principal amount on our note payable for each of the years ended December 31, 2020 through December 31, 2024 is $0.1 million and $0.3 million in total thereafter.

Operating Lease. At December 31, 2019, our operating lease right-of-use asset, net was approximately $0.3 million. At December 31, 2019, our operating lease liability was approximately $0.3 million of which less than $0.1 million is classified as current and included in accrued expenses and other liabilities on our consolidated balance sheet.

We recognize operating lease expense over the term of the lease. For the year ended December 31, 2019, we recorded less than $0.1 million of lease expense. Future minimum lease liabilities under Topic 842 for each of the years ended December 31, 2020 through December 31, 2024 is less than $0.1 million and approximately $0.1 million in total thereafter.

Note 5 - Related Party Transactions

We enter into transactions with our affiliates within the ordinary course of business, including storage and transportation services under long-term contracts, product purchases and sells and other operating agreements. During the year ended December 31, 2019, we recognized revenues of approximately $1.8 million related to the sale of natural gas to a subsidiary of CMLP. Below is a description of our related party agreements.

Storage and Transportation Agreements. We have a storage and transportation agreement with Consolidated Edison that extends through March 2021. The agreement provides for firm storage capacity of 7.2 Bcf and daily transportation rights of 0.1 Bcf. We recognized revenues of $33.4 million, $31.3 million and $33.9 million under this agreement for the years ended December 31, 2019, 2018 and 2017.

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In October 2018, we entered into a transportation agreement with Consolidated Edison that extends through December 2023. The agreement provides for the purchase of capacity from Consolidated Edison on a fixed-fee basis. We incurred costs of services sold of approximately $0.3 million for the year ended December 31, 2019.

Management Agreement. We have a management agreement with Crestwood Midstream Operations LLC, a subsidiary of CMLP, pursuant to which they will manage the day to day operations of our business in addition to providing management, commercial and administrative services. The agreement is for an initial term through May 31, 2021 and is automatically extended for successive three year periods unless otherwise terminated by either party. Under the agreement, we reimburse all costs incurred in connection with management services provided to us. For each of the years ended December 31, 2019, 2018 and 2017, we incurred operations and maintenance expenses of $3.4 million under this management agreement. In addition, we incurred general and administrative expenses of $3.2 million during each of the years ended December 31, 2019 and 2018, and $3.6 million for the year ended December 31, 2017 under this agreement.

Electricity Agreement. We have an electricity sales agreement with a subsidiary of Consolidated Edison under which we purchase electricity supply on a fixed-fee basis for use at our compressor stations in Pennsylvania. For the year ended December 31, 2017, we incurred costs of services sold of approximately $3.7 million under this agreement. As of December 2017, this contract was sold by Consolidated Edison, and as such, is no longer considered a related party expense.

Note 6 - Members’ Equity

Contributions. During the years ended December 31, 2019 and 2017, we received contributions from our members of approximately $4.2 million and $1.6 million. We did not receive any contributions from our members during the year ended December 31, 2018.

Distributions. Our amended limited liability company agreement requires that within 30 days following the end of each quarter, we make quarterly distributions of our available cash (as defined in our amended limited liability company agreement) to Crestwood Northeast and CEGP based on their respective 50% ownership interest in us effective July 1, 2019. Prior to July 1, 2019, we distributed our available cash to Crestwood Northeast and CEGP based on distribution percentages of 40% and 60%, respectively, and prior to July 1, 2018, our quarterly cash distributions to Crestwood Northeast and CEGP were based on distribution percentages of 35% and 65%, respectively. During the years ended December 31, 2019, 2018 and 2017, we made cash distributions of approximately $123.4 million, $134.1 million and $135.1 million to our members. In January 2020, we made a cash distribution of approximately $31.0 million to our members.

Net Income or Loss Allocation. Pursuant to our Amended Agreement and prior to July 1, 2019, we allocated net income or loss to our members using the Hypothetical Liquidation at Book Value (HLBV) method because our members' ownership and distribution percentages differed. Under the HLBV method, a calculation was prepared at each balance sheet date to determine the amount that our members would receive if we were to liquidate all of our assets, as valued in accordance with GAAP, and distribute that cash to our members. The difference between the calculated liquidation distribution amounts at the beginning and end of the reporting period, after adjusting for capital contributions and distributions, was our members' respective share of our earnings or losses for the period, which approximated how we allocated earnings under the terms of our amended limited liability company agreement.

Note 7- Revenues

Topic 606 Receivables and Contract Liabilities. Amounts due from our customers under our revenue contracts are primarily billed at the end of each month and are due within 10 days of billing. Our receivables related to our Topic 606 revenue contracts totaled approximately $13.5 million at both December 31, 2019 and 2018, and are included in accounts receivable and accounts receivable - related party on our consolidated balance sheets. Our contract liabilities primarily consist of current and non-current deferred revenues. On our consolidated balance sheet, our current deferred revenues are included in accrued expenses and other liabilities and our non-current deferred revenues are included in other long-term liabilities. The majority of revenues associated with our deferred revenues is expected to be recognized as the performance obligations under the related contracts are satisfied over the next 15 years. At December 31, 2019, our current and non-current deferred revenues were less than $0.1 million and $0.5 million, respectively. At December 31, 2018, our current deferred revenues were approximately $0.1 million. We did not have non-current deferred revenues at December 31, 2018. The change in our contract liabilities during the year ended December 31, 2019 primarily related to capital reimbursements associated with a revenue contract.

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Performance Obligations. The following table summarizes the transaction price allocated to our remaining performance obligations that has not been recognized as of December 31, 2019 (in millions):

2020	$	108.5
2021	92.5
2022	81.2
2023	12.2
2024	0.4
Thereafter	0.1
Total	$	294.9

Our remaining performance obligations generally exclude, based on the following practical expedients that we elected to apply, disclosures for (i) variable consideration allocated to a wholly-unsatisfied promise to transfer a distinct service that forms part of the identified single performance obligation; (ii) unsatisfied performance obligations where the contract term is one year or less; and (iii) contracts for which we recognize revenues as amounts are invoiced.

Disaggregation of Revenues. The following table summarizes our revenue from contracts with customers disaggregated by type of service for the years ended December 31, 2019 and 2018 (in millions). We believe this summary best depicts how the nature, amount, timing and uncertainty of our revenues and cash flows are affected by economic factors.

	Year Ended December 31,
	2019		2018
Natural gas storage	$	56.9	$	59.7
Natural gas transportation	103.7		108.5
Total Topic 606 revenues	160.6		168.2
Non-Topic 606 revenues	3.2		3.2
Total revenues	$	163.8	$	171.4

16

XML

Certain Balance Sheet Information (Property, Plant And Equipment) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 3,612.5	$ 2,598.1
Less: accumulated depreciation	703.4	568.4
Property, plant and equipment, net	2,909.1	2,029.7
Capitalized interests	14.4	5.0	$ 2.9
Finance Lease, Right-of-Use Asset	9.5
Capital Leases, Balance Sheet, Assets by Major Class, Net		9.7
Crestwood Equity Partners LP
Property, Plant and Equipment [Line Items]
Property, plant and equipment	3,612.5	2,598.1
Less: accumulated depreciation	703.4	568.4
Property, plant and equipment, net	2,909.1	2,029.7
Depreciation	139.5	123.6	135.9
Crestwood Equity Partners LP | Gathering systems and pipelines and related assets
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,017.8	758.6
Crestwood Equity Partners LP | Facilities and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,797.7	1,230.7
Crestwood Equity Partners LP | Buildings, land, rights-of-way, storage rights and easements
Property, Plant and Equipment [Line Items]
Property, plant and equipment	370.6	331.7
Crestwood Equity Partners LP | Vehicles
Property, Plant and Equipment [Line Items]
Property, plant and equipment	27.7	17.9
Crestwood Equity Partners LP | Construction in process
Property, Plant and Equipment [Line Items]
Property, plant and equipment	368.7	230.8
Crestwood Equity Partners LP | Office furniture and fixtures
Property, Plant and Equipment [Line Items]
Property, plant and equipment	30.0	28.4
CMLP
Property, Plant and Equipment [Line Items]
Property, plant and equipment	3,942.6	2,928.2
Less: accumulated depreciation	875.1	725.9
Property, plant and equipment, net	3,067.5	2,202.3
Depreciation	153.5	137.7	$ 150.0
CMLP | Gathering systems and pipelines and related assets
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,160.6	901.5
CMLP | Facilities and equipment
Property, Plant and Equipment [Line Items]
Property, plant and equipment	1,982.8	1,415.9
CMLP | Buildings, land, rights-of-way, storage rights and easements
Property, Plant and Equipment [Line Items]
Property, plant and equipment	374.3	335.4
CMLP | Vehicles
Property, Plant and Equipment [Line Items]
Property, plant and equipment	26.0	16.1
CMLP | Construction in process
Property, Plant and Equipment [Line Items]
Property, plant and equipment	368.7	230.8
CMLP | Office furniture and fixtures
Property, Plant and Equipment [Line Items]
Property, plant and equipment	$ 30.2	$ 28.5

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Consolidated Statements of Operations - USD ($) shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Revenues	$ 3,181.9	$ 3,654.1	$ 3,880.9
Costs of product/services sold (exclusive of items shown separately below):
Product costs - related party (Note 16)	45.4	134.7	15.3
Total costs of products/services sold	2,544.9	3,129.4	3,374.7
Operating expenses and other:
Operations and maintenance	138.8	125.8	136.0
General and administrative	103.4	88.1	96.5
Depreciation, amortization and accretion	195.8	168.7	191.7
Loss on long-lived assets, net	6.2	28.6	65.6
Gain on acquisition	(209.4)	0.0	0.0
Goodwill impairment	0.0	0.0	38.8
Loss on contingent consideration	0.0	0.0	57.0
Total expenses	234.8	411.2	585.6
Operating income (loss)	402.2	113.5	(79.4)
Earnings from unconsolidated affiliates, net	32.8	53.3	47.8
Interest and debt expense, net	(115.4)	(99.2)	(99.4)
Loss on modification/extinguishment of debt	0.0	(0.9)	(37.7)
Other income, net	0.6	0.4	1.3
Income (loss) before income taxes	320.2	67.1	(167.4)
(Provision) benefit for income taxes	(0.3)	(0.1)	0.8
Net income (loss)	319.9	67.0	(166.6)
Net income attributable to non-controlling partner	34.8	16.2	25.3
Net income (loss) attributable to parent	285.1	50.8	(191.9)
Net income attributable to preferred units	60.1	60.1	62.5
Net income (loss) attributable to partners	225.0	(9.3)	(254.4)
Subordinated unitholders’ interest in net income	1.4	0.0	0.0
Common unitholders’ interest in net income (loss)	$ 223.6	$ (9.3)	$ (254.4)
Net income (loss) per limited partner unit:
Basic (dollars per unit)	$ 3.11	$ (0.13)	$ (3.64)
Diluted (dollars per unit)	$ 2.93	$ (0.13)	$ (3.64)
Weighted-average limited partners’ units outstanding:
Basic (units)	71.8	71.2	69.8
Dilutive units (units)	5.1	0.0	0.0
Diluted (units)	76.9	71.2	69.8
CMLP
Revenues:
Revenues	$ 3,181.9	$ 3,654.1	$ 3,880.9
Costs of product/services sold (exclusive of items shown separately below):
Product costs - related party (Note 16)	45.4	134.7	15.3
Total costs of products/services sold	2,544.9	3,129.4	3,374.7
Operating expenses and other:
Operations and maintenance	138.8	125.8	136.0
General and administrative	98.2	83.5	93.1
Depreciation, amortization and accretion	209.9	181.4	202.7
Loss on long-lived assets, net	6.2	28.6	65.6
Gain on acquisition	(209.4)	0.0	0.0
Goodwill impairment	0.0	0.0	38.8
Loss on contingent consideration	0.0	0.0	57.0
Total expenses	243.7	419.3	593.2
Operating income (loss)	393.3	105.4	(87.0)
Earnings from unconsolidated affiliates, net	32.8	53.3	47.8
Interest and debt expense, net	(115.4)	(99.2)	(99.4)
Loss on modification/extinguishment of debt	0.0	(0.9)	(37.7)
Other income, net	0.2	0.0	0.8
Income (loss) before income taxes	310.9	58.6	(175.5)
(Provision) benefit for income taxes	(0.3)	0.0	0.0
Net income (loss)	310.6	58.6	(175.5)
Net income attributable to non-controlling partner	34.8	16.2	25.3
Net income (loss) attributable to parent	275.8	42.4	(200.8)
Service
Revenues:
Revenues	426.6	344.4	418.7
Related party (Note 16)	0.0	1.0	1.8
Costs of product/services sold (exclusive of items shown separately below):
Product and service costs	29.8	44.2	49.9
Service | CMLP
Revenues:
Revenues	426.6	344.4	418.7
Related party (Note 16)	0.0	1.0	1.8
Costs of product/services sold (exclusive of items shown separately below):
Product and service costs	29.8	44.2	49.9
Product
Revenues:
Revenues	2,755.3	3,309.7	3,462.2
Related party (Note 16)	2.9	0.0	0.0
Costs of product/services sold (exclusive of items shown separately below):
Product and service costs	2,469.7	2,950.5	3,309.5
Product | CMLP
Revenues:
Revenues	2,755.3	3,309.7	3,462.2
Related party (Note 16)	2.9	0.0	0.0
Costs of product/services sold (exclusive of items shown separately below):
Product and service costs	2,469.7	2,950.5	3,309.5
Gathering and Processing Segment | Service
Revenues:
Revenues	380.0	276.1	317.3
Gathering and Processing Segment | Service | CMLP
Revenues:
Revenues	380.0	276.1	317.3
Gathering and Processing Segment | Product
Revenues:
Revenues	455.8	670.5	1,369.1
Gathering and Processing Segment | Product | CMLP
Revenues:
Revenues	455.8	670.5	1,369.1
Marketing Supply and Logistics
Revenues:
Revenues		2,690.3
Marketing Supply and Logistics | Service
Revenues:
Revenues	26.2	50.2	62.4
Marketing Supply and Logistics | Service | CMLP
Revenues:
Revenues	26.2	50.2	62.4
Marketing Supply and Logistics | Product
Revenues:
Revenues	2,296.6	2,639.2	2,093.1
Marketing Supply and Logistics | Product | CMLP
Revenues:
Revenues	2,296.6	2,639.2	2,093.1
Storage and Transportation | Service
Revenues:
Revenues	20.4	17.1	37.2
Storage and Transportation | Service | CMLP
Revenues:
Revenues	$ 20.4	$ 17.1	$ 37.2

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Basis of Presentation and Summary of Significant Accounting Policies (Remaining Performance Obligations) (Details) $ in Millions	Dec. 31, 2019 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, expected timing of satisfaction, period	17 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, amount	$ 99.4
Revenue, remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, amount	$ 86.2
Revenue, remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, amount	$ 79.3
Revenue, remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, amount	$ 3.3
Revenue, remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, amount	$ 275.6

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Organization and Description of Business

12 Months Ended

Dec. 31, 2019

Disclosure Partnership Organization And Basis Of Presentation Narrative [Abstract]

Organization and Description of Business

Organization and Description of Business

The accompanying notes to the consolidated financial statements apply to Crestwood Equity Partners LP (the Company, Crestwood Equity or CEQP) and Crestwood Midstream Partners LP (Crestwood Midstream or CMLP) unless otherwise indicated.

Organization

Crestwood Equity Partners LP. CEQP is a publicly-traded (NYSE: CEQP) Delaware limited partnership formed in March 2001. Crestwood Equity GP LLC, which is indirectly owned by Crestwood Holdings LLC (Crestwood Holdings), owns our non-economic general partnership interest. Crestwood Holdings, which is substantially owned and controlled by First Reserve Management, L.P. (First Reserve), also owns approximately 25% of Crestwood Equity’s common units and all of its subordinated units.

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

The diagram below reflects a simplified version of our ownership structure as of December 31, 2019:

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

Description of Business

Crestwood Equity develops, acquires, owns or controls, and operates primarily fee-based assets and operations within the energy midstream sector. We provide broad-ranging infrastructure solutions across the value chain to service premier liquids-rich natural gas and crude oil shale plays across the United States. We own and operate a diversified portfolio of crude oil and natural gas gathering, processing, storage and transportation assets that connect fundamental energy supply with energy demand across the United States. Crestwood Equity is a holding company and all of its consolidated operating assets are owned by or through its wholly-owned subsidiary, Crestwood Midstream.

Our financial statements reflect three operating and reporting segments described below.

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

• Storage and Transportation. Our storage and transportation (S&T) operations provide crude oil and natural gas storage and transportation services to producers, utilities and other customers. This segment primarily includes (i) the COLT Hub which consists of our integrated crude oil loading, storage and pipeline terminal located in the heart of the Bakken and Three Forks Shale oil-producing areas in Williams County, North Dakota; and (ii) joint ventures that own regulated natural gas storage and transportation facilities in New York and Pennsylvania, natural gas storage facilities in Texas and a crude-by-rail terminal in Wyoming.

•

Marketing, Supply and Logistics. Our marketing, supply and logistics (MS&L) operations provide NGL, crude oil and natural gas marketing, storage and transportation services to producers, refiners, marketers and other customers. This segment primarily includes (i) our fleet of rail and rolling stock, which includes our rail-to-truck NGL terminals located in Florida, New Jersey, New York, Rhode Island, North Carolina and Connecticut, and our truck maintenance facilities located in North Dakota, Indiana, West Virginia and New Jersey; (ii) our Bath and Seymour NGL storage facilities located in New York and Indiana; and (iii) our crude oil transportation assets.

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Equity Plans (Narrative) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Feb. 10, 2020
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 45,100,000	$ 24,300,000	$ 22,400,000
Employer matching contribution, percent	6.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Percent	10.00%
Defined Contribution Plan, Maximum Annual Contributions Per Employee, Amount	$ 25,000
Common Stock, Shares Authorized	1,500,000
Unit Purchase Plan, Shares Purchased Under Plan	6,341	0
Crestwood Long-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation costs not yet recognized	$ 34,600,000	$ 28,000,000.0
Common units to satisfy employee tax withholding obligations	336,548	221,576	206,600
Equity Securities
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Compensation expense	$ 4,600,000
Subsequent Event | Crestwood Long-Term Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for future issuance				2,593,885
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier	50.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Performance multiplier	200.00%

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Long-Term Debt (Narrative) (Details) - USD ($)	1 Months Ended		12 Months Ended
	Apr. 30, 2019	Mar. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 09, 2019	Apr. 08, 2019
Debt Instrument [Line Items]
Amount of Restricted Net Assets for Consolidated and Unconsolidated Subsidiaries			$ 2,099,300,000
Gains (Losses) on Extinguishment of Debt			0	$ (900,000)	$ (37,700,000)
Debt Issuance Costs, Net			29,100,000	26,400,000
CMLP
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt			$ 0	(900,000)	(37,700,000)
Revolving Loan Facility | CMLP
Debt Instrument [Line Items]
Debt Instrument, Term			5 years
Credit agreement outstanding carrying value			$ 1,250,000,000	1,500,000,000
Crestwood Midstream Revolver
Debt Instrument [Line Items]
Gains (Losses) on Extinguishment of Debt			$ 900,000
2023 Senior Notes | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage			6.25%
2023 Senior Notes | Crestwood Midstream 2022 senior unsecured notes
Debt Instrument [Line Items]
Carrying amount			$ 700,000,000.0	700,000,000.0
2023 Senior Notes | Crestwood Midstream 2022 senior unsecured notes | CMLP
Debt Instrument [Line Items]
Carrying amount			695,100,000	693,600,000
2025 Senior Notes | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Interest rate, stated percentage		5.75%
2025 Senior Notes | Crestwood Midstream 2019 Senior Notes | CMLP
Debt Instrument [Line Items]
Proceeds from Issuance of Debt		$ 492,000,000
2025 Senior Notes | Crestwood Midstream 2022 senior unsecured notes
Debt Instrument [Line Items]
Carrying amount			500,000,000.0	500,000,000.0
2025 Senior Notes | Crestwood Midstream 2022 senior unsecured notes | CMLP
Debt Instrument [Line Items]
Carrying amount			494,400,000	493,400,000
2027 Senior Notes | CMLP
Debt Instrument [Line Items]
Carrying amount			592,100,000	0
2027 Senior Notes | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Carrying amount	$ 600,000,000		600,000,000.0	0
Interest rate, stated percentage	5.625%
2027 Senior Notes | Crestwood Midstream 2019 Senior Notes | CMLP
Debt Instrument [Line Items]
Proceeds from Issuance of Debt	$ 591,100,000
Crestwood Midstream Credit Facility
Debt Instrument [Line Items]
Line of Credit Facility, Additional Potential Capacity			350,000,000.0
Line of Credit Facility, Current Borrowing Capacity			350,000,000.0
Crestwood Midstream Credit Facility | Minimum
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Amount			0.0025
Crestwood Midstream Credit Facility | Maximum
Debt Instrument [Line Items]
Line of Credit Facility, Commitment Fee Amount			$ 0.0045
Senior Notes, 2022
Debt Instrument [Line Items]
Debt Issuance Costs, Net					6,800,000
Repayments of Senior Debt					457,800,000
Senior Notes, 2022 | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Interest Paid, Including Capitalized Interest, Operating and Investing Activities					1,000,000.0
Senior Notes, 2020
Debt Instrument [Line Items]
Repayments of Senior Debt					349,900,000
Senior Notes, 2020 | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Interest Paid, Including Capitalized Interest, Operating and Investing Activities					$ 5,100,000
Crestwood Midstream Revolver
Debt Instrument [Line Items]
Consolidated leverage ratio, maximum			5.50
Crestwood Midstream Revolver | Revolving Credit Facility
Debt Instrument [Line Items]
Credit agreement outstanding carrying value			$ 557,000,000.0	578,200,000
Letters of credit outstanding			$ 31,700,000	$ 68,000,000.0
Total funded debt to consolidated EBITDA			4.13
Consolidated EBITDA to consolidated interest expense			4.47
Senior Secured Leverage Ratio			0.98
Weighted average interest rate			4.00%	4.79%
Unused borrowing capacity			$ 661,300,000
Interest coverage ratio, minimum			2.50
Senior Secured Leverage Ratio, maximum			3.75
Line of Credit Facility, Increase (Decrease), Net	$ 250,000,000
Crestwood Midstream Revolver | Revolving Credit Facility | Minimum
Debt Instrument [Line Items]
Weighted average interest rate			3.96%	4.63%
Crestwood Midstream Revolver | Revolving Credit Facility | Maximum
Debt Instrument [Line Items]
Weighted average interest rate			6.00%	6.75%
Crestwood Midstream Revolver | Bridge Loan
Debt Instrument [Line Items]
Credit agreement outstanding carrying value			$ 25,000,000.0
Obligations Under Noncompetition Agreements And Notes To Former Owners Of Businesses Acquired | CMLP
Debt Instrument [Line Items]
Total payments due			700,000	$ 1,700,000
Obligations under noncompete agreements, unamortized discount			$ 100,000	$ 200,000
Obligations Under Noncompetition Agreements And Notes To Former Owners Of Businesses Acquired | Minimum | CMLP
Debt Instrument [Line Items]
Inputed interest			5.02%
Obligations Under Noncompetition Agreements And Notes To Former Owners Of Businesses Acquired | Maximum | CMLP
Debt Instrument [Line Items]
Inputed interest			6.75%
Federal Funds Rate | Revolving Credit Facility | Crestwood Midstream Revolver
Debt Instrument [Line Items]
Variable interest rate			0.50%
Eurodollar [Member] | Revolving Credit Facility | Crestwood Midstream Credit Facility | Minimum
Debt Instrument [Line Items]
Variable interest rate			1.50%
Eurodollar [Member] | Revolving Credit Facility | Crestwood Midstream Credit Facility | Maximum
Debt Instrument [Line Items]
Variable interest rate			2.50%
Eurodollar [Member] | Revolving Credit Facility | Crestwood Midstream Revolver
Debt Instrument [Line Items]
Variable interest rate			1.00%
Eurodollar [Member] | Revolving Credit Facility | Crestwood Midstream Revolver | Minimum
Debt Instrument [Line Items]
Variable interest rate			0.50%
Eurodollar [Member] | Revolving Credit Facility | Crestwood Midstream Revolver | Maximum
Debt Instrument [Line Items]
Variable interest rate			1.50%
Jackalope Gas Gathering Services, LLC
Debt Instrument [Line Items]
Equity Interest	50.00%		50.00%
Equity method ownership percentage	50.00%		0.00%			50.00%	50.00%

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Partners' Capital (Schedule of Issuance of Units) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Partners' Capital [Abstract]
Issuance of common units (in units)	0	0	633,271
Proceeds from Issuance or Sale of Equity		$ 15.2
Units	72,282,942	71,659,385

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Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Purchases of property, plant and equipment	$ 455.5	$ 305.5	$ 188.4
Related Parties Amount in Cost of Sales	45.4	134.7	15.3
Related Party Transaction, Due from (to) Related Party [Abstract]
Related Party Transaction, Expenses from Transactions with Related Party	25.9	28.7	22.3
Applied Consultants, Inc.
Related Party Transaction [Line Items]
Purchases of property, plant and equipment	9.9	7.2
Affiliated Entity
Related Party Transaction [Line Items]
Revenues at CEQP and CMLP	2.9	1.0	1.8
Related Parties Amount in Cost of Sales	45.4	134.7	15.3
General and administrative expenses charged by CEQP to CMLP, net(3)	41.4	20.7	19.4
Crestwood Permian Basin Holdings LLC
Related Party Transaction [Line Items]
Related Parties Amount in Cost of Sales	19.0	56.1
Ascent Resources - Utica, LLC
Related Party Transaction [Line Items]
Related Parties Amount in Cost of Sales	23.9	78.6
Blue Racer Midstream, LLC
Related Party Transaction [Line Items]
Related Parties Amount in Cost of Sales	0.2
Stagecoach Gas Services LLC
Related Party Transaction [Line Items]
Related Parties Amount in Cost of Sales	2.3
Sabine Oil and Gas
Related Party Transaction [Line Items]
Related Parties Amount in Cost of Sales			15.3
CMLP
Related Party Transaction [Line Items]
Purchases of property, plant and equipment	455.5	305.5	188.4
Related Parties Amount in Cost of Sales	45.4	134.7	15.3
CMLP | Affiliated Entity
Related Party Transaction [Line Items]
General and administrative expenses charged by CEQP to CMLP, net(3)	3.7	3.6	3.0
Related Party Transaction, Due from (to) Related Party [Abstract]
Accounts payable at CEQP	13.1	13.6
Crestwood Equity Partners LP
Related Party Transaction [Line Items]
Related Party Transaction, (Income) Expenses from Transactions with Related Party	(0.6)	(2.7)	(1.7)
Crestwood Equity Partners LP | Affiliated Entity
Related Party Transaction, Due from (to) Related Party [Abstract]
Accounts receivable at CEQP and CMLP	7.3	4.1
Accounts payable at CEQP	15.6	16.1
Crestwood Long-Term Incentive Plan | CMLP
Related Party Transaction [Line Items]
Allocated share based compensation expense	45.1	24.3	22.4
Crestwood Long-Term Incentive Plan | Crestwood Holdings
Related Party Transaction [Line Items]
Allocated share based compensation expense	1.9	4.2	3.1
Stagecoach Gas Services LLC
Related Party Transaction, Due from (to) Related Party [Abstract]
Related Party Transaction, Expenses from Transactions with Related Party	7.5	7.9	8.4
Tres Palacios Holdings LLC
Related Party Transaction, Due from (to) Related Party [Abstract]
Related Party Transaction, Expenses from Transactions with Related Party	4.4	3.8	3.5
Crestwood Permian Basin Holdings
Related Party Transaction, Due from (to) Related Party [Abstract]
Related Party Transaction, Expenses from Transactions with Related Party	13.5	15.9	10.0
Jackalope Gas Gathering Services, LLC
Related Party Transaction, Due from (to) Related Party [Abstract]
Related Party Transaction, Expenses from Transactions with Related Party	$ 0.5	$ 1.1	$ 0.4

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Segments Disaggregation of Revenue (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Product revenues	$ 252.3	$ 343.3	$ 234.1
Revenues	3,181.9	3,654.1	$ 3,880.9
Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue including intersegment eliminations	1,010.8	1,139.1
Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue including intersegment eliminations	34.6	27.6
Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue including intersegment eliminations	2,325.7
Revenues		2,690.3
Natural Gas Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	163.2	134.9
Natural Gas Gathering | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	163.2	134.9
Natural Gas Gathering | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Natural Gas Gathering | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Crude Oil Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	75.0	38.8
Crude Oil Gathering | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	75.0	38.8
Crude Oil Gathering | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Crude Oil Gathering | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Water Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	79.6	58.0
Water Gathering | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	79.6	58.0
Water Gathering | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Water Gathering | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Natural Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	28.9	10.7
Natural Gas Processing | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	28.9	10.7
Natural Gas Processing | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Natural Gas Processing | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
NGL Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		6.1
NGL Processing | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
NGL Processing | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
NGL Processing | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		6.1
Natural Gas Compression
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	24.9	29.1
Natural Gas Compression | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	24.9	29.1
Natural Gas Compression | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Natural Gas Compression | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Crude Oil Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5.0	4.5
Crude Oil Storage | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1.9	1.8
Crude Oil Storage | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5.4	4.2
Crude Oil Storage | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
NGL Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	6.3	8.6
NGL Storage | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
NGL Storage | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
NGL Storage | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	6.3	8.6
Crude Oil Pipeline
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5.2	4.8
Crude Oil Pipeline | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Crude Oil Pipeline | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	7.9	7.1
Crude Oil Pipeline | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	12.7	8.8
Crude Oil Transportation | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	7.0	2.9
Crude Oil Transportation | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Crude Oil Transportation | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5.8	5.9
NGL Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	11.7	26.9
NGL Transportation | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
NGL Transportation | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
NGL Transportation | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	11.7	26.9
Water Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.2	0.3
Water Transportation | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Water Transportation | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Water Transportation | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.2	0.3
Crude Oil Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	11.0	9.3
Crude Oil Rail Loading | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Crude Oil Rail Loading | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	16.7	14.3
Crude Oil Rail Loading | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.2
NGL Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3.1
NGL Rail Loading | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
NGL Rail Loading | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
NGL Rail Loading | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3.1
Natural Gas Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	95.7	110.1
Natural Gas Product Sales | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	56.8	55.8
Natural Gas Product Sales | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Natural Gas Product Sales | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	72.3	70.9
Crude Oil Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,726.6	1,549.6
Crude Oil Product Sales | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	532.1	722.9
Crude Oil Product Sales | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Crude Oil Product Sales | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,315.6	978.0
NGL Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	680.7	1,306.7
NGL Product Sales | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	41.4	84.2
NGL Product Sales | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
NGL Product Sales | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	659.3	1,247.0
Other revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1.9	0.5
Other revenue | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Other revenue | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	4.6	2.0
Other revenue | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1.2	0.0
Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenues	(189.2)	(202.9)
Intersegment Eliminations | Natural Gas Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Crude Oil Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Water Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Natural Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | NGL Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
Intersegment Eliminations | Natural Gas Compression
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Crude Oil Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(2.3)	(1.5)
Intersegment Eliminations | NGL Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Crude Oil Pipeline
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(2.7)	(2.3)
Intersegment Eliminations | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(0.1)	0.0
Intersegment Eliminations | NGL Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Water Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Crude Oil Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(5.7)	(5.2)
Intersegment Eliminations | NGL Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
Intersegment Eliminations | Natural Gas Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(33.4)	(16.6)
Intersegment Eliminations | Crude Oil Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(121.1)	(151.3)
Intersegment Eliminations | NGL Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(20.0)	(24.5)
Intersegment Eliminations | Other revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(3.9)	(1.5)
Revenue from Contract with Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,928.6	3,310.8
Revenue from Contract with Customer | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,010.8	1,139.1
Revenue from Contract with Customer | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	34.6	27.6
Revenue from Contract with Customer | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,072.4	2,347.0
Revenue from Contract with Customer | Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ (189.2)	$ (202.9)

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Partners' Capital Rollforward of non-controlling interest (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 09, 2019
Temporary Equity [Line Items]
Interest of non-controlling partner in subsidiary		$ 426.2			$ 0.0
Non-controlling interest reclassification (Note 12)		178.8
Proceeds from Noncontrolling Interests	$ 175.0	235.0	$ 0.0	$ 175.0
Temporary Equity, Net Income		30.8
Series A-3
Temporary Equity [Line Items]
Proceeds from Noncontrolling Interests		235.0
Non-Controlling Partner
Temporary Equity [Line Items]
Noncontrolling Interest, Decrease from Distributions to Noncontrolling Interest Holders		$ (18.4)

XML

Partners' Capital

12 Months Ended

Dec. 31, 2019

Partners' Capital [Abstract]

Partners' Capital

Partners’ Capital

Preferred Units

Subject to certain conditions, the holders of the preferred units will have the right to convert preferred units into (i) common units on a 1-for-10 basis, or (ii) a number of common units determined pursuant to a conversion ratio set forth in Crestwood Equity’s partnership agreement upon the occurrence of certain events, such as a change in control. The preferred units have voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class, with each preferred units entitled to one vote for each common unit into which such preferred unit is convertible, except that the preferred units are entitled to vote as a separate class on any matter on which all unitholders are entitled to vote that adversely affects the rights, powers, privileges or preferences of the preferred units in relation to CEQP’s other securities outstanding.

In 2018, Crestwood Equity registered 71,257,445 preferred units under a shelf registration statement filed with the SEC under which holders of the preferred units may sell their preferred units. The preferred units representing limited partner interests are listed on the NYSE under the symbol “CEQP-P.”

Common Units

On August 4, 2017, we entered into an equity distribution agreement with certain financial institutions (each, a Manager), under which we may offer and sell from time to time through one or more of the Managers, common units having an aggregate offering price of up to $250 million. Common units sold pursuant to this at-the-market (ATM) equity distribution program are issued under a registration statement that became effective on April 12, 2017. We are required to pay the Managers an aggregate fee of up to 2.0% of the gross sales price per common unit sold under our ATM equity distribution program. There were no units issued under our ATM equity distribution program during the years ended December 31, 2019 and 2018. During the year ended December 31, 2017, we issued 633,271 common units under the ATM equity distribution program for net proceeds of approximately $15.2 million and we paid a manager fee of approximately $0.3 million related to the sale of these common units.

Subordinated Units

In conjunction with Crestwood Holdings’ acquisition of Crestwood Equity’s general partner, Crestwood Equity issued 438,789 subordinated units, which are considered limited partnership interests, and have the same rights and obligations as its common units, except that the subordinated units are entitled to receive distributions of available cash for a particular quarter only after each of our common units has received a distribution of at least $1.30 for that quarter. The subordinated units convert to common units after (i) CEQP’s common units have received a cumulative distribution in excess of $5.20 during a consecutive four quarter period; and (ii) its Adjusted Operating Surplus (as defined in the agreement) exceeds the distribution on a fully dilutive basis.

Distributions

Crestwood Equity

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

• provide for the proper conduct of its business;

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

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

plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. The amount of cash CEQP has available for distribution depends primarily upon its cash flow (which consists of the cash distributions it receives in connection with its ownership of Crestwood Midstream).

A summary of CEQP’s limited partner quarterly cash distributions for the years ended December 31, 2019, 2018 and 2017 is presented below:

Record Date	Payment Date	Per Unit Rate		Cash Distributions  (in millions)
2019
February 7, 2019	February 14, 2019	$	0.60	$	43.1
May 8, 2019	May 15, 2019	0.60		43.1
August 7, 2019	August 14, 2019	0.60		43.1
November 7, 2019	November 14, 2019	0.60		43.1
				$	172.4
2018
February 7, 2018	February 14, 2018	$	0.60	$	42.7
May 8, 2018	May 15, 2018	0.60		42.7
August 7, 2018	August 14, 2018	0.60		42.7
November 7, 2018	November 14, 2018	0.60		42.7
				$	170.8
2017
February 7, 2017	February 14, 2017	$	0.60	$	41.8
May 8, 2017	May 15, 2017	0.60		41.8
August 7, 2017	August 14, 2017	0.60		41.8
November 7, 2017	November 14, 2017	0.60		42.2
				$	167.6

On February 14, 2020, we paid a distribution of $0.625 per limited partner unit to unitholders of record on February 7, 2020 with respect to the fourth quarter of 2019.

Preferred Unitholders. The holders of our preferred units are entitled to receive fixed quarterly distributions of $0.2111 per unit. Through the quarters ending September 30, 2017 (the Initial Distribution Period), distributions on the preferred units could be made in additional preferred units, cash, or a combination thereof, at our election. We paid distributions on our preferred units through the issuance of additional preferred units through and for the quarter ended June 30, 2017. The number of units distributed was calculated as the fixed quarterly distribution of $0.2111 per unit divided by the cash purchase price of $9.13 per unit. We accrued the fair value of such distribution at the end of the quarterly period and adjusted the fair value of the distribution on the date the additional preferred units were distributed. Distributions on the preferred units following the Initial Distribution Period will be paid in cash unless, subject to certain exceptions, (i) there is no distribution being paid on our common units; and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash distribution to

our preferred unitholders. If we fail to pay the full amount payable to our preferred unitholders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the preferred units will increase to $0.2567 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the preferred units have been paid in full in cash. In addition, if we fail to pay in full any Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

During the year ended December 31, 2019 and 2018, we made cash distributions to our preferred unitholders of approximately $60.1 million in both periods. In November 2017, we made a cash distribution to our preferred unitholders of approximately $15.0 million for the quarter ended September 30, 2017. During the year ended December 31, 2017, we issued 4,724,030 preferred units to our preferred unitholders in lieu of paying quarterly cash distributions of $43.1 million. On February 14, 2020, we made a cash distribution of approximately $15.0 million to our preferred unitholders for the quarter ended December 31, 2019.

Crestwood Midstream

In accordance with the partnership agreement, Crestwood Midstream’s general partner may, from time to time, cause Crestwood Midstream to make cash distributions at the sole discretion of the general partner. During the years ended December 31, 2019, 2018 and 2017, Crestwood Midstream made distributions of $235.8 million, $238.4 million and $174.0 million, which represented net amounts due to Crestwood Midstream related to cash advances to CEQP for its general corporate activities.

Non-Controlling Partner

Crestwood Niobrara, our consolidated subsidiary, issued a preferred interest (Series A Preferred Units) to a subsidiary of General Electric Capital Corporation and GE Structured Finance, Inc. (collectively, GE) in conjunction with the acquisition of its initial 50% equity interest in Jackalope. In December 2017, Crestwood Niobrara redeemed 100% of the outstanding Series A Preferred Units from GE for an aggregate purchase price of approximately $202.7 million and issued $175 million in new Series A-2 Preferred Units to CN Jackalope Holdings LLC (Jackalope Holdings), which is reflected as interest of non-controlling partner in subsidiary and a component of total partners’ capital on our consolidated balance sheet at December 31, 2018. In April 2019, Crestwood Niobrara issued $235 million in new Series A-3 Preferred Units (collectively with the Series A-2 Preferred Units defined as the Crestwood Niobrara Preferred Units) to Jackalope Holdings in conjunction with Crestwood Niobrara’s acquisition of the remaining 50% equity interest in Jackalope from Williams. In connection with the issuance of the Series A-3 Preferred Units, we entered into a Third Amended and Restated Limited Liability Company Agreement (Crestwood Niobrara Amended Agreement) with Jackalope Holdings, pursuant to which we serve as managing member of Crestwood Niobrara. The Crestwood Niobrara Amended Agreement modified certain provisions under the previous limited liability company agreement related to the conversion and redemption of the Series A-2 Preferred Units, as follows:

• The Crestwood Niobrara Preferred Units are convertible by the preferred interest holder starting on January 1, 2021 into Crestwood Niobrara common units. The preferred interest holder has the option to contribute additional capital to Crestwood Niobrara to increase their common ownership percentage in Crestwood Niobrara to 50% upon the conversion.

• The Crestwood Niobrara Preferred Units are redeemable by the preferred interest holder starting on December 31, 2023 for an amount equal to the Liquidation Preference (as defined in the Crestwood Niobrara Amended Agreement). If redemption is elected by the preferred interest holder, we have the option to elect to give consideration equal to the Liquidation Preference in either (i) unregistered CEQP common units (subject to a Registration Rights Agreement) with a total value of up to $100 million and/or cash; or (ii) proceeds from a full liquidation of Crestwood Niobrara’s assets and unregistered CEQP common units (subject to a Registration Rights Agreement).

• The Crestwood Niobrara Preferred Units are redeemable by us starting on January 1, 2023 for either (i) unregistered CEQP common units (subject to a Registration Rights Agreement) with a total value of up to $100 million and/or cash; or (ii) proceeds from a full liquidation of Crestwood Niobrara’s assets and registered CEQP common units (subject to a Registration Rights Agreement).

As a result of the modification of the conversion and redemption provisions of the Crestwood Niobrara Preferred Units, we continue to consolidate Crestwood Niobrara and have reflected these preferred interests as a non-controlling interest in

subsidiary apart from partners’ capital (i.e., temporary equity) on our consolidated balance sheet at December 31, 2019. The following table shows the change in our non-controlling interest in subsidiary at December 31, 2019 (in millions):

Balance at April 9, 2019(1)	$	—
Reclassification of Series A-2 Preferred Units	178.8
Issuance of Series A-3 Preferred Units	235.0
Distributions to non-controlling partner	(18.4		)
Net income attributable to non-controlling partner(2)	30.8
Balance at December 31, 2019	$	426.2

(1) For further detail related to our non-controlling interest in subsidiary for the period December 31, 2018 to April 8, 2019, see our consolidated statements of partners’ capital.

(2) We adjust the carrying amount of our non-controlling interest to its redemption value each period through net income attributable to non-controlling partner.

Crestwood Niobrara is required to make quarterly cash distributions on its preferred interest within 30 days after the end of each quarter. During the years ended December 31, 2019, 2018 and 2017, Crestwood Niobrara paid cash distributions of $25.0 million, $9.9 million and $15.2 million to its preferred interest owners. In January 2020, Crestwood Niobrara paid a cash distribution of $9.2 million to Jackalope Holdings for the quarter ended December 31, 2019.

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Fair Value Measurements

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

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

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

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

Instruments in this category include non-exchange-traded derivatives such as over the counter (OTC) forwards, options and physical exchanges.

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

Cash, Accounts Receivable and Accounts Payable

As of December 31, 2019 and 2018, the carrying amounts of cash, accounts receivable and accounts payable approximate fair value based on the short-term nature of these instruments.

Credit Facility

The fair value of the amounts outstanding under our Crestwood Midstream credit facility approximates the carrying amounts as of December 31, 2019 and 2018, due primarily to the variable nature of the interest rate of the instrument, which is considered a Level 2 fair value measurement.

Senior Notes

We estimate the fair value of our senior notes primarily based on quoted market prices for the same or similar issuances (representing a Level 2 fair value measurement). The following table represents the carrying amount (reduced for deferred financing costs associated with the respective notes) and fair value of our senior notes (in millions):

	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2023 Senior Notes	$	695.1	$	714.0	$	693.6	$	668.1
2025 Senior Notes	$	494.4	$	514.4	$	493.4	$	466.2
2027 Senior Notes	$	592.1	$	610.1	$	—	$	—

Financial Assets and Liabilities

As of December 31, 2019 and 2018, we held certain assets and liabilities that are required to be measured at fair value on a recurring basis, which include our derivative instruments related to heating oil, crude oil, and NGLs. Our derivative instruments consist of forwards, swaps, futures, physical exchanges and options.

Our derivative instruments that are traded on the NYMEX have been categorized as Level 1.

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

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

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

The following tables set forth by level within the fair value hierarchy, our financial instruments that were accounted for at fair value on a recurring basis at December 31, 2019 and 2018 (in millions):

	December 31, 2019
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Fair Value
Assets
Assets from price risk management	$	3.7	$	164.0	$	—	$	167.7	$	(122.3	)	$	(2.2	)	$	43.2
Suburban Propane Partners, L.P. units(2)	3.1		—		—		3.1		—			—			3.1
Total assets at fair value	$	6.8	$	164.0	$	—	$	170.8	$	(122.3	)	$	(2.2	)	$	46.3
Liabilities
Liabilities from price risk management	$	2.8	$	151.9	$	—	$	154.7	$	(122.3	)	$	(25.7	)	$	6.7
Total liabilities at fair value	$	2.8	$	151.9	$	—	$	154.7	$	(122.3	)	$	(25.7	)	$	6.7
	December 31, 2018
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Fair Value
Assets
Assets from price risk management	$	12.4	$	160.7	$	—	$	173.1	$	(140.3	)	$	1.9		$	34.7
Suburban Propane Partners, L.P. units(2)	2.8		—		—		2.8		—			—			2.8
Total assets at fair value	$	15.2	$	160.7	$	—	$	175.9	$	(140.3	)	$	1.9		$	37.5
Liabilities
Liabilities from price risk management	$	7.0	$	144.7	$	—	$	151.7	$	(140.3	)	$	(5.6	)	$	5.8
Total liabilities at fair value	$	7.0	$	144.7	$	—	$	151.7	$	(140.3	)	$	(5.6	)	$	5.8

(1) Amounts represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.

(2)

Amount is reflected in other assets on CEQP’s consolidated balance sheets.

XML

Certain Balance Sheet Information

12 Months Ended

Dec. 31, 2019

Balance Sheet Related Disclosures [Abstract]

Certain Balance Sheet Information

Certain Balance Sheet Information

Property, Plant and Equipment

Property, plant and equipment consisted of the following at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Gathering systems and pipelines and related assets	$	1,017.8	$	758.6	$	1,160.6	$	901.5
Facilities and equipment	1,797.7		1,230.7		1,982.8		1,415.9
Buildings, land, rights-of-way, storage rights and easements	370.6		331.7		374.3		335.4
Vehicles	27.7		17.9		26.0		16.1
Construction in process	368.7		230.8		368.7		230.8
Office furniture and fixtures	30.0		28.4		30.2		28.5
	3,612.5		2,598.1		3,942.6		2,928.2
Less: accumulated depreciation	703.4		568.4		875.1		725.9
Total property, plant and equipment, net	$	2,909.1	$	2,029.7	$	3,067.5	$	2,202.3

Depreciation. CEQP’s depreciation expense totaled $139.5 million, $123.6 million and $135.9 million for the years ended December 31, 2019, 2018 and 2017. CMLP’s depreciation expense totaled $153.5 million, $137.7 million and $150.0 million for the years ended December 31, 2019, 2018 and 2017.

Capitalized Interest. During the years ended December 31, 2019, 2018 and 2017, CEQP and CMLP capitalized interest of $14.4 million, $5.0 million and $2.9 million related to certain expansion projects.

Finance Leases. We had finance lease assets of $9.5 million and $9.7 million included in property, plant and equipment, net at December 31, 2019 and 2018, primarily related to certain vehicle leases. See Notes 2 and 15 for a further discussion of our finance lease assets.

Intangible Assets

Intangible assets at CEQP and CMLP consisted of the following at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Customer accounts	$	438.9	$	438.9
Gas gathering, compression and processing contracts (1)	631.2		325.2
Trademarks	6.2		6.2
	1,076.3		770.3
Less: accumulated amortization	271.1		216.5
Total intangible assets, net	$	805.2	$	553.8

(1) Includes $306.0 million related to a revenue contract acquired from the Jackalope Acquisition, which is further discussed in Note 3.

The following table summarizes total accumulated amortization of CEQP’s and CMLP’s intangible assets at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Customer accounts	$	134.4	$	112.1
Gas gathering, compression and processing contracts	132.5		100.8
Trademarks	4.2		3.6
Total accumulated amortization	$	271.1	$	216.5

Crestwood Equity’s amortization expense related to its intangible assets for the years ended December 31, 2019, 2018 and 2017, was approximately $54.6 million, $43.5 million and $53.7 million. Crestwood Midstream’s amortization expense related to its intangible assets for the years ended December 31, 2019, 2018 and 2017 was approximately $54.6 million, $42.1 million and $50.6 million.

Estimated amortization of CEQP’s and CMLP’s intangible assets for the next five years is as follows (in millions):

Year Ending December 31,
2020	$	58.9
2021	$	58.9
2022	$	58.9
2023	$	55.0
2024	$	50.1

Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Accrued expenses(1)	$	61.6	$	64.8	$	60.3	$	63.7
Accrued property taxes	6.1		2.6		6.1		2.6
Income tax payable	0.3		0.3		0.3		0.3
Interest payable	25.6		19.8		25.6		19.8
Accrued additions to property, plant and equipment	38.0		10.5		38.0		10.5
Operating leases	18.1		—		18.1		—
Finance leases	3.2		2.4		3.2		2.4
Deferred revenue	8.8		12.0		8.8		12.0
Total accrued expenses and other liabilities	$	161.7	$	112.4	$	160.4	$	111.3

(1) Includes $16.2 million of related party accrued expenses at December 31, 2018 related to deposits received from Jackalope prior to the acquisition of the remaining 50% equity interest in Jackalope from Williams in April 2019.

Other Long-Term Liabilities

Other long-term liabilities consisted of the following at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Contract liabilities	$	144.7	$	65.4	$	144.7	$	65.4
Contingent consideration	57.0		57.0		57.0		57.0
Operating leases	41.5		—		41.5		—
Asset retirement obligations	33.3		27.6		33.3		27.6
Other	25.1		23.6		19.1		21.0
Total other long-term liabilities	$	301.6	$	173.6	$	295.6	$	171.0

XML

Certain Balance Sheet Information (Tables)

12 Months Ended

Dec. 31, 2019

Balance Sheet Related Disclosures [Abstract]

Property, Plant And Equipment

Property, plant and equipment consisted of the following at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Gathering systems and pipelines and related assets	$	1,017.8	$	758.6	$	1,160.6	$	901.5
Facilities and equipment	1,797.7		1,230.7		1,982.8		1,415.9
Buildings, land, rights-of-way, storage rights and easements	370.6		331.7		374.3		335.4
Vehicles	27.7		17.9		26.0		16.1
Construction in process	368.7		230.8		368.7		230.8
Office furniture and fixtures	30.0		28.4		30.2		28.5
	3,612.5		2,598.1		3,942.6		2,928.2
Less: accumulated depreciation	703.4		568.4		875.1		725.9
Total property, plant and equipment, net	$	2,909.1	$	2,029.7	$	3,067.5	$	2,202.3

Intangible Assets

Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:

	Weighted-Average Life (years)
Customer accounts and revenue contracts	20
Trademarks	10

Intangible assets at CEQP and CMLP consisted of the following at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Customer accounts	$	438.9	$	438.9
Gas gathering, compression and processing contracts (1)	631.2		325.2
Trademarks	6.2		6.2
	1,076.3		770.3
Less: accumulated amortization	271.1		216.5
Total intangible assets, net	$	805.2	$	553.8

(1) Includes $306.0 million related to a revenue contract acquired from the Jackalope Acquisition, which is further discussed in Note 3.

The following table summarizes total accumulated amortization of CEQP’s and CMLP’s intangible assets at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Customer accounts	$	134.4	$	112.1
Gas gathering, compression and processing contracts	132.5		100.8
Trademarks	4.2		3.6
Total accumulated amortization	$	271.1	$	216.5

Schedule of Intangible Assets, Future Amortization Expense

Estimated amortization of CEQP’s and CMLP’s intangible assets for the next five years is as follows (in millions):

Year Ending December 31,
2020	$	58.9
2021	$	58.9
2022	$	58.9
2023	$	55.0
2024	$	50.1

Schedule of Accrued Liabilities

Accrued expenses and other liabilities consisted of the following at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Accrued expenses(1)	$	61.6	$	64.8	$	60.3	$	63.7
Accrued property taxes	6.1		2.6		6.1		2.6
Income tax payable	0.3		0.3		0.3		0.3
Interest payable	25.6		19.8		25.6		19.8
Accrued additions to property, plant and equipment	38.0		10.5		38.0		10.5
Operating leases	18.1		—		18.1		—
Finance leases	3.2		2.4		3.2		2.4
Deferred revenue	8.8		12.0		8.8		12.0
Total accrued expenses and other liabilities	$	161.7	$	112.4	$	160.4	$	111.3

(1)

Includes $16.2 million of related party accrued expenses at December 31, 2018 related to deposits received from Jackalope prior to the acquisition of the remaining 50% equity interest in Jackalope from Williams in April 2019.

Other Noncurrent Liabilities

Other long-term liabilities consisted of the following at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Contract liabilities	$	144.7	$	65.4	$	144.7	$	65.4
Contingent consideration	57.0		57.0		57.0		57.0
Operating leases	41.5		—		41.5		—
Asset retirement obligations	33.3		27.6		33.3		27.6
Other	25.1		23.6		19.1		21.0
Total other long-term liabilities	$	301.6	$	173.6	$	295.6	$	171.0

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Schedule of Carrying Values and Estimated Fair Values of Debt Instruments

The following table represents the carrying amount (reduced for deferred financing costs associated with the respective notes) and fair value of our senior notes (in millions):

	December 31, 2019				December 31, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
2023 Senior Notes	$	695.1	$	714.0	$	693.6	$	668.1
2025 Senior Notes	$	494.4	$	514.4	$	493.4	$	466.2
2027 Senior Notes	$	592.1	$	610.1	$	—	$	—

Assets And Liabilities Measured At Fair Value On Recurring Basis

The following tables set forth by level within the fair value hierarchy, our financial instruments that were accounted for at fair value on a recurring basis at December 31, 2019 and 2018 (in millions):

	December 31, 2019
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Fair Value
Assets
Assets from price risk management	$	3.7	$	164.0	$	—	$	167.7	$	(122.3	)	$	(2.2	)	$	43.2
Suburban Propane Partners, L.P. units(2)	3.1		—		—		3.1		—			—			3.1
Total assets at fair value	$	6.8	$	164.0	$	—	$	170.8	$	(122.3	)	$	(2.2	)	$	46.3
Liabilities
Liabilities from price risk management	$	2.8	$	151.9	$	—	$	154.7	$	(122.3	)	$	(25.7	)	$	6.7
Total liabilities at fair value	$	2.8	$	151.9	$	—	$	154.7	$	(122.3	)	$	(25.7	)	$	6.7
	December 31, 2018
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)			Collateral/Margin Received or Paid			Fair Value
Assets
Assets from price risk management	$	12.4	$	160.7	$	—	$	173.1	$	(140.3	)	$	1.9		$	34.7
Suburban Propane Partners, L.P. units(2)	2.8		—		—		2.8		—			—			2.8
Total assets at fair value	$	15.2	$	160.7	$	—	$	175.9	$	(140.3	)	$	1.9		$	37.5
Liabilities
Liabilities from price risk management	$	7.0	$	144.7	$	—	$	151.7	$	(140.3	)	$	(5.6	)	$	5.8
Total liabilities at fair value	$	7.0	$	144.7	$	—	$	151.7	$	(140.3	)	$	(5.6	)	$	5.8

(1) Amounts represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.

(2)

Amount is reflected in other assets on CEQP’s consolidated balance sheets.

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Schedule I - Crestwood Equity Partners LP - Parent Only

12 Months Ended

Dec. 31, 2019

Condensed Financial Information Disclosure [Abstract]

Schedule I - Crestwood Equity Partners LP - Parent Only

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Balance Sheets

(in millions)

	December 31,
	2019		2018
Assets
Current assets:
Cash	$	0.2	$	0.2
Total current assets	0.2		0.2
Property, plant and equipment, net	1.0		1.1
Investments in subsidiaries	1,935.9		1,854.7
Other assets	3.1		2.8
Total assets	$	1,940.2	$	1,858.8
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	0.1	$	2.6
Accrued expenses	1.3		1.1
Total current liabilities	1.4		3.7
Other long-term liabilities	6.0		2.6
Total partners’ capital	1,932.8		1,852.5
Total liabilities and partners’ capital	$	1,940.2	$	1,858.8

See accompanying notes.

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Operations

(in millions)

	Year Ended December 31,
	2019			2018			2017
Revenues	$	—		$	—		$	—
Expenses	5.3			6.1			6.7
Operating loss	(5.3		)	(6.1		)	(6.7		)
Equity in net income (loss) of subsidiaries	290.0			56.5			(185.7		)
Other income, net	0.4			0.4			0.5
Net income (loss) attributable to Crestwood Equity Partners LP	$	285.1		$	50.8		$	(191.9	)

See accompanying notes.

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Comprehensive Income

(in millions)

	Year Ended December 31,
	2019		2018			2017
Net income (loss) attributable to Crestwood Equity Partners LP	$	285.1	$	50.8		$	(191.9	)
Change in fair value of Suburban Propane Partners, LP units	0.3		(0.7		)	(0.8		)
Comprehensive income (loss) attributable to Crestwood Equity Partners LP	$	285.4	$	50.1		$	(192.7	)

See accompanying notes.

Schedule I

Crestwood Equity Partners LP

Parent Only

Condensed Statements of Cash Flows

(in millions)

	Year Ended December 31,
	2019			2018			2017
Cash flows from operating activities	$	(3.7	)	$	(3.8	)	$	(3.6	)
Cash flows from investing activities	235.8			238.4			174.0
Cash flows from financing activities:
Distributions paid to partners	(232.5		)	(230.9		)	(182.6		)
Proceeds from issuance of common units	—			—			15.2
Change in intercompany balances	0.4			(3.8		)	(3.0		)
Net cash used in financing activities	(232.1		)	(234.7		)	(170.4		)
Net change in cash	—			(0.1		)	—
Cash at beginning of period	0.2			0.3			0.3
Cash at end of period	$	0.2		$	0.2		$	0.3

See accompanying notes.

Schedule I

Crestwood Equity Partners LP

Parent Only

Notes to Condensed Financial Statements

Note 1. Basis of Presentation

In the parent-only financial statements, our investment in subsidiaries is stated at cost plus equity in undistributed earnings of subsidiaries since the date of acquisition.  Our share of net income of our unconsolidated subsidiaries is included in consolidated income using the equity method.  The parent-only financial statements should be read in conjunction with our consolidated financial statements. 

The condensed statements of operations for the years ended December 31, 2018 and 2017 include reclassifications

that were made to conform to the current year presentation, none of which impacted previously reported net income (loss) attributable to Crestwood Equity Partners LP or partners’ capital.

Note 2. Distributions    

During the years ended December 31, 2019, 2018 and 2017, we received cash distributions from Crestwood Midstream Partners LP of approximately $235.8 million, $238.4 million and $174.0 million.

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Related Party Transactions

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Related Party Transactions

Related Party Transactions

Crestwood Holdings indirectly owns both CEQP’s and CMLP’s general partner. The affiliates of Crestwood Holdings and its owners are considered CEQP’s and CMLP’s related parties. We enter into transactions with our affiliates within the ordinary course of business and the services are based on the same terms as non-affiliates, including gas gathering and processing services under long-term contracts, product purchases, marketing and various operating agreements. We also enter into transactions with our affiliates related to services provided on our expansion projects. During the years ended December 31, 2019 and 2018, we paid approximately $9.9 million and $7.2 million of capital expenditures to Applied Consultants, Inc., an affiliate of Crestwood Holdings. Below is a discussion of certain of our related party agreements.

Shared Services. CMLP shares common management, general and administrative and overhead costs with CEQP. CEQP grants long-term incentive awards under the Crestwood LTIP as discussed in Note 13 and, as such, CEQP allocates a portion of its unit-based compensation costs to CMLP.

Stagecoach Gas Management Agreement. In May 2016, Crestwood Midstream Operations, LLC (Crestwood Midstream Operations), our wholly-owned subsidiary and Stagecoach Gas entered into a management agreement under which Crestwood Midstream Operations provides the management and operating services required by Stagecoach Gas’ facilities. The initial term of the agreement will expire in May 2021, and is automatically extended for three-year periods unless otherwise terminated pursuant to the terms of the agreement. Reimbursements received from Stagecoach Gas under this agreement are reflected as operations and maintenance expenses at CEQP and CMLP in the table below.

Tres Palacios Operating Agreement. A consolidated subsidiary of Crestwood Midstream entered into an operating agreement with Tres Palacios, pursuant to which we assumed the responsibility of operating and maintaining the facilities as well as certain administrative and other general services identified in the agreement. Under the operating agreement, Tres Palacios reimburses us for all costs incurred on its behalf. These reimbursements are reflected as operations and maintenance expenses at CEQP and CMLP in the table below.

Crestwood Permian Operating Agreement. In October 2016, Crestwood Midstream Operations entered into an operating agreement with Crestwood Permian, pursuant to which we provide operating services for Crestwood Permian’s facilities, as well as certain administrative and other general services identified in the agreement. Under this operating agreement, Crestwood Permian reimburses us for all costs incurred on its behalf. These reimbursements are reflected as operations and maintenance expenses at CEQP and CMLP in the table below.

Jackalope Gas Gathering Services, L.L.C. On April 9, 2019, Crestwood Niobrara, our consolidated subsidiary, acquired Williams’ 50% equity interest in Jackalope, and as a result, Crestwood Niobrara controls and owns 100% of the equity interests in Jackalope. Prior to the acquisition of the remaining interest in Jackalope, a consolidated subsidiary of Crestwood Midstream entered into a marketing services agreement with Jackalope under which we provided marketing services for Jackalope as well as certain administrative and other general services identified in the agreement. Under this marketing services agreement, Jackalope reimbursed us for all costs incurred on its behalf. These reimbursements are reflected as operations and maintenance expenses at CEQP and CMLP in the table below.

The following table shows transactions with our affiliates which are reflected in our consolidated statements of operations for the years December 31, 2019, 2018 and 2017 (in millions):

	Year Ended December 31,
	2019			2018			2017
Revenues at CEQP and CMLP	$	2.9		$	1.0		$	1.8
Costs of product/services sold at CEQP and CMLP(1)	$	45.4		$	134.7		$	15.3
Operations and maintenance expenses at CEQP and CMLP(2)	$	25.9		$	28.7		$	22.3
General and administrative expenses charged by CEQP to CMLP, net(3)	$	41.4		$	20.7		$	19.4
General and administrative expenses at CEQP charged from Crestwood Holdings, net(4)	$	(0.6	)	$	(2.7	)	$	(1.7	)

(1) Includes (i) $19.0 million and $56.1 million during the years ended December 31, 2019 and 2018 related to purchases of NGLs from a subsidiary of Crestwood Permian; (ii) $23.9 million and $78.6 million during the years ended December 31, 2019 and 2018 related to an agency marketing agreement with Ascent Resources - Utica, LLC (Ascent); (iii) $0.2 million during the year ended December 31, 2019 related to an agreement with Blue Racer Midstream, LLC (Blue Racer); (iv) $2.3 million during the year ended December 31, 2019 related to purchases of natural gas from a subsidiary of Stagecoach Gas; and (v) $15.3 million during the year ended December 31, 2017 related to natural gas purchases from Sabine Oil and Gas (Sabine). Ascent, Blue Racer and Sabine are affiliates of Crestwood Holdings for the respective periods presented.

(2) We have operating agreements with certain of our unconsolidated affiliates pursuant to which we charge them operations and maintenance expenses in accordance with their respective agreements, and these charges are reflected as a reduction of operations and maintenance expenses in our consolidated statements of operations. During the year ended December 31, 2019, we charged $7.5 million to Stagecoach Gas, $4.4 million to Tres Palacios, $13.5 million to Crestwood Permian and $0.5 million to Jackalope. During the year ended December 31, 2018, we charged $7.9 million to Stagecoach Gas, $3.8 million to Tres Palacios, $15.9 million to Crestwood Permian and $1.1 million to Jackalope. During the year ended December 31, 2017, we charged $8.4 million to Stagecoach Gas, $3.5 million to Tres Palacios, $10.0 million to Crestwood Permian and $0.4 million to Jackalope.

(3) Includes $45.1 million, $24.3 million and $22.4 million of net unit-based compensation charges allocated from CEQP to CMLP for the years ended December 31, 2019, 2018 and 2017. In addition, includes $3.7 million, $3.6 million and $3.0 million of CMLP’s general and administrative costs allocated to CEQP during the years ended December 31, 2019, 2018 and 2017.

(4) Includes $1.9 million, $4.2 million and $3.1 million of unit-based compensation charges allocated from Crestwood Holdings to CEQP and CMLP during the years ended December 31, 2019, 2018 and 2017.

The following table shows accounts receivable and accounts payable from our affiliates as of December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Accounts receivable at CEQP and CMLP	$	7.3	$	4.1
Accounts payable at CEQP	$	15.6	$	16.1
Accounts payable at CMLP	$	13.1	$	13.6

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Purchase Commitment, Excluding Long-term Commitment

The following table summarizes CEQP’s and CMLP’s self-insurance reserves at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Self-insurance reserves(1)	$	9.7	$	11.3	$	8.3	$	9.6

(1)

At December 31, 2019, CEQP and CMLP classified approximately $6.2 million and $5.2 million, respectively of these reserves as other long-term liabilities on their consolidated balance sheets.

Assets And Liabilities, Lessee

The following table summarizes the balance sheet information related to our operating and finance leases at December 31, 2019 (in millions):

Operating Leases
Operating lease right-of-use assets, net	$	53.8
Accrued expenses and other liabilities	$	18.1
Other long-term liabilities	41.5
Total operating lease liabilities	$	59.6
Finance Leases
Property, plant and equipment	$	14.9
Less: accumulated depreciation	5.4
Property, plant and equipment, net	$	9.5
Accrued expenses and other liabilities	$	3.2
Other long-term liabilities	5.2
Total finance lease liabilities	$	8.4

Lease, Cost

The following table presents the costs and sublease income associated with our operating and finance leases for the year ended December 31, 2019 (in millions):

Operating leases:
Operating lease expense(1)(2)	$	28.3
Sublease income(3)	(1.0		)
Total operating lease expense, net	$	27.3
Finance leases:
Amortization of right-of-use assets(4)	$	3.6
Interest on lease liabilities(5)	0.7
Total finance lease expense	$	4.3

(1) Approximately $17.5 million is included in costs of product/services sold and $10.8 million is included in operations and maintenance expense on our consolidated statements of operations for the year ended December 31, 2019.

(2) Includes short-term and variable lease costs of approximately $3.7 million for the year ended December 31, 2019.

(3) Included in marketing, supply and logistics service revenues on our consolidated statements of operations.

(4) Included in depreciation, amortization and accretion expense on our consolidated statements of operations.

(5)

Included in interest and debt expense, net on our consolidated statements of operations.

The following table presents the weighted-average remaining lease term and the weighted-average discount rate associated with our operating and finance leases as of December 31, 2019:

Weighted-average remaining lease term (in years):
Operating leases(1)	4.4
Finance leases(2)	2.6
Weighted-average discount rate:
Operating leases(3)	5.9	%
Finance leases(3)	7.3	%

(1) Remaining terms vary from one year to 20 years.

(2) Remaining terms vary from one year to four years.

(3)

We utilized discount rates ranging from 3.5% to 8.3% to estimate the discounted cash flows used in estimating our right-of-use assets and lease liabilities as of December 31, 2019, which were primarily based on our credit-adjusted collateralized incremental borrowing rate.

The following table presents supplemental cash flow information for our operating and finance leases for the year ended December 31, 2019 (in millions):

Cash paid for lease liabilities:
Operating cash flows from operating leases	$	22.9
Operating cash flows from finance leases	$	0.7
Financing cash flows from finance leases	$	3.5
Right-of-use assets obtained in exchange for lease obligations:
Operating leases(1)	$	4.2
Finance leases	$	1.8

(1)

Includes approximately $2.9 million of operating leases obtained from the Jackalope Acquisition, which is further discussed in Note 3.

Lessee, Operating Lease, Liability, Maturity

The following table presents the future minimum lease liabilities under Topic 842 for our leases as of December 31, 2019 for the next five years and in total thereafter (in millions):

Year Ending December 31,	Operating Leases		Finance Leases		Total
2020	$	20.9	$	3.6	$	24.5
2021	16.3		3.6		19.9
2022	11.1		1.9		13.0
2023	6.7		0.1		6.8
2024	6.0		—		6.0
Thereafter	7.5		—		7.5
Total lease payments	68.5		9.2		77.7
Less: Interest	8.9		0.8		9.7
Present value of lease liabilities	$	59.6	$	8.4	$	68.0

XML

Condensed Consolidating Financial Information (Tables)

12 Months Ended

Dec. 31, 2019

Condensed Financial Information Disclosure [Abstract]

Condensed Consolidating Balance Sheet

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2019
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	1.8	$	—	$	23.6	$	—		$	25.4
Accounts receivable	—		229.1		12.8		—			241.9
Inventory	—		53.7		—		—			53.7
Other current assets	—		54.6		0.2		—			54.8
Total current assets	1.8		337.4		36.6		—			375.8
Property, plant and equipment, net	—		2,331.3		736.2		—			3,067.5
Goodwill and intangible assets, net	—		650.7		373.4		—			1,024.1
Operating lease right-of-use assets, net	—		51.0		2.8		—			53.8
Investments in consolidated affiliates	4,451.6		—		—		(4,451.6		)	—
Investments in unconsolidated affiliates	—		—		980.4		—			980.4
Other non-current assets	—		1.9		0.5		—			2.4
Total assets	$	4,453.4	$	3,372.3	$	2,129.9	$	(4,451.6	)	$	5,504.0
Liabilities and capital
Current liabilities:
Accounts payable	$	—	$	175.9	$	10.7	$	—		$	186.6
Other current liabilities	25.8		123.9		17.6		—			167.3
Total current liabilities	25.8		299.8		28.3		—			353.9
Long-term liabilities:
Long-term debt, less current portion	2,328.3		—		—		—			2,328.3
Other long-term liabilities	—		174.8		120.8		—			295.6
Deferred income taxes	—		0.7		—		—			0.7
Total liabilities	2,354.1		475.3		149.1		—			2,978.5
Interest of non-controlling partner in subsidiary	—		—		426.2		—			426.2
Partners’ capital	2,099.3		2,897.0		1,554.6		(4,451.6		)	2,099.3
Total liabilities and capital	$	4,453.4	$	3,372.3	$	2,129.9	$	(4,451.6	)	$	5,504.0

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2018
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	0.2	$	—	$	—	$	—		$	0.2
Restricted cash	16.3		—		—		—			16.3
Accounts receivable	—		246.3		19.9		(16.3		)	249.9
Inventory	—		64.6		—		—			64.6
Other current assets	—		46.0		—		—			46.0
Total current assets	16.5		356.9		19.9		(16.3		)	377.0
Property, plant and equipment, net	—		2,202.3		—		—			2,202.3
Goodwill and intangible assets, net	—		692.4		—		—			692.4
Investments in consolidated affiliates	3,800.4		—		—		(3,800.4		)	—
Investments in unconsolidated affiliates	—		—		1,188.2		—			1,188.2
Other non-current assets	—		2.1		—		—			2.1
Total assets	$	3,816.9	$	3,253.7	$	1,208.1	$	(3,816.7	)	$	4,462.0
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	16.3	$	210.5	$	—	$	(16.3	)	$	210.5
Other current liabilities	20.0		81.8		16.2		—			118.0
Total current liabilities	36.3		292.3		16.2		(16.3		)	328.5
Long-term liabilities:
Long-term debt, less current portion	1,752.4		—		—		—			1,752.4
Other long-term liabilities	—		114.0		57.0		—			171.0
Deferred income taxes	—		0.6		—		—			0.6
Total liabilities	1,788.7		406.9		73.2		(16.3		)	2,252.5
Partners’ capital	2,028.2		2,846.8		953.6		(3,800.4		)	2,028.2
Interest of non-controlling partner in subsidiary	—		—		181.3		—			181.3
Total partners’ capital	2,028.2		2,846.8		1,134.9		(3,800.4		)	2,209.5
Total liabilities and partners’ capital	$	3,816.9	$	3,253.7	$	1,208.1	$	(3,816.7	)	$	4,462.0

Condensed Consolidating Statements of Operations

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2019
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,111.8		$	70.1		$	—		$	3,181.9
Costs of product/services sold	—			2,544.9			—			—			2,544.9
Operating expenses and other:
Operations and maintenance	—			120.0			18.8			—			138.8
General and administrative	51.2			47.0			—			—			98.2
Depreciation, amortization and accretion	—			179.4			30.5			—			209.9
Loss on long-lived assets, net	—			6.2			—			—			6.2
Gain on acquisition	—			—			(209.4		)	—			(209.4		)
	51.2			352.6			(160.1		)	—			243.7
Operating income (loss)	(51.2		)	214.3			230.2			—			393.3
Earnings from unconsolidated affiliates, net	—			—			32.8			—			32.8
Interest and debt income (expense), net	(115.5		)	—			0.1			—			(115.4		)
Other income, net	—			0.2			—			—			0.2
Equity in net income (loss) of subsidiaries	442.5			—			—			(442.5		)	—
Income (loss) before income taxes	275.8			214.5			263.1			(442.5		)	310.9
Provision for income taxes	—			(0.3		)	—			—			(0.3		)
Net income (loss)	275.8			214.2			263.1			(442.5		)	310.6
Net income attributable to non-controlling partner	—			—			34.8			—			34.8
Net income (loss) attributable to Crestwood Midstream Partners LP	$	275.8		$	214.2		$	228.3		$	(442.5	)	$	275.8

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2018
(in millions)
	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Revenues	$	—		$	3,654.1	$	—	$	—		$	3,654.1
Costs of product/services sold	—			3,129.4		—		—			3,129.4
Operating expenses and other:
Operations and maintenance	—			125.8		—		—			125.8
General and administrative	55.1			28.4		—		—			83.5
Depreciation, amortization and accretion	—			181.4		—		—			181.4
Loss on long-lived assets, net	—			28.6		—		—			28.6
	55.1			364.2		—		—			419.3
Operating income (loss)	(55.1		)	160.5		—		—			105.4
Earnings from unconsolidated affiliates, net	—			—		53.3		—			53.3
Interest and debt expense, net	(99.2		)	—		—		—			(99.2		)
Loss on modification/extinguishment of debt	(0.9		)	—		—		—			(0.9		)
Equity in net income (loss) of subsidiaries	197.6			—		—		(197.6		)	—
Net income (loss)	42.4			160.5		53.3		(197.6		)	58.6
Net income attributable to non-controlling partner	—			—		16.2		—			16.2
Net income (loss) attributable to Crestwood Midstream Partners LP	$	42.4		$	160.5	$	37.1	$	(197.6	)	$	42.4

Crestwood Midstream Partners
Condensed Consolidating Statements of Operations
Year Ended December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,880.9	$	—		$	—		$	3,880.9
Costs of product/services sold	—			3,374.7		—			—			3,374.7
Operating expenses and other:
Operations and maintenance	—			136.0		—			—			136.0
General and administrative	67.6			25.5		—			—			93.1
Depreciation, amortization and accretion	—			202.7		—			—			202.7
Loss on long-lived assets, net	—			65.6		—			—			65.6
Goodwill impairment	—			38.8		—			—			38.8
Loss on contingent consideration	—			—		57.0			—			57.0
	67.6			468.6		57.0			—			593.2
Operating income (loss)	(67.6		)	37.6		(57.0		)	—			(87.0		)
Earnings from unconsolidated affiliates, net	—			—		47.8			—			47.8
Interest and debt expense, net	(99.4		)	—		—			—			(99.4		)
Loss on modification/extinguishment of debt	(37.7		)	—		—			—			(37.7		)
Other income, net	—			0.8		—			—			0.8
Equity in net income (loss) of subsidiaries	3.9			—		—			(3.9		)	—
Net income (loss)	(200.8		)	38.4		(9.2		)	(3.9		)	(175.5		)
Net income attributable to non-controlling partner	—			—		25.3			—			25.3
Net income (loss) attributable to Crestwood Midstream Partners LP	$	(200.8	)	$	38.4	$	(34.5	)	$	(3.9	)	$	(200.8	)

Condensed Consolidating Statements of Cash Flows

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2019
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(171.0	)	$	469.1		$	126.0		$	—		$	424.1
Cash flows from investing activities:
Acquisition, net of cash acquired	—			—			(462.1		)	—			(462.1		)
Purchases of property, plant and equipment	—			(258.1		)	(197.4		)	—			(455.5		)
Investment in unconsolidated affiliates	—			—			(61.3		)	—			(61.3		)
Capital distributions from unconsolidated affiliates	—			—			35.5			—			35.5
Net proceeds from sale of assets	—			0.8			—			—			0.8
Other	—			(1.1		)	—			—			(1.1		)
Capital contributions to consolidated affiliates	(203.8		)	—			—			203.8			—
Net cash provided by (used in) investing activities	(203.8		)	(258.4		)	(685.3		)	203.8			(943.7		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,307.3			—			—			—			2,307.3
Payments on long-term debt	(1,728.6		)	(0.9		)	—			—			(1,729.5		)
Payments on finance leases	—			(3.5		)	—			—			(3.5		)
Payments for debt-related deferred costs	(9.0		)	—			—			—			(9.0		)
Net proceeds from the issuance of     non-controlling interest	—			—			235.0			—			235.0
Distributions to partners	(235.8		)	—			(25.0		)	—			(260.8		)
Contributions from parent	—			—			203.8			(203.8		)	—
Taxes paid for unit-based compensation vesting	—			(11.0		)	—			—			(11.0		)
Change in intercompany balances	26.2			(195.3		)	169.1			—			—
Net cash provided by (used in) financing activities	360.1			(210.7		)	582.9			(203.8		)	528.5
Net change in cash and restricted cash	(14.7		)	—			23.6			—			8.9
Cash and restricted cash at beginning of period	16.5			—			—			—			16.5
Cash and restricted cash at end of period	$	1.8		$	—		$	23.6		$	—		$	25.4

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2018
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(131.7	)	$	339.2		$	53.0		$	—		$	260.5
Cash flows from investing activities:
Purchases of property, plant and equipment	—			(305.5		)	—			—			(305.5		)
Investment in unconsolidated affiliates	—			—			(64.4		)	—			(64.4		)
Capital distributions from unconsolidated affiliates	—			—			49.2			—			49.2
Net proceeds from sale of assets	—			79.5			—			—			79.5
Capital distributions from consolidated affiliates	27.9			—			—			(27.9		)	—
Net cash provided by (used in) investing activities	27.9			(226.0		)	(15.2		)	(27.9		)	(241.2		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,274.8			—			—			—			2,274.8
Payments on long-term debt	(2,014.8		)	(0.9		)	—			—			(2,015.7		)
Payments on capital leases	—			(1.6		)	—			—			(1.6		)
Payments for deferred financing costs	(5.7		)	—			—			—			(5.7		)
Distributions to partners	(238.4		)	—			(9.9		)	—			(248.3		)
Distributions to parent	—			—			(27.9		)	27.9			—
Taxes paid for unit-based compensation vesting	—			(7.4		)	—			—			(7.4		)
Change in intercompany balances	103.4			(103.4		)	—			—			—
Other	—			0.1			—			—			0.1
Net cash provided by (used in) financing activities	119.3			(113.2		)	(37.8		)	27.9			(3.8		)
Net change in cash and restricted cash	15.5			—			—			—			15.5
Cash and restricted cash at beginning of period	1.0			—			—			—			1.0
Cash and restricted cash at end of period	$	16.5		$	—		$	—		$	—		$	16.5

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(162.3	)	$	379.2		$	45.3		$	—		$	262.2
Cash flows from investing activities:
Purchases of property, plant and equipment	—			(188.4		)	—			—			(188.4		)
Investment in unconsolidated affiliates	—			—			(58.0		)	—			(58.0		)
Capital distributions from unconsolidated affiliates	—			—			59.9			—			59.9
Net proceeds from sale of assets	—			225.2			—			—			225.2
Capital contributions to consolidated affiliates	4.3			—			—			(4.3		)	—
Net cash provided by (used in) investing activities	4.3			36.8			1.9			(4.3		)	38.7
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,838.6			—			—			—			2,838.6
Payments on long-term debt	(2,912.6		)	(1.3		)	—			—			(2,913.9		)
Payments on capital leases	—			(2.7		)	—			—			(2.7		)
Payments for deferred financing costs	(1.0		)	—			—			—			(1.0		)
Redemption of non-controlling interest	—			—			(202.7		)	—			(202.7		)
Net proceeds from issuance of non-controlling      interest	—			—			175.0			—			175.0
Distributions to partners	(174.0		)	—			(15.2		)	—			(189.2		)
Distributions to parent	—			—			(4.3		)	4.3			—
Taxes paid for unit-based compensation vesting	—			(5.5		)	—			—			(5.5		)
Change in intercompany balances	406.7			(406.7		)	—			—			—
Other	—			0.2			—			—			0.2
Net cash provided by (used in) financing activities	157.7			(416.0		)	(47.2		)	4.3			(301.2		)
Net change in cash and restricted cash	(0.3		)	—			—			—			(0.3		)
Cash and restricted cash at beginning of period	1.3			—			—			—			1.3
Cash and restricted cash at end of period	$	1.0		$	—		$	—		$	—		$	1.0

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Long-Term Debt (Components Of Long-Term Debt) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Apr. 30, 2019	Dec. 31, 2018
Debt Instrument [Line Items]
Obligations under noncompetition agreements and notes to former owners of businesses acquired	$ 0.6		$ 1.5
Debt Issuance Costs, Net	29.1		26.4
Debt, Long-term and Short-term, Combined Amount	2,328.5		1,753.3
Less: current portion	0.2		0.9
Total long-term debt	2,328.3		1,752.4
Crestwood Midstream Revolver | Revolving Credit Facility
Debt Instrument [Line Items]
Credit agreement outstanding carrying value	557.0		578.2
2023 Senior Notes | Crestwood Midstream 2022 senior unsecured notes
Debt Instrument [Line Items]
Carrying Amount	700.0		700.0
2025 Senior Notes | Crestwood Midstream 2022 senior unsecured notes
Debt Instrument [Line Items]
Carrying Amount	500.0		500.0
2027 Senior Notes | Crestwood Midstream 2019 Senior Notes
Debt Instrument [Line Items]
Carrying Amount	$ 600.0	$ 600.0	$ 0.0

XML

Schedule I - Crestwood Equity Partners LP - Parent Only - Condensed Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Statements, Captions [Line Items]
Cash flows from operating activities	$ 420.4	$ 253.6	$ 255.9
Cash flows from investing activities	(943.7)	(241.2)	38.7
Payments on long-term debt	(1,729.5)	(2,015.7)	(2,913.9)
Distributions to partners	(172.4)	(170.8)	(167.6)
Net proceeds from issuance of common units	0.0	0.0	15.2
Net cash provided by (used in) financing activities	531.8	3.5	(294.9)
Cash at beginning of period	0.9
Cash at end of period	25.7	0.9
Parent Company
Condensed Financial Statements, Captions [Line Items]
Cash flows from operating activities	(3.7)	(3.8)	(3.6)
Cash flows from investing activities	235.8	238.4	174.0
Distributions to partners	(232.5)	(230.9)	(182.6)
Net proceeds from issuance of common units	0.0	0.0	15.2
Change in intercompany balances	0.4	(3.8)	(3.0)
Net cash provided by (used in) financing activities	(232.1)	(234.7)	(170.4)
Net change in cash	0.0	(0.1)	0.0
Cash at beginning of period	0.2	0.3	0.3
Cash at end of period	$ 0.2	$ 0.2	$ 0.3

XML

Condensed Consolidating Financial Information (Statements Of Cash Flows) (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Cash flows from operating activities		$ 420.4	$ 253.6	$ 255.9
Cash flows from investing activities:
Acquisition, net of cash acquired		(462.1)	0.0	0.0
Purchases of property, plant and equipment		(455.5)	(305.5)	(188.4)
Investment in unconsolidated affiliates		(61.3)	(64.4)	(58.0)
Net proceeds from sale of assets		0.8	79.5	225.2
Other		(1.1)	0.0	0.0
Capital distributions from unconsolidated affiliates		35.5	49.2	59.9
Net cash provided by (used in) investing activities		(943.7)	(241.2)	38.7
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		2,307.3	2,274.8	2,838.6
Payments on long-term debt		(1,729.5)	(2,015.7)	(2,913.9)
Payments on finance leases		3.5
Payments on capital leases			(1.6)	(2.7)
Payments for deferred financing costs		(9.0)	(5.7)	(1.0)
Redemption of non-controlling interest	$ (202.7)	0.0	0.0	(202.7)
Distributions to partners		(172.4)	(170.8)	(167.6)
Net proceeds from issuance of non-controlling interest	175.0	235.0	0.0	175.0
Taxes paid for unit-based compensation vesting		(11.0)	(7.4)	(5.5)
Other		0.0	(0.1)	(0.1)
Net cash provided by (used in) financing activities		531.8	3.5	(294.9)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect		8.5	15.9	(0.3)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	1.3	25.7	17.2	1.3	$ 1.6
Eliminations
Cash flows from operating activities		0.0	0.0	0.0
Cash flows from investing activities:
Acquisition, net of cash acquired		0.0
Purchases of property, plant and equipment		0.0	0.0	0.0
Investment in unconsolidated affiliates		0.0	0.0	0.0
Net proceeds from sale of assets		0.0	0.0	0.0
Other		0.0
Capital distributions from unconsolidated affiliates		0.0	0.0	0.0
Capital contributions to consolidated affiliates		203.8	(27.9)	(4.3)
Net cash provided by (used in) investing activities		203.8	(27.9)	(4.3)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		0.0	0.0	0.0
Payments on long-term debt		0.0	0.0	0.0
Payments on finance leases		0.0
Payments on capital leases			0.0	0.0
Payments for deferred financing costs		0.0	0.0	0.0
Redemption of non-controlling interest				0.0
Distributions to partners		0.0	0.0	0.0
Distributions to partners		(203.8)	27.9	4.3
Net proceeds from issuance of non-controlling interest		0.0		0.0
Taxes paid for unit-based compensation vesting		0.0	0.0	0.0
Change in intercompany balances		0.0	0.0	0.0
Other			0.0	0.0
Net cash provided by (used in) financing activities		(203.8)	27.9	4.3
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect		0.0	0.0	0.0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	0.0	0.0	0.0	0.0	0.0
Parent Company, Crestwood Midstream Partners, LP | Reportable Legal Entities
Cash flows from operating activities		(171.0)	(131.7)	(162.3)
Cash flows from investing activities:
Acquisition, net of cash acquired		0.0
Purchases of property, plant and equipment		0.0	0.0	0.0
Investment in unconsolidated affiliates		0.0	0.0	0.0
Net proceeds from sale of assets		0.0	0.0	0.0
Other		0.0
Capital distributions from unconsolidated affiliates		0.0	0.0	0.0
Capital contributions to consolidated affiliates		(203.8)	27.9	4.3
Net cash provided by (used in) investing activities		(203.8)	27.9	4.3
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		2,307.3	2,274.8	2,838.6
Payments on long-term debt		(1,728.6)	(2,014.8)	(2,912.6)
Payments on finance leases		0.0
Payments on capital leases			0.0	0.0
Payments for deferred financing costs		(9.0)	(5.7)	(1.0)
Redemption of non-controlling interest				0.0
Distributions to partners		(235.8)	(238.4)	(174.0)
Distributions to partners		0.0	0.0	0.0
Net proceeds from issuance of non-controlling interest		0.0		0.0
Taxes paid for unit-based compensation vesting		0.0	0.0	0.0
Change in intercompany balances		26.2	103.4	406.7
Other			0.0	0.0
Net cash provided by (used in) financing activities		360.1	119.3	157.7
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect		(14.7)	15.5	(0.3)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	1.0	1.8	16.5	1.0	1.3
CMLP
Cash flows from operating activities		424.1	260.5	262.2
Cash flows from investing activities:
Acquisition, net of cash acquired		(462.1)
Purchases of property, plant and equipment		(455.5)	(305.5)	(188.4)
Investment in unconsolidated affiliates		(61.3)	(64.4)	(58.0)
Net proceeds from sale of assets		0.8	79.5	225.2
Other		(1.1)
Capital distributions from unconsolidated affiliates		35.5	49.2	59.9
Capital contributions to consolidated affiliates		0.0	0.0	0.0
Net cash provided by (used in) investing activities		(943.7)	(241.2)	38.7
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		2,307.3	2,274.8	2,838.6
Payments on long-term debt		(1,729.5)	(2,015.7)	(2,913.9)
Payments on finance leases		3.5
Payments on capital leases			(1.6)	(2.7)
Payments for deferred financing costs		(9.0)	(5.7)	(1.0)
Redemption of non-controlling interest				(202.7)
Distributions to partners		(260.8)	(248.3)	(189.2)
Distributions to partners		0.0	0.0	0.0
Net proceeds from issuance of non-controlling interest		235.0		175.0
Taxes paid for unit-based compensation vesting		(11.0)	(7.4)	(5.5)
Change in intercompany balances		0.0	0.0	0.0
Other			0.1	0.2
Net cash provided by (used in) financing activities		528.5	(3.8)	(301.2)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect		8.9	15.5	(0.3)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	1.0	25.4	16.5	1.0	1.3
Non-Guarantor Subsidiaries | Reportable Legal Entities
Cash flows from operating activities		126.0	53.0	45.3
Cash flows from investing activities:
Acquisition, net of cash acquired		(462.1)
Purchases of property, plant and equipment		(197.4)	0.0	0.0
Investment in unconsolidated affiliates		(61.3)	(64.4)	(58.0)
Net proceeds from sale of assets		0.0	0.0	0.0
Other		0.0
Capital distributions from unconsolidated affiliates		35.5	49.2	59.9
Capital contributions to consolidated affiliates		0.0	0.0	0.0
Net cash provided by (used in) investing activities		(685.3)	(15.2)	1.9
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		0.0	0.0	0.0
Payments on long-term debt		0.0	0.0	0.0
Payments on finance leases		0.0
Payments on capital leases			0.0	0.0
Payments for deferred financing costs		0.0	0.0	0.0
Redemption of non-controlling interest				(202.7)
Distributions to partners		(25.0)	(9.9)	(15.2)
Distributions to partners		203.8	(27.9)	(4.3)
Net proceeds from issuance of non-controlling interest		235.0		175.0
Taxes paid for unit-based compensation vesting		0.0	0.0	0.0
Change in intercompany balances		169.1	0.0	0.0
Other			0.0	0.0
Net cash provided by (used in) financing activities		582.9	(37.8)	(47.2)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect		23.6	0.0	0.0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	0.0	23.6	0.0	0.0	0.0
Guarantor Subsidiaries | Reportable Legal Entities
Cash flows from operating activities		469.1	339.2	379.2
Cash flows from investing activities:
Acquisition, net of cash acquired		0.0
Purchases of property, plant and equipment		(258.1)	(305.5)	(188.4)
Investment in unconsolidated affiliates		0.0	0.0	0.0
Net proceeds from sale of assets		0.8	79.5	225.2
Other		(1.1)
Capital distributions from unconsolidated affiliates		0.0	0.0	0.0
Capital contributions to consolidated affiliates		0.0	0.0	0.0
Net cash provided by (used in) investing activities		(258.4)	(226.0)	36.8
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		0.0	0.0	0.0
Payments on long-term debt		(0.9)	(0.9)	(1.3)
Payments on finance leases		3.5
Payments on capital leases			(1.6)	(2.7)
Payments for deferred financing costs		0.0	0.0	0.0
Redemption of non-controlling interest				0.0
Distributions to partners		0.0	0.0	0.0
Distributions to partners		0.0	0.0	0.0
Net proceeds from issuance of non-controlling interest		0.0		0.0
Taxes paid for unit-based compensation vesting		(11.0)	(7.4)	(5.5)
Change in intercompany balances		(195.3)	(103.4)	(406.7)
Other			0.1	0.2
Net cash provided by (used in) financing activities		(210.7)	(113.2)	(416.0)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect		0.0	0.0	0.0
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	0.0	0.0	0.0	0.0	0.0
CMLP
Cash flows from operating activities		424.1	260.5	262.2
Cash flows from investing activities:
Acquisition, net of cash acquired		(462.1)	0.0	0.0
Purchases of property, plant and equipment		(455.5)	(305.5)	(188.4)
Investment in unconsolidated affiliates		(61.3)	(64.4)	(58.0)
Net proceeds from sale of assets		0.8	79.5	225.2
Other		(1.1)	0.0	0.0
Capital distributions from unconsolidated affiliates		35.5	49.2	59.9
Net cash provided by (used in) investing activities		(943.7)	(241.2)	38.7
Cash flows from financing activities:
Proceeds from the issuance of long-term debt		2,307.3	2,274.8	2,838.6
Payments on long-term debt		(1,729.5)	(2,015.7)	(2,913.9)
Payments on finance leases		3.5
Payments on capital leases			(1.6)	(2.7)
Payments for deferred financing costs		(9.0)	(5.7)	(1.0)
Redemption of non-controlling interest		0.0	0.0	(202.7)
Distributions to partners		(235.8)	(238.4)	(174.0)
Net proceeds from issuance of non-controlling interest		235.0	0.0	175.0
Taxes paid for unit-based compensation vesting		(11.0)	(7.4)	(5.5)
Other		0.0	0.1	0.2
Net cash provided by (used in) financing activities		528.5	(3.8)	(301.2)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents, Period Increase (Decrease), Including Exchange Rate Effect		8.9	15.5	(0.3)
Cash, Cash Equivalents, Restricted Cash and Restricted Cash Equivalents	$ 1.0	$ 25.4	$ 16.5	$ 1.0	$ 1.3

XML

Risk Management (Notional Amounts and Terms of Company's Derivative Financial Instruments) (Details) bcf in Millions, MMBbls in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) MMBbls bcf	Dec. 31, 2018 USD ($) MMBbls bcf	Dec. 31, 2017 USD ($)
Derivative [Line Items]
Product revenues	$ 252.3	$ 343.3	$ 234.1
Cash collateral received, net	16.9	14.2
Commodity Contract With Credit Contingent Features
Derivative [Line Items]
Aggregate fair value of commodity derivative instruments	1.6	2.2
NYMEX-related net derivative liability position
Derivative [Line Items]
Derivative Liability	28.8	9.4
NYMEX-related cash collateral posted
Derivative [Line Items]
NYMEX margin deposit	40.4	21.7
Commodity Contract
Derivative [Line Items]
Gain (loss) reflected in costs of product/services sold	19.5	29.6	$ (31.2)
Cash collateral received, net	$ 0.1	$ 0.1
Propane, ethane, butane, heating oil and crude oil (MMBbls) | Fixed Price Payor
Derivative [Line Items]
Notional amount | MMBbls	33.5	27.8
Propane, ethane, butane, heating oil and crude oil (MMBbls) | Fixed Price Receiver
Derivative [Line Items]
Notional amount | MMBbls	36.6	30.1
Natural gas (Bcf) | Fixed Price Payor
Derivative [Line Items]
Notional amount | bcf	3.7	1.8
Natural gas (Bcf) | Fixed Price Receiver
Derivative [Line Items]
Notional amount | bcf	8.7	1.8

XML

Certain Balance Sheet Information (Other Long-Term Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Contract liabilities	$ 144.7	$ 65.4
Contingent consideration	57.0	57.0
Operating leases	41.5	0.0
Asset retirement obligations	33.3	27.6
Other long-term liabilities	301.6	173.6
CMLP
Other long-term liabilities	295.6	171.0
Other
Other long-term liabilities	25.1	23.6
Other | CMLP
Other long-term liabilities	$ 19.1	$ 21.0

XML

Revenues Remaining Performance Obligations (Details) $ in Millions	Dec. 31, 2019 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, expected timing of satisfaction, period	17 years
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, remaining performance obligations, amount	$ 99.4
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, remaining performance obligations, amount	$ 86.2
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, remaining performance obligations, amount	$ 79.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, expected timing of satisfaction, period	1 year
Revenue, remaining performance obligations, amount	$ 3.3
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Revenue, remaining performance obligations, amount	$ 275.6

XML

Condensed Consolidating Financial Information

12 Months Ended

Dec. 31, 2019

Condensed Financial Information Disclosure [Abstract]

Condensed Consolidating Financial Information Disclosure

Condensed Consolidating Financial Information

Crestwood Midstream is a holding company (Parent) and owns no operating assets and has no significant operations independent of its subsidiaries. Obligations under Crestwood Midstream’s senior notes and its credit facility are jointly and severally guaranteed by substantially all of its subsidiaries, except for Crestwood Infrastructure, Crestwood Niobrara, Crestwood Northeast, PRBIC and Tres Holdings and their respective subsidiaries (collectively, Non-Guarantor Subsidiaries). Crestwood Midstream Finance Corp., the co-issuer of the senior notes, is Crestwood Midstream’s 100% owned subsidiary and has no material assets, operations, revenues or cash flows other than those related to its service as co-issuer of the Crestwood Midstream senior notes.

The tables below present condensed consolidating financial statements for Crestwood Midstream as Parent on a stand-alone, unconsolidated basis, and Crestwood Midstream’s combined guarantor and combined non-guarantor subsidiaries as of and for the years ended December 31, 2019, 2018 and 2017. The financial information may not necessarily be indicative of the results of operations, cash flows or financial position had the subsidiaries operated as independent entities.

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2019
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	1.8	$	—	$	23.6	$	—		$	25.4
Accounts receivable	—		229.1		12.8		—			241.9
Inventory	—		53.7		—		—			53.7
Other current assets	—		54.6		0.2		—			54.8
Total current assets	1.8		337.4		36.6		—			375.8
Property, plant and equipment, net	—		2,331.3		736.2		—			3,067.5
Goodwill and intangible assets, net	—		650.7		373.4		—			1,024.1
Operating lease right-of-use assets, net	—		51.0		2.8		—			53.8
Investments in consolidated affiliates	4,451.6		—		—		(4,451.6		)	—
Investments in unconsolidated affiliates	—		—		980.4		—			980.4
Other non-current assets	—		1.9		0.5		—			2.4
Total assets	$	4,453.4	$	3,372.3	$	2,129.9	$	(4,451.6	)	$	5,504.0
Liabilities and capital
Current liabilities:
Accounts payable	$	—	$	175.9	$	10.7	$	—		$	186.6
Other current liabilities	25.8		123.9		17.6		—			167.3
Total current liabilities	25.8		299.8		28.3		—			353.9
Long-term liabilities:
Long-term debt, less current portion	2,328.3		—		—		—			2,328.3
Other long-term liabilities	—		174.8		120.8		—			295.6
Deferred income taxes	—		0.7		—		—			0.7
Total liabilities	2,354.1		475.3		149.1		—			2,978.5
Interest of non-controlling partner in subsidiary	—		—		426.2		—			426.2
Partners’ capital	2,099.3		2,897.0		1,554.6		(4,451.6		)	2,099.3
Total liabilities and capital	$	4,453.4	$	3,372.3	$	2,129.9	$	(4,451.6	)	$	5,504.0

Crestwood Midstream Partners LP
Condensed Consolidating Balance Sheet
December 31, 2018
(in millions)
	Parent		Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Assets
Current assets:
Cash	$	0.2	$	—	$	—	$	—		$	0.2
Restricted cash	16.3		—		—		—			16.3
Accounts receivable	—		246.3		19.9		(16.3		)	249.9
Inventory	—		64.6		—		—			64.6
Other current assets	—		46.0		—		—			46.0
Total current assets	16.5		356.9		19.9		(16.3		)	377.0
Property, plant and equipment, net	—		2,202.3		—		—			2,202.3
Goodwill and intangible assets, net	—		692.4		—		—			692.4
Investments in consolidated affiliates	3,800.4		—		—		(3,800.4		)	—
Investments in unconsolidated affiliates	—		—		1,188.2		—			1,188.2
Other non-current assets	—		2.1		—		—			2.1
Total assets	$	3,816.9	$	3,253.7	$	1,208.1	$	(3,816.7	)	$	4,462.0
Liabilities and partners’ capital
Current liabilities:
Accounts payable	$	16.3	$	210.5	$	—	$	(16.3	)	$	210.5
Other current liabilities	20.0		81.8		16.2		—			118.0
Total current liabilities	36.3		292.3		16.2		(16.3		)	328.5
Long-term liabilities:
Long-term debt, less current portion	1,752.4		—		—		—			1,752.4
Other long-term liabilities	—		114.0		57.0		—			171.0
Deferred income taxes	—		0.6		—		—			0.6
Total liabilities	1,788.7		406.9		73.2		(16.3		)	2,252.5
Partners’ capital	2,028.2		2,846.8		953.6		(3,800.4		)	2,028.2
Interest of non-controlling partner in subsidiary	—		—		181.3		—			181.3
Total partners’ capital	2,028.2		2,846.8		1,134.9		(3,800.4		)	2,209.5
Total liabilities and partners’ capital	$	3,816.9	$	3,253.7	$	1,208.1	$	(3,816.7	)	$	4,462.0

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2019
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,111.8		$	70.1		$	—		$	3,181.9
Costs of product/services sold	—			2,544.9			—			—			2,544.9
Operating expenses and other:
Operations and maintenance	—			120.0			18.8			—			138.8
General and administrative	51.2			47.0			—			—			98.2
Depreciation, amortization and accretion	—			179.4			30.5			—			209.9
Loss on long-lived assets, net	—			6.2			—			—			6.2
Gain on acquisition	—			—			(209.4		)	—			(209.4		)
	51.2			352.6			(160.1		)	—			243.7
Operating income (loss)	(51.2		)	214.3			230.2			—			393.3
Earnings from unconsolidated affiliates, net	—			—			32.8			—			32.8
Interest and debt income (expense), net	(115.5		)	—			0.1			—			(115.4		)
Other income, net	—			0.2			—			—			0.2
Equity in net income (loss) of subsidiaries	442.5			—			—			(442.5		)	—
Income (loss) before income taxes	275.8			214.5			263.1			(442.5		)	310.9
Provision for income taxes	—			(0.3		)	—			—			(0.3		)
Net income (loss)	275.8			214.2			263.1			(442.5		)	310.6
Net income attributable to non-controlling partner	—			—			34.8			—			34.8
Net income (loss) attributable to Crestwood Midstream Partners LP	$	275.8		$	214.2		$	228.3		$	(442.5	)	$	275.8

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Operations
Year Ended December 31, 2018
(in millions)
	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries		Eliminations			Consolidated
Revenues	$	—		$	3,654.1	$	—	$	—		$	3,654.1
Costs of product/services sold	—			3,129.4		—		—			3,129.4
Operating expenses and other:
Operations and maintenance	—			125.8		—		—			125.8
General and administrative	55.1			28.4		—		—			83.5
Depreciation, amortization and accretion	—			181.4		—		—			181.4
Loss on long-lived assets, net	—			28.6		—		—			28.6
	55.1			364.2		—		—			419.3
Operating income (loss)	(55.1		)	160.5		—		—			105.4
Earnings from unconsolidated affiliates, net	—			—		53.3		—			53.3
Interest and debt expense, net	(99.2		)	—		—		—			(99.2		)
Loss on modification/extinguishment of debt	(0.9		)	—		—		—			(0.9		)
Equity in net income (loss) of subsidiaries	197.6			—		—		(197.6		)	—
Net income (loss)	42.4			160.5		53.3		(197.6		)	58.6
Net income attributable to non-controlling partner	—			—		16.2		—			16.2
Net income (loss) attributable to Crestwood Midstream Partners LP	$	42.4		$	160.5	$	37.1	$	(197.6	)	$	42.4

Crestwood Midstream Partners
Condensed Consolidating Statements of Operations
Year Ended December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries		Non- Guarantor Subsidiaries			Eliminations			Consolidated
Revenues	$	—		$	3,880.9	$	—		$	—		$	3,880.9
Costs of product/services sold	—			3,374.7		—			—			3,374.7
Operating expenses and other:
Operations and maintenance	—			136.0		—			—			136.0
General and administrative	67.6			25.5		—			—			93.1
Depreciation, amortization and accretion	—			202.7		—			—			202.7
Loss on long-lived assets, net	—			65.6		—			—			65.6
Goodwill impairment	—			38.8		—			—			38.8
Loss on contingent consideration	—			—		57.0			—			57.0
	67.6			468.6		57.0			—			593.2
Operating income (loss)	(67.6		)	37.6		(57.0		)	—			(87.0		)
Earnings from unconsolidated affiliates, net	—			—		47.8			—			47.8
Interest and debt expense, net	(99.4		)	—		—			—			(99.4		)
Loss on modification/extinguishment of debt	(37.7		)	—		—			—			(37.7		)
Other income, net	—			0.8		—			—			0.8
Equity in net income (loss) of subsidiaries	3.9			—		—			(3.9		)	—
Net income (loss)	(200.8		)	38.4		(9.2		)	(3.9		)	(175.5		)
Net income attributable to non-controlling partner	—			—		25.3			—			25.3
Net income (loss) attributable to Crestwood Midstream Partners LP	$	(200.8	)	$	38.4	$	(34.5	)	$	(3.9	)	$	(200.8	)

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2019
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(171.0	)	$	469.1		$	126.0		$	—		$	424.1
Cash flows from investing activities:
Acquisition, net of cash acquired	—			—			(462.1		)	—			(462.1		)
Purchases of property, plant and equipment	—			(258.1		)	(197.4		)	—			(455.5		)
Investment in unconsolidated affiliates	—			—			(61.3		)	—			(61.3		)
Capital distributions from unconsolidated affiliates	—			—			35.5			—			35.5
Net proceeds from sale of assets	—			0.8			—			—			0.8
Other	—			(1.1		)	—			—			(1.1		)
Capital contributions to consolidated affiliates	(203.8		)	—			—			203.8			—
Net cash provided by (used in) investing activities	(203.8		)	(258.4		)	(685.3		)	203.8			(943.7		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,307.3			—			—			—			2,307.3
Payments on long-term debt	(1,728.6		)	(0.9		)	—			—			(1,729.5		)
Payments on finance leases	—			(3.5		)	—			—			(3.5		)
Payments for debt-related deferred costs	(9.0		)	—			—			—			(9.0		)
Net proceeds from the issuance of     non-controlling interest	—			—			235.0			—			235.0
Distributions to partners	(235.8		)	—			(25.0		)	—			(260.8		)
Contributions from parent	—			—			203.8			(203.8		)	—
Taxes paid for unit-based compensation vesting	—			(11.0		)	—			—			(11.0		)
Change in intercompany balances	26.2			(195.3		)	169.1			—			—
Net cash provided by (used in) financing activities	360.1			(210.7		)	582.9			(203.8		)	528.5
Net change in cash and restricted cash	(14.7		)	—			23.6			—			8.9
Cash and restricted cash at beginning of period	16.5			—			—			—			16.5
Cash and restricted cash at end of period	$	1.8		$	—		$	23.6		$	—		$	25.4

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
Year Ended December 31, 2018
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(131.7	)	$	339.2		$	53.0		$	—		$	260.5
Cash flows from investing activities:
Purchases of property, plant and equipment	—			(305.5		)	—			—			(305.5		)
Investment in unconsolidated affiliates	—			—			(64.4		)	—			(64.4		)
Capital distributions from unconsolidated affiliates	—			—			49.2			—			49.2
Net proceeds from sale of assets	—			79.5			—			—			79.5
Capital distributions from consolidated affiliates	27.9			—			—			(27.9		)	—
Net cash provided by (used in) investing activities	27.9			(226.0		)	(15.2		)	(27.9		)	(241.2		)
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,274.8			—			—			—			2,274.8
Payments on long-term debt	(2,014.8		)	(0.9		)	—			—			(2,015.7		)
Payments on capital leases	—			(1.6		)	—			—			(1.6		)
Payments for deferred financing costs	(5.7		)	—			—			—			(5.7		)
Distributions to partners	(238.4		)	—			(9.9		)	—			(248.3		)
Distributions to parent	—			—			(27.9		)	27.9			—
Taxes paid for unit-based compensation vesting	—			(7.4		)	—			—			(7.4		)
Change in intercompany balances	103.4			(103.4		)	—			—			—
Other	—			0.1			—			—			0.1
Net cash provided by (used in) financing activities	119.3			(113.2		)	(37.8		)	27.9			(3.8		)
Net change in cash and restricted cash	15.5			—			—			—			15.5
Cash and restricted cash at beginning of period	1.0			—			—			—			1.0
Cash and restricted cash at end of period	$	16.5		$	—		$	—		$	—		$	16.5

Crestwood Midstream Partners LP
Condensed Consolidating Statements of Cash Flows
December 31, 2017
(in millions)
	Parent			Guarantor Subsidiaries			Non- Guarantor Subsidiaries			Eliminations			Consolidated
Cash flows from operating activities:	$	(162.3	)	$	379.2		$	45.3		$	—		$	262.2
Cash flows from investing activities:
Purchases of property, plant and equipment	—			(188.4		)	—			—			(188.4		)
Investment in unconsolidated affiliates	—			—			(58.0		)	—			(58.0		)
Capital distributions from unconsolidated affiliates	—			—			59.9			—			59.9
Net proceeds from sale of assets	—			225.2			—			—			225.2
Capital contributions to consolidated affiliates	4.3			—			—			(4.3		)	—
Net cash provided by (used in) investing activities	4.3			36.8			1.9			(4.3		)	38.7
Cash flows from financing activities:
Proceeds from the issuance of long-term debt	2,838.6			—			—			—			2,838.6
Payments on long-term debt	(2,912.6		)	(1.3		)	—			—			(2,913.9		)
Payments on capital leases	—			(2.7		)	—			—			(2.7		)
Payments for deferred financing costs	(1.0		)	—			—			—			(1.0		)
Redemption of non-controlling interest	—			—			(202.7		)	—			(202.7		)
Net proceeds from issuance of non-controlling      interest	—			—			175.0			—			175.0
Distributions to partners	(174.0		)	—			(15.2		)	—			(189.2		)
Distributions to parent	—			—			(4.3		)	4.3			—
Taxes paid for unit-based compensation vesting	—			(5.5		)	—			—			(5.5		)
Change in intercompany balances	406.7			(406.7		)	—			—			—
Other	—			0.2			—			—			0.2
Net cash provided by (used in) financing activities	157.7			(416.0		)	(47.2		)	4.3			(301.2		)
Net change in cash and restricted cash	(0.3		)	—			—			—			(0.3		)
Cash and restricted cash at beginning of period	1.3			—			—			—			1.3
Cash and restricted cash at end of period	$	1.0		$	—		$	—		$	—		$	1.0

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Commitments and Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Legal Proceedings

Linde Lawsuit. On December 23, 2019, Linde Engineering North America Inc. (Linde) filed a lawsuit in Harris County, Texas alleging that Arrow Field Services, LLC, our consolidated subsidiary, and Crestwood Midstream breached a contract entered into in March 2018 under which Linde was to provide engineering, procurement and construction services to us related to the completion of the construction of the Bear Den II cryogenic processing plant. Linde claims damages of $55 million in unpaid invoices and other damages. This matter is not an insurable event based on our insurance policies and, we are unable to predict the outcome for this matter.

General. We are periodically involved in litigation proceedings. If we determine that a negative outcome is probable and the amount of loss is reasonably estimable, then we accrue the estimated amount. The results of litigation proceedings cannot be predicted with certainty. We could incur judgments, enter into settlements or revise our expectations regarding the outcome of certain matters, and such developments could have a material adverse effect on our results of operations or cash flows in the period in which the amounts are paid and/or accrued. As of December 31, 2019 and 2018, both CEQP and CMLP had approximately $10.7 million and $0.1 million accrued for outstanding legal matters. Based on currently available information, we believe it is remote that future costs related to known contingent liability exposures for which we can estimate will exceed current accruals by an amount that would have a material adverse impact on our consolidated financial statements. As we learn

new facts concerning contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.

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

Regulatory Compliance

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

Environmental Compliance

Our operations are subject to stringent and complex laws and regulations pertaining to worker health, safety, and the environment. We are subject to laws and regulations at the federal, state, regional and local levels that relate to air and water quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing, constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially criminal enforcement measures.

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

In August 2015, we received a notice of violation from the Three Affiliated Tribes’ Environmental Division related to our 2014 produced water releases on the Fort Berthold Indian Reservation. The notice of violation imposes fines and requests reimbursements exceeding $1.1 million; however, the notice of violation was stayed on September 15, 2015. Our discussions regarding the notice of violation continue with the Three Affiliated Tribes.

During September 2019, we experienced two produced water releases totaling approximately 5,000 barrels on our Arrow system located on the Fort Berthold Indian Reservation in North Dakota. We immediately notified the National Response Center, the State of North Dakota, the Three Affiliated Tribes, affected landowners and numerous other regulatory authorities. We are substantially complete with the remediation efforts and continue to monitor the impact of both spills.

In response to the water releases on our Arrow system, we removed approximately 30 miles of water gathering pipeline from service and incurred a $4.3 million impairment charge during the three months ended December 31, 2019 related to idling those facilities. In addition, we are currently in the process of replacing approximately 12 miles of water gathering pipeline with pipeline composed of higher capacity material that is more suitable to the environment and climate conditions in the Bakken, which will increase water gathering capacity on the Arrow system and further our commitment to sustainability and environmental stewardship in the areas where we live and operate.

We will continue our remediation efforts to ensure the impacted lands are restored to their prior state. We believe these releases are insurable events under our policies, and we have notified our carriers of these events. We have not recorded an insurance receivable as of December 31, 2019.

At December 31, 2019 and 2018, our accrual of approximately $6.7 million and $1.8 million was based on our undiscounted estimate of amounts we will spend on compliance with environmental and other regulations, and any associated fines or penalties. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures could range from approximately $6.7 million to $11.1 million at December 31, 2019.

Self-Insurance

We utilize third-party insurance subject to varying retention levels of self-insurance, which management considers prudent. Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims and general, product, vehicle and environmental liability. Losses are accrued based upon management’s estimates of the aggregate liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The primary assumption utilized is actuarially determined loss development factors. The loss development factors are based primarily on historical data. Our self insurance reserves could be affected if future claim developments differ from the historical trends. We believe changes in health care costs, trends in health care claims of our employee base, accident frequency and severity and other factors could materially affect the estimate for these liabilities. We continually monitor changes in employee demographics, incident and claim type and evaluate our insurance accruals and adjust our accruals based on our evaluation of these qualitative data points. We are liable for the development of claims for our disposed retail propane operations, provided they were reported prior to August 1, 2012. The following table summarizes CEQP’s and CMLP’s self-insurance reserves at December 31, 2019 and 2018 (in millions):

	CEQP				CMLP
	December 31,				December 31,
	2019		2018		2019		2018
Self-insurance reserves(1)	$	9.7	$	11.3	$	8.3	$	9.6

(1) At December 31, 2019, CEQP and CMLP classified approximately $6.2 million and $5.2 million, respectively of these reserves as other long-term liabilities on their consolidated balance sheets.

Leases

The following table summarizes the balance sheet information related to our operating and finance leases at December 31, 2019 (in millions):

Operating Leases
Operating lease right-of-use assets, net	$	53.8
Accrued expenses and other liabilities	$	18.1
Other long-term liabilities	41.5
Total operating lease liabilities	$	59.6
Finance Leases
Property, plant and equipment	$	14.9
Less: accumulated depreciation	5.4
Property, plant and equipment, net	$	9.5
Accrued expenses and other liabilities	$	3.2
Other long-term liabilities	5.2
Total finance lease liabilities	$	8.4

The following table presents the weighted-average remaining lease term and the weighted-average discount rate associated with our operating and finance leases as of December 31, 2019:

Weighted-average remaining lease term (in years):
Operating leases(1)	4.4
Finance leases(2)	2.6
Weighted-average discount rate:
Operating leases(3)	5.9	%
Finance leases(3)	7.3	%

(1) Remaining terms vary from one year to 20 years.

(2) Remaining terms vary from one year to four years.

(3) We utilized discount rates ranging from 3.5% to 8.3% to estimate the discounted cash flows used in estimating our right-of-use assets and lease liabilities as of December 31, 2019, which were primarily based on our credit-adjusted collateralized incremental borrowing rate.

The estimation of our right-of-use assets and lease liabilities requires us to make significant assumptions and judgments about the terms of the leases, variable payments, and discount rates. Our operating leases have renewal options to extend the leases from one year to 10 years at the end of each lease term, or terminate the leases at our sole discretion. In addition, our finance leases have options to purchase the lease property by the end of the lease term. We make significant assumptions on the likelihood on whether we will renew our leases or purchase the property at the end of the lease terms in determining the discounted cash flows to measure our right-of-use assets and lease liabilities. The estimation of variable lease payments in determining discounted cash flows, including those with usage-based costs, also requires us to make significant assumptions on the timing and nature of the variability of those payments based on the lease terms.

We recognize operating lease expense and amortize our right-of-use assets for our finance leases on a straight-line basis over the term of the respective leases. We have applied the practical expedient of not separating the lease and non-lease components for our leases where the predominant consideration paid related to the underlying operating and finance lease contracts relate to the lease component. The following table presents the costs and sublease income associated with our operating and finance leases for the year ended December 31, 2019 (in millions):

Operating leases:
Operating lease expense(1)(2)	$	28.3
Sublease income(3)	(1.0		)
Total operating lease expense, net	$	27.3
Finance leases:
Amortization of right-of-use assets(4)	$	3.6
Interest on lease liabilities(5)	0.7
Total finance lease expense	$	4.3

(1) Approximately $17.5 million is included in costs of product/services sold and $10.8 million is included in operations and maintenance expense on our consolidated statements of operations for the year ended December 31, 2019.

(2) Includes short-term and variable lease costs of approximately $3.7 million for the year ended December 31, 2019.

(3) Included in marketing, supply and logistics service revenues on our consolidated statements of operations.

(4) Included in depreciation, amortization and accretion expense on our consolidated statements of operations.

(5) Included in interest and debt expense, net on our consolidated statements of operations.

The following table presents supplemental cash flow information for our operating and finance leases for the year ended December 31, 2019 (in millions):

Cash paid for lease liabilities:
Operating cash flows from operating leases	$	22.9
Operating cash flows from finance leases	$	0.7
Financing cash flows from finance leases	$	3.5
Right-of-use assets obtained in exchange for lease obligations:
Operating leases(1)	$	4.2
Finance leases	$	1.8

(1) Includes approximately $2.9 million of operating leases obtained from the Jackalope Acquisition, which is further discussed in Note 3.

The following table presents the future minimum lease liabilities under Topic 842 for our leases as of December 31, 2019 for the next five years and in total thereafter (in millions):

Year Ending December 31,	Operating Leases		Finance Leases		Total
2020	$	20.9	$	3.6	$	24.5
2021	16.3		3.6		19.9
2022	11.1		1.9		13.0
2023	6.7		0.1		6.8
2024	6.0		—		6.0
Thereafter	7.5		—		7.5
Total lease payments	68.5		9.2		77.7
Less: Interest	8.9		0.8		9.7
Present value of lease liabilities	$	59.6	$	8.4	$	68.0

Purchase Commitments

We periodically enter into agreements with suppliers to purchase fixed quantities of NGLs, distillates, crude oil and natural gas at fixed prices. At December 31, 2019, the total of these firm purchase commitments was $792.4 million, of which approximately $712.3 million will occur over the course of the next twelve months. We also enter into non-binding agreements with suppliers to purchase quantities of NGLs, distillates and natural gas at variable prices at future dates at the then prevailing market prices.

We have entered into certain purchase commitments primarily related to our gathering and processing segment. At December 31, 2019, our total purchase commitments were approximately $126.6 million, which primarily relate to future growth projects and maintenance obligations in our gathering and processing segment. The purchases associated with these commitments are expected to occur over the next twelve months.

Guarantees and Indemnifications

We are involved in various joint ventures that sometimes require financial and performance guarantees. In a financial guarantee, we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements related to assets or businesses we have sold. For a further description of our guarantees associated with our joint ventures, see Note 6.

Our potential exposure under guarantee and indemnification arrangements can range from a specified amount to an unlimited dollar amount, depending on the nature of the claim, specificity as to duration, and the particular transaction. As of December 31, 2019, we have no amounts accrued for these guarantees.

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2019

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

The following table shows transactions with our affiliates which are reflected in our consolidated statements of operations for the years December 31, 2019, 2018 and 2017 (in millions):

	Year Ended December 31,
	2019			2018			2017
Revenues at CEQP and CMLP	$	2.9		$	1.0		$	1.8
Costs of product/services sold at CEQP and CMLP(1)	$	45.4		$	134.7		$	15.3
Operations and maintenance expenses at CEQP and CMLP(2)	$	25.9		$	28.7		$	22.3
General and administrative expenses charged by CEQP to CMLP, net(3)	$	41.4		$	20.7		$	19.4
General and administrative expenses at CEQP charged from Crestwood Holdings, net(4)	$	(0.6	)	$	(2.7	)	$	(1.7	)

(1) Includes (i) $19.0 million and $56.1 million during the years ended December 31, 2019 and 2018 related to purchases of NGLs from a subsidiary of Crestwood Permian; (ii) $23.9 million and $78.6 million during the years ended December 31, 2019 and 2018 related to an agency marketing agreement with Ascent Resources - Utica, LLC (Ascent); (iii) $0.2 million during the year ended December 31, 2019 related to an agreement with Blue Racer Midstream, LLC (Blue Racer); (iv) $2.3 million during the year ended December 31, 2019 related to purchases of natural gas from a subsidiary of Stagecoach Gas; and (v) $15.3 million during the year ended December 31, 2017 related to natural gas purchases from Sabine Oil and Gas (Sabine). Ascent, Blue Racer and Sabine are affiliates of Crestwood Holdings for the respective periods presented.

(2) We have operating agreements with certain of our unconsolidated affiliates pursuant to which we charge them operations and maintenance expenses in accordance with their respective agreements, and these charges are reflected as a reduction of operations and maintenance expenses in our consolidated statements of operations. During the year ended December 31, 2019, we charged $7.5 million to Stagecoach Gas, $4.4 million to Tres Palacios, $13.5 million to Crestwood Permian and $0.5 million to Jackalope. During the year ended December 31, 2018, we charged $7.9 million to Stagecoach Gas, $3.8 million to Tres Palacios, $15.9 million to Crestwood Permian and $1.1 million to Jackalope. During the year ended December 31, 2017, we charged $8.4 million to Stagecoach Gas, $3.5 million to Tres Palacios, $10.0 million to Crestwood Permian and $0.4 million to Jackalope.

(3) Includes $45.1 million, $24.3 million and $22.4 million of net unit-based compensation charges allocated from CEQP to CMLP for the years ended December 31, 2019, 2018 and 2017. In addition, includes $3.7 million, $3.6 million and $3.0 million of CMLP’s general and administrative costs allocated to CEQP during the years ended December 31, 2019, 2018 and 2017.

(4) Includes $1.9 million, $4.2 million and $3.1 million of unit-based compensation charges allocated from Crestwood Holdings to CEQP and CMLP during the years ended December 31, 2019, 2018 and 2017.

Schedule of Related Party Receivables and Payables

The following table shows accounts receivable and accounts payable from our affiliates as of December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Accounts receivable at CEQP and CMLP	$	7.3	$	4.1
Accounts payable at CEQP	$	15.6	$	16.1
Accounts payable at CMLP	$	13.1	$	13.6

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Organization and Description of Business (Narrative) (Details) - 12 months ended Dec. 31, 2019	Total	segment	reporting_units
Partnership Organization And Basis Of Presentation [Line Items]
Number of operating segments		3	3
Crestwood Equity Partners LP
Partnership Organization And Basis Of Presentation [Line Items]
Limited partnership interest	99.90%
Crestwood Gas Services GP, LLC
Partnership Organization And Basis Of Presentation [Line Items]
Limited partnership interest	0.10%
Common Unit Capital | Crestwood Holdings
Partnership Organization And Basis Of Presentation [Line Items]
General partner ownership percentage	25.00%

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Condensed Consolidating Financial Information (Statements Of Operations) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenues:
Revenues	$ 3,181.9	$ 3,654.1	$ 3,880.9
Costs of product/services sold (exclusive of items shown separately below):
Product costs - related party (Note 16)	45.4	134.7	15.3
Total costs of products/services sold	2,544.9	3,129.4	3,374.7
Operating expenses and other:
Operations and maintenance	138.8	125.8	136.0
General and administrative	103.4	88.1	96.5
Depreciation, amortization and accretion	195.8	168.7	191.7
Goodwill impairment	0.0	0.0	38.8
Loss on contingent consideration	0.0	0.0	57.0
Loss on long-lived assets, net	6.2	28.6	65.6
Gain on acquisition	(209.4)	0.0	0.0
Total expenses	234.8	411.2	585.6
Operating income (loss)	402.2	113.5	(79.4)
Other income (expense):
Earnings from unconsolidated affiliates, net	32.8	53.3	47.8
Interest and debt expense, net	(115.4)	(99.2)	(99.4)
Loss on modification/extinguishment of debt	0.0	(0.9)	(37.7)
Other income, net	0.6	0.4	1.3
Income (loss) before income taxes	320.2	67.1	(167.4)
(Provision) benefit for income taxes	(0.3)	(0.1)	0.8
Net income (loss)	319.9	67.0	(166.6)
Net income attributable to non-controlling partner	34.8	16.2	25.3
Net income (loss) attributable to parent	285.1	50.8	(191.9)
Net income attributable to preferred units	60.1	60.1	62.5
Net income (loss) attributable to partners	225.0	(9.3)	(254.4)
Eliminations
Revenues:
Revenues	0.0	0.0	0.0
Costs of product/services sold (exclusive of items shown separately below):
Total costs of products/services sold	0.0	0.0	0.0
Operating expenses and other:
Operations and maintenance	0.0	0.0	0.0
General and administrative	0.0	0.0	0.0
Depreciation, amortization and accretion	0.0	0.0	0.0
Goodwill impairment			0.0
Loss on contingent consideration			0.0
Loss on long-lived assets, net	0.0	0.0	0.0
Gain on acquisition	0.0
Total expenses	0.0	0.0	0.0
Operating income (loss)	0.0	0.0	0.0
Other income (expense):
Earnings from unconsolidated affiliates, net	0.0	0.0	0.0
Interest and debt expense, net	0.0	0.0	0.0
Loss on modification/extinguishment of debt		0.0	0.0
Other income, net			0.0
Other income, net	0.0
Loss from unconsolidated affiliates	(442.5)	(197.6)	(3.9)
Income (loss) before income taxes	(442.5)
(Provision) benefit for income taxes	0.0
Net income (loss)	(442.5)	(197.6)	(3.9)
Net income attributable to non-controlling partner	0.0	0.0	0.0
Net income (loss) attributable to parent	(442.5)	(197.6)
Net income (loss) attributable to partners			(3.9)
Parent Company, Crestwood Midstream Partners, LP | Reportable Legal Entities
Revenues:
Revenues	0.0	0.0	0.0
Costs of product/services sold (exclusive of items shown separately below):
Total costs of products/services sold	0.0	0.0	0.0
Operating expenses and other:
Operations and maintenance	0.0	0.0	0.0
General and administrative	51.2	55.1	67.6
Depreciation, amortization and accretion	0.0	0.0	0.0
Goodwill impairment			0.0
Loss on contingent consideration			0.0
Loss on long-lived assets, net	0.0	0.0	0.0
Gain on acquisition	0.0
Total expenses	51.2	55.1	67.6
Operating income (loss)	(51.2)	(55.1)	(67.6)
Other income (expense):
Earnings from unconsolidated affiliates, net	0.0	0.0	0.0
Interest and debt expense, net	(115.5)	(99.2)	(99.4)
Loss on modification/extinguishment of debt		(0.9)	(37.7)
Other income, net			0.0
Other income, net	0.0
Loss from unconsolidated affiliates	442.5	197.6	3.9
Income (loss) before income taxes	275.8
(Provision) benefit for income taxes	0.0
Net income (loss)	275.8	42.4	(200.8)
Net income attributable to non-controlling partner	0.0	0.0	0.0
Net income (loss) attributable to parent	275.8	42.4
Net income (loss) attributable to partners			(200.8)
Guarantor Subsidiaries | Reportable Legal Entities
Revenues:
Revenues	3,111.8	3,654.1	3,880.9
Costs of product/services sold (exclusive of items shown separately below):
Total costs of products/services sold	2,544.9	3,129.4	3,374.7
Operating expenses and other:
Operations and maintenance	120.0	125.8	136.0
General and administrative	47.0	28.4	25.5
Depreciation, amortization and accretion	179.4	181.4	202.7
Goodwill impairment			38.8
Loss on contingent consideration			0.0
Loss on long-lived assets, net	6.2	28.6	65.6
Gain on acquisition	0.0
Total expenses	352.6	364.2	468.6
Operating income (loss)	214.3	160.5	37.6
Other income (expense):
Earnings from unconsolidated affiliates, net	0.0	0.0	0.0
Interest and debt expense, net	0.0	0.0	0.0
Loss on modification/extinguishment of debt		0.0	0.0
Other income, net			0.8
Other income, net	0.2
Loss from unconsolidated affiliates	0.0	0.0	0.0
Income (loss) before income taxes	214.5
(Provision) benefit for income taxes	(0.3)
Net income (loss)	214.2	160.5	38.4
Net income attributable to non-controlling partner	0.0	0.0	0.0
Net income (loss) attributable to parent	214.2	160.5
Net income (loss) attributable to partners			38.4
Non-Guarantor Subsidiaries | Reportable Legal Entities
Revenues:
Revenues	70.1	0.0	0.0
Costs of product/services sold (exclusive of items shown separately below):
Total costs of products/services sold	0.0	0.0	0.0
Operating expenses and other:
Operations and maintenance	18.8	0.0	0.0
General and administrative	0.0	0.0	0.0
Depreciation, amortization and accretion	30.5	0.0	0.0
Goodwill impairment			0.0
Loss on contingent consideration			57.0
Loss on long-lived assets, net	0.0	0.0	0.0
Gain on acquisition	(209.4)
Total expenses	(160.1)	0.0	57.0
Operating income (loss)	230.2	0.0	(57.0)
Other income (expense):
Earnings from unconsolidated affiliates, net	32.8	53.3	47.8
Interest and debt expense, net	0.1	0.0	0.0
Loss on modification/extinguishment of debt		0.0	0.0
Other income, net			0.0
Other income, net	0.0
Loss from unconsolidated affiliates	0.0	0.0	0.0
Income (loss) before income taxes	263.1
(Provision) benefit for income taxes	0.0
Net income (loss)	263.1	53.3	(9.2)
Net income attributable to non-controlling partner	34.8	16.2	25.3
Net income (loss) attributable to parent	228.3	37.1
Net income (loss) attributable to partners			(34.5)
CMLP
Revenues:
Revenues	3,181.9	3,654.1	3,880.9
Costs of product/services sold (exclusive of items shown separately below):
Total costs of products/services sold	2,544.9	3,129.4	3,374.7
Operating expenses and other:
Operations and maintenance	138.8	125.8	136.0
General and administrative	98.2	83.5	93.1
Depreciation, amortization and accretion	209.9	181.4	202.7
Goodwill impairment			38.8
Loss on contingent consideration			57.0
Loss on long-lived assets, net	6.2	28.6	65.6
Gain on acquisition	(209.4)
Total expenses	243.7	419.3	593.2
Operating income (loss)	393.3	105.4	(87.0)
Other income (expense):
Earnings from unconsolidated affiliates, net	32.8	53.3	47.8
Interest and debt expense, net	(115.4)	(99.2)	(99.4)
Loss on modification/extinguishment of debt		(0.9)	(37.7)
Other income, net			0.8
Other income, net	0.2
Loss from unconsolidated affiliates	0.0	0.0	0.0
Income (loss) before income taxes	310.9
(Provision) benefit for income taxes	(0.3)
Net income (loss)	310.6	58.6	(175.5)
Net income attributable to non-controlling partner	34.8	16.2	25.3
Net income (loss) attributable to parent	$ 275.8	$ 42.4
Net income (loss) attributable to partners			$ (200.8)

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Investments in Unconsolidated Affiliates - Narrative (Details) - USD ($) $ in Millions				1 Months Ended		6 Months Ended	12 Months Ended
	Jul. 01, 2018	Jan. 01, 2018	Jun. 21, 2017	Jan. 31, 2020	Oct. 31, 2017	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jun. 30, 2019	Apr. 30, 2019	Apr. 09, 2019	Apr. 08, 2019
Schedule of Equity Method Investments [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification							$ 0.7
Contributions							61.3	$ 64.4	$ 58.0
Investments in unconsolidated affiliates							980.4	1,188.2
Contingent consideration							57.0	57.0
Loss on contingent consideration							0.0	0.0	57.0
Earnings from unconsolidated affiliates, net							32.8	53.3	47.8
Net proceeds from sale of assets							0.8	79.5	225.2
Contribution of Property			$ 69.4
Distributions							75.2	103.0	107.6
Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates							0.0	210.2				$ 226.7
Earnings from unconsolidated affiliates, net							3.7	18.1	10.5
Amortization							$ 0.1	0.1	0.1
Equity method ownership percentage							0.00%				50.00%	50.00%	50.00%
Distributions							$ 11.6	32.4	26.3
Tres Palacios Holdings LLC
Schedule of Equity Method Investments [Line Items]
Contributions							6.3	2.5	5.6
Investments in unconsolidated affiliates							35.9	35.0
Earnings from unconsolidated affiliates, net							0.9	0.0	2.2
Difference between carrying amount and underlying equity							24.0
Amortization							$ 1.3	1.3	1.3
Equity method ownership percentage							50.01%
Distributions							$ 6.3	5.3	9.0
Powder River Basin Industrial Complex, LLC
Schedule of Equity Method Investments [Line Items]
Contributions							0.2	0.2	0.0
Investments in unconsolidated affiliates							8.3	8.3
Earnings from unconsolidated affiliates, net							(0.2)	1.5	1.4
Difference between carrying amount and underlying equity							5.5
Amortization							$ 0.4	0.5	0.6
Equity method ownership percentage							50.01%
Distributions							$ 0.0	1.9	1.6
Crestwood Permian Basin Holdings
Schedule of Equity Method Investments [Line Items]
Percentage of Available Cash Distributed							100.00%
Crestwood Permian Basin Holdings | Subsequent Event
Schedule of Equity Method Investments [Line Items]
Distributions				$ 3.8
Crestwood Permian Basin LLC
Schedule of Equity Method Investments [Line Items]
Difference between carrying amount and underlying equity							$ 11.5
Net proceeds from sale of assets					$ 37.9
Stagecoach Gas Services LLC
Schedule of Equity Method Investments [Line Items]
Percentage of Available Cash Distributed	40.00%
Contributions							2.1	0.0	0.8
Investments in unconsolidated affiliates							814.4	830.4
Contingent consideration							57.0	57.0
Earnings from unconsolidated affiliates, net							34.2	29.3	25.3
Difference between carrying amount and underlying equity							$ 51.3
Equity Method Investment Distribution Percentage										40.00%
Equity method ownership percentage	50.00%						50.00%
Distributions							$ 52.3	48.7	47.3
Stagecoach Gas Services LLC | Subsequent Event
Schedule of Equity Method Investments [Line Items]
Distributions				$ 15.5
Crestwood Permian Basin Holdings LLC
Schedule of Equity Method Investments [Line Items]
Contributions							28.3	12.6
Investments in unconsolidated affiliates							121.8	104.3
Earnings from unconsolidated affiliates, net							$ (5.8)	4.4	8.4
Equity method ownership percentage							50.00%
Distributions					$ 18.9		$ 5.0	14.7	23.4
Guarantee to third party amount							10.0
Crestwood Niobrara LLC
Schedule of Equity Method Investments [Line Items]
Percentage of voting interests acquired												100.00%
Crestwood Niobrara LLC | Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
Contributions							$ 24.4	49.1	$ 3.5
Crestwood Equity Partners LP | Crestwood Permian Basin Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage									50.00%
First Reserve Management, L.P. | Crestwood Permian Basin Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage									50.00%
SWEPI LP | Crestwood Permian Basin LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage					50.00%
Twin Eagle Powder River Basin, LLC | Powder River Basin Industrial Complex, LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage							50.00%
CEGP | Stagecoach Gas Services LLC
Schedule of Equity Method Investments [Line Items]
Percentage of Available Cash Distributed						35.00%
CMLP
Schedule of Equity Method Investments [Line Items]
Contributions							$ 61.3	64.4	$ 58.0
Investments in unconsolidated affiliates							980.4	1,188.2
Loss on contingent consideration							0.0	0.0	57.0
Earnings from unconsolidated affiliates, net							32.8	53.3	47.8
Net proceeds from sale of assets							$ 0.8	$ 79.5	$ 225.2
CMLP | Tres Palacios Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage							50.01%
CMLP | Stagecoach Gas Services LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage							50.00%
Brookfield Infrastructure Group | Tres Palacios Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage							49.99%
Accounting Standards Update 2014-09 | Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification		$ 9.5
New Accounting Pronouncement, Equity Earnings Decrease							$ 9.7
Williams Partners LP | Crestwood Niobrara LLC
Schedule of Equity Method Investments [Line Items]
Additional voting interest acquired												50.00%
Business Acquisition, Percentage of Voting Interest After Acquisition												100.00%

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Certain Balance Sheet Information (Accrued Expenses and Other Liabilities) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Apr. 30, 2019	Apr. 09, 2019	Apr. 08, 2019	Dec. 31, 2018
Accrued Expenses and Other Liabilities [Line Items]
Deferred revenue	$ 8.8				$ 12.0
Accrued expenses and other liabilities	161.7				112.4
CMLP
Accrued Expenses and Other Liabilities [Line Items]
Accrued expenses	60.3				63.7
Accrued property taxes	6.1				2.6
Income tax payable	0.3				0.3
Interest payable	25.6				19.8
Accrued additions to property, plant and equipment	38.0				10.5
Operating leases	18.1
Finance leases	3.2
Finance leases					2.4
Deferred revenue	8.8				12.0
Accrued expenses and other liabilities	160.4				111.3
Crestwood Equity Partners LP
Accrued Expenses and Other Liabilities [Line Items]
Accrued expenses	61.6				64.8
Accrued property taxes	6.1				2.6
Income tax payable	0.3				0.3
Interest payable	25.6				19.8
Accrued additions to property, plant and equipment	38.0				10.5
Operating leases	18.1
Finance leases	3.2
Finance leases					2.4
Deferred revenue	8.8				12.0
Accrued expenses and other liabilities	$ 161.7				$ 112.4
Jackalope Gas Gathering Services, LLC
Accrued Expenses and Other Liabilities [Line Items]
Equity method ownership percentage	0.00%	50.00%	50.00%	50.00%
Jackalope Gas Gathering Services, LLC
Accrued Expenses and Other Liabilities [Line Items]
Accrued expenses	$ 16.2

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Revenues Contract Assets and Liabilities (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Revenue from Contract with Customer [Abstract]
Contract with Customer, Asset, Gross, Noncurrent	$ 1.2	$ 1.0
Deferred revenue	8.8	12.0
Contract liabilities	144.7	$ 65.4
Contract with Customer, Liability, Revenue Recognized	$ 13.3

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Fair Value Measurements (Assets And Liabilities Measured At Fair Value On Recurring Basis) (Details) - Fair Value, Measurements, Recurring - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Assets, Fair Value Disclosure [Abstract]
Assets from price risk management	$ 167.7	$ 173.1
SPH units	3.1	2.8
Assets, Fair Value Disclosure, Excluding Netting Adjustments	170.8	175.9
Netting Agreements	(122.3)	(140.3)
Derivative Asset, Fair Value of Collateral	(2.2)	1.9
Assets from price risk management, Total	43.2	34.7
Total assets at fair value	46.3	37.5
Liabilities, Fair Value Disclosure [Abstract]
Liabilities from price risk management	154.7	151.7
Liabilities, Fair Value Disclosure, Excluding Netting Adjustments	154.7	151.7
Netting Agreements	(122.3)	(140.3)
Derivative Liability, Fair Value of Collateral	(25.7)	(5.6)
Liabilities from price risk management, Total	6.7	5.8
Total liabilities at fair value		5.8
Level 1
Assets, Fair Value Disclosure [Abstract]
Assets from price risk management	3.7	12.4
SPH units	3.1	2.8
Assets, Fair Value Disclosure, Excluding Netting Adjustments	6.8	15.2
Liabilities, Fair Value Disclosure [Abstract]
Liabilities from price risk management	2.8	7.0
Liabilities, Fair Value Disclosure, Excluding Netting Adjustments	2.8	7.0
Level 2
Assets, Fair Value Disclosure [Abstract]
Assets from price risk management	164.0	160.7
SPH units	0.0	0.0
Assets, Fair Value Disclosure, Excluding Netting Adjustments	164.0	160.7
Liabilities, Fair Value Disclosure [Abstract]
Liabilities from price risk management	151.9	144.7
Liabilities, Fair Value Disclosure, Excluding Netting Adjustments	151.9	144.7
Level 3
Assets, Fair Value Disclosure [Abstract]
Assets from price risk management	0.0	0.0
SPH units	0.0	0.0
Assets, Fair Value Disclosure, Excluding Netting Adjustments	0.0	0.0
Liabilities, Fair Value Disclosure [Abstract]
Liabilities from price risk management	0.0	0.0
Liabilities, Fair Value Disclosure, Excluding Netting Adjustments	$ 0.0	$ 0.0

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Schedule I - Crestwood Equity Partners LP - Parent Only - Statement of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	$ 319.9	$ 67.0	$ (166.6)
Change in fair value of Suburban Propane Partners, LP units	0.3	(0.7)	(0.8)
Comprehensive income (loss)	320.2	66.3	(167.4)
Parent Company
Condensed Financial Statements, Captions [Line Items]
Net income (loss)	285.1	50.8	(191.9)
Change in fair value of Suburban Propane Partners, LP units	0.3	(0.7)	(0.8)
Comprehensive income (loss)	$ 285.4	$ 50.1	$ (192.7)

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Basis of Presentation and Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation and Summary of Significant Accounting Policies

Basis of Presentation

Our consolidated financial statements are prepared in accordance with GAAP and include the accounts of all consolidated subsidiaries after the elimination of all intercompany accounts and transactions. In management’s opinion, all necessary adjustments to fairly present our results of operations, financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and recurring nature.

Significant Accounting Policies

Principles of Consolidation

We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The determination to consolidate or apply the equity method of accounting to an entity can also require us to evaluate whether that entity is considered a variable interest entity (VIE). This evaluation, along with the determination of our ability to control, direct or exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can exert significant influence over, but do not control or direct the policies, decisions or activities of an entity and in the case of a VIE, are not the primary beneficiary. We use the cost method of accounting where we are unable to exert significant influence over the entity. All of our consolidated entities and equity method investments are not VIEs except for our investment in Crestwood Permian Basin Holdings LLC (Crestwood Permian).

Our equity interest in Crestwood Permian is considered a VIE because CEQP has provided a guarantee to a third party that requires CEQP to pay up to $10 million if Crestwood Permian fails to honor its obligations to its equity investee, Crestwood

Permian Basin, in the event Crestwood Permian Basin fails to satisfy its obligations under its gas gathering agreement with a third party. We account for our investment in Crestwood Permian as an equity method investment because we are not the primary beneficiary of the VIE as of December 31, 2019 and 2018. See Note 6 for a further discussion of our investment in Crestwood Permian.

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.

Restricted Cash

On January 1, 2018, we adopted the provisions of ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) which changed the classification and presentation of restricted cash in the statement of cash flows. The standard requires us to include restricted cash in our total cash when reconciling the beginning of period and end of period amounts shown on our consolidated statements of cash flows. The retrospective application of this ASU did not have an impact on our consolidated statement of cash flows for the year ended December 31, 2017.

Our restricted cash represents cash held under the terms of certain contractual agreements and is classified as current on our consolidated balance sheets. The $16.3 million decrease in restricted cash during the year ended December 31, 2019 and the $16.3 million increase in restricted cash during the year ended December 31, 2018 is included in operating activities (change in accounts payable, accrued expenses and other liabilities) in the consolidated statements of cash flows.

Inventory

Our inventory is stated at the lower of cost or net realizable value and cost is computed predominantly using the average cost method. Inventory consisted of the following at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Crude oil and NGLs	$	53.2	$	64.2
Spare parts	0.5		0.4
Total inventory	$	53.7	$	64.6

Property, Plant and Equipment

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

	Years
Gathering systems and pipelines	15 - 20
Facilities and equipment	3 - 25
Buildings, rights-of-way and easements	1 - 40
Office furniture and fixtures	5 - 10
Vehicles	5

We evaluate our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset

and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset, which is typically based on discounted cash flow projections using assumptions as to revenues, costs and discount rates typical of third party market participants, which is a Level 3 fair value measurement.

During 2019 and 2017, we recorded impairments of our property, plant and equipment and we reflected these impairments in long on long-lived assets in our consolidated statements of operations. We did not record impairments of our property, plant and equipment during the year ended December 31, 2018. During 2019, we incurred $4.3 million of impairments of our property, plant and equipment related to certain of our water gathering facilities in our Arrow operations which is further discussed in Note 15. During 2017, we incurred $81.4 million of impairments of our property, plant and equipment related to our MS&L West Coast operations, which resulted from decreasing the forecasted cash flows to be generated by those operations. At December 31, 2017, our estimates of fair value considered a number of factors, including the potential value if we sold the asset, a 12% discount rate and projected cash flows, which is a Level 3 fair value measurement. During 2018, we sold our MS&L West Coast operations for $70.5 million, and recorded a loss on long-lived assets of approximately $26.9 million (including $9.0 million related to the write off of goodwill). See “Goodwill” below and Note 3 for further information on the sale of these assets.

Projected cash flows of our property, plant and equipment are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, constructions costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Identifiable Intangible Assets

Our identifiable intangible assets consist of customer accounts, trademarks and certain revenue contracts. These intangible assets have arisen primarily from acquisitions. We amortize certain of our revenue contracts based on the projected cash flows associated with these contracts if the projected cash flows are readily determinable, otherwise we amortize our revenue contracts on a straight-line basis.  We recognize acquired intangible assets separately if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

We did not record impairments of our intangible assets during the years ended December 31, 2019 and 2018. During 2017, we fully impaired $0.8 million of intangible assets related to our MS&L West Coast operations, which resulted from decreasing forecasted cash flows to be generated by those operations and we reflected the impairment in loss on long-lived assets in our consolidated statements of operations. During 2018, we sold our MS&L West Coast operations for $70.5 million, and recorded a $26.9 million of loss on long-lived assets associated with the sale. See Note 3 for further information on the sale of these assets.

Projected cash flows of our intangible assets are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:

	Weighted-Average Life (years)
Customer accounts and revenue contracts	20
Trademarks	10

Goodwill

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

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

Upon acquisition, we are required to record the assets, liabilities and goodwill of a reporting unit at its fair value on the date of acquisition. As a result, any level of decrease in the forecasted cash flows of these businesses or increases in the discount rates utilized to value those businesses from their respective acquisition dates would likely result in the fair value of the reporting unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill is impaired.

Current commodity prices are significantly lower compared to commodity prices during 2014, and that decrease has adversely impacted forecasted cash flows, discount rates and stock/unit prices for most companies in the midstream industry, including us. As a result, we recorded goodwill impairments on several of our reporting units during 2017. We did not record impairments of our goodwill during the years ended December 31, 2019 and 2018. At December 31, 2019, our accumulated goodwill impairments at CEQP and CMLP were approximately $1,656.5 million and $1,399.3 million, respectively. The following table summarizes the goodwill of our various reporting units (in millions):

	Goodwill Impairments during the Year Ended December 31, 2017		Goodwill at January 1, 2018		Other				Impact of Sale of West Coast				Goodwill at December 31, 2018		Goodwill Addition during the Year Ended December 31, 2019			Goodwill at December 31, 2019
G&P
Arrow	$	—	$	45.9	$	—			$	—			$	45.9	$	—		$	45.9
Powder River Basin	—		—		—				—				—		80.3		(3)	80.3
MS&L
NGL Marketing and Logistics	—		—		101.7			(1)	(9.0		)	(2)	92.7		—			92.7
West Coast	2.4		—		—				—				—		—			—
Supply and Logistics	—		101.7		(101.7		)	(1)	—				—		—			—
Storage and Terminals	36.4		—		—				—				—		—			—
Total	$	38.8	$	147.6	$	—			$	(9.0	)		$	138.6	$	80.3		$	218.9

(1) Reflects the combination of the MS&L reporting units into one NGL Marketing and Logistics reporting unit as further discussed below.

(2) In October 2018, we sold our West Coast assets and wrote off the goodwill attributable to these assets as further discussed below.

(3) In April 2019, we acquired the remaining 50% equity interest in Jackalope from Williams. See Note 3 for a further discussion of the acquisition.

On January 1, 2018, we combined the four reporting units included in the MS&L segment into one NGL Marketing and Logistics reporting unit for the purpose of evaluating goodwill for impairment on an ongoing basis. We combined these reporting units based on a strategic shift in the way in which we manage, operate and report our NGL operations as an integrated platform instead of as four individual stand-alone operations. We allocated approximately $9.0 million of the

goodwill associated with our NGL Marketing and Logistics reporting unit to the West Coast facilities during 2018, and this goodwill was included in the loss on the sale of the West Coast assets. See Note 3 for a further discussion of the sale of our West Coast assets.

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

Leases

We maintain leases in the ordinary course of our business activities. Our leases include those for office buildings, crude oil railroad cars, certain vehicles and other operating facilities and equipment. We also sublease certain of our crude oil railroad cars and trucks to a third party. We do not have any material leases where we are considered to be the lessor. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants.

Prior to January 1, 2019, we classified our leases as either capital or operating leases under ASC Topic 840, Leases (Topic 840). We recognized assets (included in property, plant and equipment) and liabilities (included in accrued expenses and other liabilities and other long-term liabilities) related to our capital leases on our consolidated balance sheets. We also recognized depreciation expense and interest expense related to our capital leases on our consolidated statements of operations. The majority of our lease arrangements were classified as operating leases, under which we did not recognize assets or liabilities on our consolidated balance sheets, but rather recognized lease payments on our consolidated statements of operations as either costs of product/services sold or operations and maintenance expense on a straight-line basis over the lease term.

On January 1, 2019, we adopted the provisions of ASC Topic 842, Leases (Topic 842), which revises the accounting for leases by requiring certain leases to be recognized as assets and liabilities on the balance sheet, and requiring companies to disclose additional information about their leasing arrangements. We adopted the standard using the modified retrospective method. Based on the practical expedients allowed for in the standard, we did not reassess the current GAAP classification of leases, easements and rights of way that existed as of January 1, 2019, and we did not utilize the hindsight method in determining the assets and liabilities to be recorded for our existing leases on January 1, 2019. The adoption of this standard required us to make significant judgments on whether our revenue and expenditure-related contracts were considered to be leases (or contain leases) under Topic 842, and if contracts were considered to be leases whether they should be considered operating leases or finance leases under the new standard. We do not have any material revenue contracts that are considered leases under Topic 842.

Upon the adoption of this standard, on January 1, 2019, we recorded a $67.5 million increase to our operating lease right-of-use assets, an $18.6 million increase to our accrued expenses and other liabilities and a $48.9 million increase to our long-term operating lease liabilities, related to reflecting our operating leases on our consolidated balance sheet as a result of adopting the new standard. We also recorded a $1.6 million increase to our property, plant and equipment, $0.3 million increase to our accrued expenses and other liabilities and a $1.3 million increase to our other long-term liabilities, related to our finance leases (which were all formerly capital leases under Topic 840) as a result of applying the provisions of the new standard to the leases. The adoption of the standard did not result in a material cumulative effect of accounting change to our consolidated financial statements. See Note 15 for a further discussion of our leases.

Investments in Unconsolidated Affiliates

Equity method investments in which we exercise significant influence, but do not control and are not the primary beneficiary, are accounted for using the equity method of accounting. Differences in the basis of investments and the separate net asset values of the investees, if any, are amortized into net income or loss over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill. We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, or if we decide to sell an investment in unconsolidated affiliate, we adjust the carrying values of the asset downward, if necessary, to their estimated fair values. We did not record impairments of our equity method investments during the years ended December 31, 2019, 2018 and 2017.

Asset Retirement Obligations

An asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. We record a liability for legal or contractual obligations to retire our long-lived assets associated with our facilities and right-of-way contracts we hold. We record a liability in the period the obligation is incurred and estimable. An ARO is initially recorded at its estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the fair value of the liability as a result of the passage of time, which we record as depreciation, amortization and accretion expense on our consolidated statements of operations.

We have various obligations to remove property, plant and equipment on rights-of-way and leases for which we cannot currently estimate the fair value of those obligations because the associated assets have indeterminate lives. An asset retirement obligation liability (and related assets), if any, will be recorded for these obligations once sufficient information is available to reasonably estimate the fair value of the obligations. Our current AROs are reflected in accrued expenses and other liabilities and our long-term AROs are reflected in other long-term liabilities on our consolidated balance sheets. See Note 5 for a further discussion of our AROs.

Deferred Financing Costs

Deferred financing costs represent costs associated with obtaining long-term financing and are amortized over the term of the related debt using a method which approximates the effective interest method and has a weighted average life of five years. Our net deferred financing costs are reflected as a reduction of long-term debt on our consolidated balance sheets.

Revenue Recognition

We provide gathering, processing, compression, storage, fractionation, and transportation (consisting of pipelines, truck and rail terminals, truck/trailer units and rail cars) services and we sell commodities (including crude oil, natural gas, NGLs and water) under various contracts. These contracts include:

• Fixed-fee contracts. Under these contracts, we do not take title to the underlying crude oil, natural gas, NGLs and water but charge our customers a fixed-fee for the services we provide, which can be a firm reservation charge and/or a charge per volume gathered, processed, compressed, stored, loaded and/or transported (which, in certain contracts, can be subject to a minimum level of volumes);

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

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

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

On January 1, 2018, we adopted the provisions of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. We adopted the standard using the modified retrospective method for all revenue contracts that involve revenue generating

activities that occur after January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under the new standard, while amounts prior to January 1, 2018 continue to be reported in accordance with our historic accounting under Revenue Recognition (Topic 605).

Prior to January 1, 2018, we recognized revenues for services and products when all of the following criteria were met under Topic 605: (i) services had been rendered or products delivered or sold; (ii) persuasive evidence of an exchange arrangement existed; (iii) the price for services was fixed or determinable; and (iv) collectability was reasonably assured. We recorded deferred revenue when we received amounts from our customers but had not yet met the criteria listed above. We recognized deferred revenue in our consolidated statement of operations when the criteria had been met and all services had been rendered.

Beginning January 1, 2018, we recognize revenues for services and products under revenue contracts as our obligations to perform services or deliver/sell products under the contracts are satisfied. A contract’s transaction price is allocated to each performance obligation in the contract and recognized as revenue when, or as, the performance obligation is satisfied. Our fixed-fee contracts and our percentage-of-proceeds service contracts primarily have a single performance obligation to deliver a series of distinct goods or services that are substantially the same and have the same pattern of transfer to our customers. For performance obligations associated with these contracts, we recognize revenues over time utilizing the output method based on the actual volumes of products delivered/sold or services performed, because the single performance obligation is satisfied over time using the same performance measure of progress toward satisfaction of the performance obligation. The transaction price under certain of our fixed-fee contracts and percentage-of-proceeds service contracts includes variable consideration that varies primarily based on actual volumes that are delivered under the contracts. Because the variable consideration specifically relates to our efforts to transfer the services and/or products under the contracts, we allocate the variable consideration entirely to the distinct service utilizing the allocation exception guidance under Topic 606, and accordingly recognize the variable consideration as revenues at the time the good or service is transferred to the customer.

Certain of our fixed-fee contracts contain minimum volume features under which the customers must utilize our services to gather, compress or load a specified quantity of crude oil or natural gas or pay a deficiency fee based on the difference between actual volumes and the contractual minimum volume. We recognize revenues from these contracts when actual volumes are gathered, compressed or loaded and the likelihood of a customer exercising its remaining rights to make up the deficient volumes under minimum volume commitments becomes remote.

We recognize revenues at a point in time for performance obligations associated with our percentage-of proceeds product contracts and purchase and sale contracts, and these revenues are recognized because control of the underlying product is transferred to the customer when the distinct good is provided to the customer.

The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our performance obligations requires significant judgments and assumptions, including our evaluation of the timing of when control of the underlying good or service has transferred to our customers and the relative standalone selling price of goods and services provided to customers under contracts with multiple performance obligations. Actual results can significantly vary from those judgments and assumptions. We did not have any material contracts with multiple performance obligations or under which we receive material amounts of non-cash consideration during the year ended December 31, 2019.

Contract Assets and Contract Liabilities. Amounts due from our customers under our revenue contracts are typically billed as the service is being provided or on a weekly, bi-weekly or monthly basis and are due within 30 days of billing. Under certain of our contracts, we recognize revenues in excess of billings which we present as contract assets on our consolidated balance sheets.

Under certain contracts, we may be entitled to receive payments in advance of satisfying our performance obligations under the contract. We recognize a liability for these payments in excess of revenue recognized and present it as deferred revenue or contract liabilities on our consolidated balance sheets. Our deferred revenue primarily relates to:

• Capital Reimbursements. Certain contracts in our G&P segment require that our customers reimburse us for capital expenditures related to the construction of long-lived assets utilized to provide services to them under the revenue contracts. Because we consider these amounts as consideration from customers associated with ongoing services to be provided to customers, we defer these upfront payments in deferred revenue and recognize the amounts in revenue over the life of the associated revenue contract as the performance obligations are satisfied under the contract. On January 1, 2018, we recorded an $87.6 million increase to our property, plant and equipment, net, a $69.1 million increase to our deferred revenue liability and an $18.5 million increase to partners’ capital as a result of applying the cumulative impact of adopting the new standard on these types of contracts.

• Contracts with Increasing (Decreasing) Rates per Unit. Certain contracts in our G&P, S&T and MS&L segments have fixed rates per volume that increase and/or decrease over the life of the contract once certain time periods or thresholds are met. We record revenues on these contracts ratably per unit over the life of the contract based on the remaining performance obligations to be performed, which can result in the deferral of revenue for the difference between the consideration received and the ratable revenue recognized. On January 1, 2018, we recorded a $1.5 million increase to our deferred revenue liability and a corresponding decrease to partners’ capital as a result of applying the cumulative impact of adopting the new standard on these types of contracts.

Credit Risk and Concentrations

Inherent in our contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing credit risk and have established control procedures, which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate.

Income Taxes

Crestwood Equity is a master limited partnership and Crestwood Midstream is a limited partnership. Partnerships are generally not subject to federal income tax, although publicly-traded partnerships are treated as corporations for federal income tax purposes and therefore are subject to federal income tax, unless the partnership generates at least 90% of its gross income from qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a partnership for federal income tax purposes. We satisfy the qualifying income requirement and are treated as a partnership for federal and state income tax purposes. Our consolidated earnings are included in the federal and state income tax returns of our partners. However, legislation in certain states allows for taxation of partnerships, and as such, certain state taxes have been included in our accompanying financial statements as income taxes due to the nature of the tax in those particular states as discussed below. In addition, federal and state income taxes are provided on the earnings of the subsidiaries incorporated as taxable entities. We are required to recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax basis of assets and liabilities using expected rates in effect for the year in which the differences are expected to reverse.

We are responsible for the Texas Margin tax computed on the Texas franchise tax returns. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Environmental Costs and Other Contingencies

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

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

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

Price Risk Management Activities

We utilize certain derivative financial instruments to (i) manage our exposure to commodity price risk, specifically, the related change in the fair value of inventory, as well as the variability of cash flows related to forecasted transactions; (ii) ensure the availability of adequate physical supply of commodity; and (iii) manage our exposure to the interest rate risk associated with fixed and variable rate borrowings. We record all derivative instruments on the balance sheet at their fair values as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded through current earnings.

We did not have any derivatives designated as fair value hedges or cash flow hedges for accounting purposes during the years ended December 31, 2019, 2018 or 2017.

Unit-Based Compensation

Long-term incentive awards are granted under the Crestwood Equity incentive plan. Unit-based compensation awards consist of restricted units that are valued at the closing market price of CEQP’s common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. We generally recognize the expense associated with the award over the vesting period on a straight line basis.

New Accounting Pronouncement Issued But Not Yet Adopted

As of December 31, 2019, the following accounting standard had not yet been adopted by us:

In June 2016, the FASB issued ASU 2016-13, Financial Instruments - Credit Losses (Topic 326), which provides guidance on how companies should evaluate their accounts and notes receivable and other financial instruments for impairment. The standard requires companies to evaluate their financial instruments for impairment by recording an allowance for doubtful accounts and/or bad debt expense based on certain categories of instruments rather than a specific identification approach. We utilized a method to estimate the allowance for doubtful accounts that considered both the aging of our accounts receivable and the projected loss rate of our receivables to adopt the provisions of this standard effective January 1, 2020. Upon adoption of this standard, we anticipate increasing our allowance for doubtful accounts by approximately $0.7 million.

XML

Cover Page - USD ($)

12 Months Ended

Dec. 31, 2019

Feb. 10, 2020

Jun. 28, 2019

Entity Information [Line Items]

Document Type

10-K

Document Annual Report

true

Document Transition Report

false

Entity Registrant Name

Crestwood Equity Partners LP

Entity File Number

001-34664

Entity Incorporation, State or Country Code

DE

Entity Tax Identification Number

43-1918951

Entity Address, Address Line One

811 Main Street

Entity Address, Address Line Two

Suite 3400

Entity Address, City or Town

Houston

Entity Address, State or Province

TX

Entity Address, Postal Zip Code

77002

City Area Code

832

Local Phone Number

519-2200

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Large Accelerated Filer

Entity Small Business

false

Entity Emerging Growth Company

false

Entity Shell Company

false

Entity Public Float

$ 1,800,000,000

Entity Common Stock, Shares Outstanding

72,725,966

Entity Central Index Key

0001136352

Current Fiscal Year End Date

--12-31

Document Period End Date

Dec. 31, 2019

Document Fiscal Year Focus

2019

Document Fiscal Period Focus

FY

Amendment Flag

false

Documents Incorporated by Reference [Text Block]

DOCUMENTS INCORPORATED BY REFERENCE

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

Crestwood Equity Partners LP	None
Crestwood Midstream Partners LP	None

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

CMLP

Entity Information [Line Items]

Document Type

10-K

Entity Registrant Name

Crestwood Midstream Partners LP

Entity File Number

001-35377

Entity Incorporation, State or Country Code

DE

Entity Tax Identification Number

20-1647837

Entity Well-known Seasoned Issuer

No

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Non-accelerated Filer

Entity Small Business

false

Entity Emerging Growth Company

false

Entity Shell Company

false

Entity Public Float

$ 0

Entity Common Stock, Shares Outstanding

0

Entity Central Index Key

0001304464

Document Period End Date

Dec. 31, 2019

Document Fiscal Year Focus

2019

Document Fiscal Period Focus

FY

Amendment Flag

false

Common units

Entity Information [Line Items]

Title of 12(b) Security

Common Units representing limited partnership interests

Trading Symbol

CEQP

Security Exchange Name

NYSE

Preferred Units

Entity Information [Line Items]

Title of 12(b) Security

Preferred Units representing limited partner interests

Trading Symbol

CEQP-P

Security Exchange Name

NYSE

XML

Acquisitions and Divestitures (Narrative) (Details) - Marketing Supply and Logistics - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2018	Dec. 31, 2019	Dec. 31, 2018
West Coast
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration	$ 70.5
Property, Plant and Equipment, Gross, Period Decrease	61.8
Goodwill, Period Decrease	9.0
Decrease in Other Operating Assets	$ 26.6
Gain (Loss) on Sale of Assets and Asset Impairment Charges		$ 26.9	$ 81.4
US Salt, LLC
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Disposal Group, Including Discontinued Operation, Consideration			223.6
Gain (Loss) on Sale of Assets and Asset Impairment Charges			$ 33.6

XML

Basis of Presentation and Summary of Significant Accounting Policies (Revenue Recognition) (Details) - USD ($) $ in Millions		12 Months Ended
	Jan. 01, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 09, 2019
Summary Of Significant Accounting Policies [Line Items]
Property, plant and equipment		$ 3,612.5	$ 2,598.1
Revenues		3,181.9	3,654.1	$ 3,880.9
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification		0.7
ASC 606 Accounts Receivable		$ 225.0	209.7
Revenue, remaining performance obligations, expected timing of satisfaction, period		17 years
Contract with Customer, Asset, Gross, Noncurrent		$ 1.2	1.0
Deferred revenue		8.8	12.0
Contract liabilities		144.7	65.4
Contract with Customer, Liability, Revenue Recognized		13.3
Depreciation, amortization and accretion		195.8	168.7	191.7
Earnings from unconsolidated affiliates, net		32.8	53.3	47.8
Net income (loss)		319.9	67.0	(166.6)
Less: accumulated depreciation		703.4	568.4
Investments in unconsolidated affiliates		980.4	1,188.2
Accrued expenses and other liabilities		161.7	112.4
Other long-term liabilities		301.6	173.6
Partners' capital		1,320.8	1,240.5
Total CEQP/CMLP partners’ capital		1,932.8	1,852.5
Property, plant and equipment, net		2,909.1	2,029.7
Accounting Standards Update 2014-09
Summary Of Significant Accounting Policies [Line Items]
Deferred Revenue	$ 69.1
Property, plant and equipment, net	87.6
Product
Summary Of Significant Accounting Policies [Line Items]
Revenues		2,755.3	3,309.7	3,462.2
Product and service costs		2,469.7	2,950.5	3,309.5
Service
Summary Of Significant Accounting Policies [Line Items]
Revenues		426.6	344.4	418.7
Product and service costs		29.8	44.2	49.9
Gathering and Processing Segment | Product
Summary Of Significant Accounting Policies [Line Items]
Revenues		455.8	670.5	1,369.1
Gathering and Processing Segment | Service
Summary Of Significant Accounting Policies [Line Items]
Revenues		380.0	276.1	317.3
Marketing Supply and Logistics
Summary Of Significant Accounting Policies [Line Items]
Revenues			2,690.3
Marketing Supply and Logistics | Product
Summary Of Significant Accounting Policies [Line Items]
Revenues		2,296.6	2,639.2	2,093.1
Marketing Supply and Logistics | Service
Summary Of Significant Accounting Policies [Line Items]
Revenues		26.2	50.2	62.4
CMLP
Summary Of Significant Accounting Policies [Line Items]
Property, plant and equipment		3,942.6	2,928.2
Revenues		3,181.9	3,654.1	3,880.9
Deferred revenue		8.8	12.0
Depreciation, amortization and accretion		209.9	181.4	202.7
Earnings from unconsolidated affiliates, net		32.8	53.3	47.8
Net income (loss)		310.6	58.6	(175.5)
Less: accumulated depreciation		875.1	725.9
Investments in unconsolidated affiliates		980.4	1,188.2
Accrued expenses and other liabilities		160.4	111.3
Other long-term liabilities		295.6	171.0
Total CEQP/CMLP partners’ capital		2,099.3	2,028.2
Property, plant and equipment, net		3,067.5	2,202.3
CMLP | Product
Summary Of Significant Accounting Policies [Line Items]
Revenues		2,755.3	3,309.7	3,462.2
Product and service costs		2,469.7	2,950.5	3,309.5
CMLP | Service
Summary Of Significant Accounting Policies [Line Items]
Revenues		426.6	344.4	418.7
Product and service costs		29.8	44.2	49.9
CMLP | Gathering and Processing Segment | Product
Summary Of Significant Accounting Policies [Line Items]
Revenues		455.8	670.5	1,369.1
CMLP | Gathering and Processing Segment | Service
Summary Of Significant Accounting Policies [Line Items]
Revenues		380.0	276.1	317.3
CMLP | Marketing Supply and Logistics | Product
Summary Of Significant Accounting Policies [Line Items]
Revenues		2,296.6	2,639.2	2,093.1
CMLP | Marketing Supply and Logistics | Service
Summary Of Significant Accounting Policies [Line Items]
Revenues		26.2	50.2	62.4
Jackalope Gas Gathering Services, LLC
Summary Of Significant Accounting Policies [Line Items]
Earnings from unconsolidated affiliates, net		3.7	18.1	$ 10.5
Investments in unconsolidated affiliates		0.0	$ 210.2		$ 226.7
Jackalope Gas Gathering Services, LLC | Accounting Standards Update 2014-09
Summary Of Significant Accounting Policies [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	9.5
New Accounting Pronouncement, Equity Earnings Decrease		$ 9.7
Capital Reimbursements [Member] | Accounting Standards Update 2014-09
Summary Of Significant Accounting Policies [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	18.5
Contracts with Increasing (Decreasing) Rates per Unit [Member] | Accounting Standards Update 2014-09
Summary Of Significant Accounting Policies [Line Items]
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification	$ 1.5

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Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Statement of Comprehensive Income [Abstract]
Net income (loss)	$ 319.9	$ 67.0	$ (166.6)
Change in fair value of Suburban Propane Partners, L.P. units	0.3	(0.7)	(0.8)
Comprehensive income (loss)	320.2	66.3	(167.4)
Comprehensive income (loss) attributable to non-controlling partners	34.8	16.2	25.3
Comprehensive income (loss) attributable to Crestwood Equity Partners LP	$ 285.4	$ 50.1	$ (192.7)

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Revenues (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Business Acquisition [Line Items]
Contract liabilities	$ 144.7	$ 65.4
ASC 606 Accounts Receivable	$ 225.0	$ 209.7
Revenue, remaining performance obligations, expected timing of satisfaction, period	17 years
Jackalope Gas Gathering Services, LLC
Business Acquisition [Line Items]
Contract liabilities	$ 21.5

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Equity Plans (Schedule of Phantom and Restricted Unit Activity) (Details) - Crestwood Long-Term Incentive Plan - $ / shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Unvested units - December 31, units	2,187,970	1,830,096	1,292,330
Unvested units - December 31	$ 24.78	$ 25.21	$ 24.67
Unvested units - December 31, units	2,355,949	2,187,970	1,830,096
Unvested units - December 31	$ 28.94	$ 24.78	$ 25.21
Restricted units
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted, units	988,096	1,144,017	919,411
Granted	$ 31.48	$ 25.80	$ 25.69
Vested, units	(985,751)	(617,807)	(607,115)
Vested	$ 23.39	$ 23.73	$ 28.00
Canceled, units	(47,547)	(53,530)	(140,137)
Canceled	$ 27.85	$ 23.36	$ 23.73
Performance Shares
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted, units	238,263	901	405,620
Granted	$ 34.21	$ 25.60	$ 30.21
Vested, units	(32,246)	(11,772)	(31,106)
Vested	$ 34.21	$ 28.87	$ 30.27
Canceled, units		(5,870)	(24,756)
Canceled		$ 30.45	$ 30.45
Phantom Share Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Granted, units	7,164	7,750	15,849
Granted	$ 29.03	$ 26.10	$ 25.02
Vested, units		(105,809)
Vested		$ 49.45
Canceled, units		(6)
Canceled		$ 49.45

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Employee Benefit Plan (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Postemployment Benefits [Abstract]
Defined Contribution Plan, Employer Matching Contribution, Percent	90.00%
Defined Benefit Plan, Employee Contributions, Statutory Maximum Per Employee	$ 19,000	$ 18,500	$ 18,000
Defined Contribution Plan Participants Basic Contribution	100.00%
Employer matching contribution, percent	6.00%
Defined Contribution Plan, Requisite Service Period	90 days
Defined Contribution Plan, Employer Discretionary Contribution Amount	$ 4,700,000	$ 4,600,000	$ 4,000,000.0

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Long-Term Debt (Maturities of Long Term Debt) (Details) - CMLP $ in Millions	Dec. 31, 2019 USD ($)
Debt Instrument [Line Items]
2019	$ 0.2
2020	0.2
2021	0.2
2022	1,257.0
2023	0.0
Thereafter	1,100.0
Total debt	$ 2,357.6

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Partners' Capital (Narrative) (Details) - USD ($) $ / shares in Units, $ in Millions																											1 Months Ended				12 Months Ended
	Feb. 14, 2020	Feb. 07, 2020	Nov. 14, 2019	Nov. 07, 2019	Aug. 14, 2019	Aug. 07, 2019	May 15, 2019	May 08, 2019	Feb. 14, 2019	Feb. 07, 2019	Nov. 14, 2018	Nov. 07, 2018	Aug. 14, 2018	Aug. 07, 2018	May 15, 2018	May 08, 2018	Feb. 14, 2018	Feb. 07, 2018	Nov. 14, 2017	Nov. 07, 2017	Aug. 14, 2017	Aug. 07, 2017	May 15, 2017	May 08, 2017	Feb. 14, 2017	Feb. 07, 2017	Jan. 31, 2020	Apr. 30, 2019	Dec. 31, 2017	Nov. 30, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 09, 2019	Apr. 08, 2019
Distribution Made to Member or Limited Partner [Line Items]
Distribution to limited partner, distribution date			Nov. 14, 2019		Aug. 14, 2019		May 15, 2019		Feb. 14, 2019		Nov. 14, 2018		Aug. 14, 2018		May 15, 2018		Feb. 14, 2018		Nov. 14, 2017		Aug. 14, 2017		May 15, 2017		Feb. 14, 2017
Maximum Period For Distribution Of Available Cash																															45 days
Per unit rate, in dollars per unit			$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60
Distributions to partners																															$ (172.4)	$ (170.8)	$ (167.6)
Contributions																															61.3	64.4	58.0
Loss on contingent consideration																															0.0	0.0	$ (57.0)
Distribution made to limited partners																																	4,724,030
Distributions paid to non-controlling partners																															$ 25.0	$ 9.9	$ 15.2
Limited partners' units, issued																															72,282,942	71,659,385
Dividends, Paid-in-kind																																	$ 43.1
Preferred units, outstanding (in units)																															71,257,445	71,257,445
Preferred units, issued																															71,257,445	71,257,445
Equity Offering Program Authorized Amount																															$ 250.0
Equity Distribution Program Management Fee Percentage																															2.00%
Payments of Stock Issuance Costs																																$ 0.3
Issuance of common units (in units)																															0	0	633,271
Proceeds from Issuance or Sale of Equity																																$ 15.2
Distributions to preferred unitholders																														$ 15.0	$ 60.1	60.1	$ 15.0
Distribution to limited partner, record date				Nov. 07, 2019		Aug. 07, 2019		May 08, 2019		Feb. 07, 2019		Nov. 07, 2018		Aug. 07, 2018		May 08, 2018		Feb. 07, 2018		Nov. 07, 2017		Aug. 07, 2017		May 08, 2017		Feb. 07, 2017
Payments for Repurchase of Redeemable Noncontrolling Interest																													$ 202.7		0.0	0.0	202.7
Proceeds from Noncontrolling Interests																													$ 175.0		235.0	0.0	175.0
Maximum Value of Common Units to be Issued Under Optional Redemption																															$ 100.0
Preferred Units, Class A
Distribution Made to Member or Limited Partner [Line Items]
Partners' Capital Account, Private Placement of Units, Price Per Unit																															$ 9.13
Subsequent Event
Distribution Made to Member or Limited Partner [Line Items]
Distributions to preferred unitholders	$ 15.0
Crestwood Equity Partners LP
Distribution Made to Member or Limited Partner [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest																															99.90%
Crestwood Niobrara LLC
Distribution Made to Member or Limited Partner [Line Items]
Percentage of voting interests acquired																																		100.00%
Proceeds from Noncontrolling Interests																												$ 235.0
Crestwood Niobrara LLC | Cash distribution
Distribution Made to Member or Limited Partner [Line Items]
Distributions paid to non-controlling partners																															$ 25.0	9.9	15.2
Crestwood Niobrara LLC | Subsequent Event | Cash distribution
Distribution Made to Member or Limited Partner [Line Items]
Distributions paid to non-controlling partners																											$ 9.2
Crestwood Gas Services GP, LLC
Distribution Made to Member or Limited Partner [Line Items]
Limited Liability Company or Limited Partnership, Members or Limited Partners, Ownership Interest																															0.10%
CMLP
Distribution Made to Member or Limited Partner [Line Items]
Distributions to partners																															$ (235.8)	(238.4)	(174.0)
Contributions																															61.3	64.4	58.0
Loss on contingent consideration																															0.0	0.0	(57.0)
Distributions paid to non-controlling partners																															25.0	9.9	15.2
Distribution Made to General Partner, Cash Distributions Paid																															235.8	238.4	174.0
Payments for Repurchase of Redeemable Noncontrolling Interest																															0.0	0.0	202.7
Proceeds from Noncontrolling Interests																															235.0	0.0	175.0
Tres Palacios Holdings LLC
Distribution Made to Member or Limited Partner [Line Items]
Contributions																															$ 6.3	2.5	5.6
Equity method ownership percentage																															50.01%
Tres Palacios Holdings LLC | CMLP
Distribution Made to Member or Limited Partner [Line Items]
Equity method ownership percentage																															50.01%
Jackalope Gas Gathering Services, LLC
Distribution Made to Member or Limited Partner [Line Items]
Equity method ownership percentage																												50.00%			0.00%			50.00%	50.00%
Equity Interest																												50.00%			50.00%
Jackalope Gas Gathering Services, LLC | Crestwood Niobrara LLC
Distribution Made to Member or Limited Partner [Line Items]
Contributions																															$ 24.4	$ 49.1	$ 3.5
Cash distribution | Subsequent Event
Distribution Made to Member or Limited Partner [Line Items]
Distribution to limited partner, distribution date	Feb. 14, 2020
Distribution declared per limited partner unit	$ 0.625
Distribution to limited partner, record date		Feb. 07, 2020
Preferred Partner
Distribution Made to Member or Limited Partner [Line Items]
Partners' Capital, Distribution Amount Per Share																															$ 0.2567
Partners' Capital, Contingent Distribution Amount Per Share																															$ 0.2111
Partner's Capital, Unpaid Distribution, Accrual Percentage																															2.8125%
Subordinated Unit | Limited Partners
Distribution Made to Member or Limited Partner [Line Items]
Limited partners' units, issued																													438,789				438,789
Partners' Capital Account, Units, Cash Distribution Threshold, Quarterly Distribution																															$ 1.30
Partners' Capital Account, Units, Conversion Threshold, Cumulative Distribution																															$ 5.20
Non-Controlling Partner
Distribution Made to Member or Limited Partner [Line Items]
Issuance of non-controlling interest																																	$ 175.0
Non-Controlling Partner | CMLP
Distribution Made to Member or Limited Partner [Line Items]
Issuance of non-controlling interest																																	$ 175.0
Williams Partners LP | Crestwood Niobrara LLC
Distribution Made to Member or Limited Partner [Line Items]
Additional voting interest acquired																																		50.00%

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Segments (Narrative) (Details) $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 31, 2019	Dec. 31, 2019 segment	Dec. 31, 2019 reporting_units	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Revenue, Major Customer [Line Items]
Revenues	$ 3,181.9				$ 3,654.1	$ 3,880.9
Number of operating segments			3	3
Concentration Risk, Percentage		10.00%			10.00%	10.00%
Crestwood Equity Partners LP
Revenue, Major Customer [Line Items]
Earnings (Losses) Before Interest, Taxes, Depreciation and Amortization from Equity Method Investments	42.1				$ 42.3	$ 32.5
CMLP
Revenue, Major Customer [Line Items]
Revenues	3,181.9				$ 3,654.1	$ 3,880.9
British Petroleum and its subsidiaries
Revenue, Major Customer [Line Items]
Revenues	$ 333.9

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Risk Management

12 Months Ended

Dec. 31, 2019

Risk Management - Notional Amounts and Terms of Companys Derivative Financial Instruments [Abstract]

Risk Management

Risk Management

We are exposed to certain market risks related to our ongoing business operations. These risks include exposure to changing commodity prices. We utilize derivative instruments to manage our exposure to fluctuations in commodity prices, which is discussed below. Additional information related to our derivatives is discussed in Note 2 and Note 8.

Commodity Derivative Instruments and Price Risk Management

Risk Management Activities

We sell NGLs (such as propane, ethane, butane and heating oil), crude oil and natural gas to energy-related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of NGLs, crude oil and natural gas. We periodically enter into offsetting positions to economically hedge against the exposure our customer contracts create. Certain of these contracts and positions are derivative instruments. We do not designate any of our commodity-based derivatives as hedging instruments for accounting purposes. Our commodity-based derivatives are reflected at fair value in the consolidated balance sheets, and changes in the fair value of these derivatives that impact the consolidated statements of operations are reflected in costs of product/services sold. Our commodity-based derivatives that are settled with physical commodities are reflected as an increase to product revenues, and the commodity inventory that is utilized to satisfy those physical obligations is reflected as an increase to costs of product sold in our consolidated statements of operations. The following table summarizes the impact to our consolidated statements of operations related to our commodity-based derivatives reflected in operating revenues and costs of product/services sold during the years ended December 31, 2019, 2018 and 2017 (in millions):

	December 31,
	2019		2018		2017
Product revenues	$	252.3	$	343.3	$	234.1
Gain (loss) reflected in costs of product/services sold	$	19.5	$	29.6	$	(31.2	)

We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery obligations. This balance in the contractual portfolio significantly reduces the volatility in costs of product/services sold related to these instruments.

Commodity Price and Credit Risk

Notional Amounts and Terms

The notional amounts and terms of our derivative financial instruments include the following:

	December 31, 2019		December 31, 2018
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, ethane, butane, heating oil and crude oil (MMBbls)	33.5	36.6	27.8	30.1
Natural gas (Bcf)	3.7	8.7	1.8	1.8

Notional amounts reflect the volume of transactions, but do not represent the amounts exchanged by the parties to the financial instruments. Accordingly, notional amounts do not reflect our monetary exposure to market or credit risks. All contracts subject to price risk had a maturity of 37 months or less; however, 85% of the contracted volumes will be delivered or settled within 12 months.

Credit Risk

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

Certain of our derivative instruments have credit limits that require us to post collateral. The amount of collateral required to be posted is a function of the net liability position of the derivative as well as our established credit limit with the respective counterparty. If our credit rating were to change, the counterparties could require us to post additional collateral. The amount of additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as well as the requirements of the individual counterparty. In addition, we have margin requirements with a New York Mercantile Exchange (NYMEX) broker related to our net asset or liability position with such broker. All collateral amounts have been netted against the asset or liability with the respective counterparty and are reflected in our consolidated balance sheets as assets and liabilities from price risk management activities.

The following table presents the fair value of our commodity derivative instruments with credit-risk-related contingent features and their associated collateral (in millions):

	December 31,
	2019		2018
Aggregate fair value of derivative instruments with credit-risk-related    contingent features(1)	$	1.6	$	2.2
NYMEX-related net derivative liability position	$	28.8	$	9.4
NYMEX-related cash collateral posted	$	40.4	$	21.7
Cash collateral received, net	$	16.9	$	14.2

(1) At December 31, 2019 and 2018, we posted less than $0.1 million of collateral associated with these derivatives.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Divestitures

Divestitures

Acquisition

On April 9, 2019, Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, acquired Williams Partners LP’s (Williams) 50% equity interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) for approximately $484.6 million (Jackalope Acquisition). The acquisition was funded through a combination of borrowings under the CMLP credit facility and the issuance of $235 million of new preferred units to CN Jackalope Holdings LLC (Jackalope Holdings) (see Note 12 for a further discussion of the issuance of the new preferred units). Prior to the Jackalope Acquisition, Crestwood Niobrara owned a 50% equity interest in Jackalope, which we accounted for under the equity method of accounting. As a result of this transaction, Crestwood Niobrara controls and owns 100% of the equity interests in Jackalope. The financial results of Jackalope are included in our gathering and processing segment from the date of the acquisition. Transaction costs related to the Jackalope Acquisition were approximately $2.8 million during the year ended December 31, 2019. These costs are included in operations and maintenance expenses in our consolidated statements of operations.

The fair values of the assets acquired and liabilities assumed were determined primarily utilizing market-related information and other projections on the performance of the assets acquired, including an analysis of the discounted cash flows at a discount rate of approximately 12%. Those fair values are Level 3 fair value measurements and were developed by management with the assistance of a third-party valuation firm.

The following table summarizes the final valuation of the assets acquired and liabilities assumed at the acquisition date (in millions):

Cash	$	22.5
Other current assets	30.9
Property, plant and equipment	532.9
Intangible assets	306.0
Goodwill	80.3
Current liabilities	(30.4		)
Other long-term liabilities	(21.5		)
Estimated fair value of 100% interest in Jackalope	920.7
Less:
Elimination of equity investment in Jackalope	226.7
Gain on acquisition of Jackalope	209.4
Total purchase price	$	484.6

The identifiable intangible assets primarily consists of a customer contract that has a weighted-average remaining life of 17 years. The goodwill recognized relates primarily to anticipated operating synergies between the assets acquired and our existing operations. The fair value of the assets acquired and liabilities assumed in the Jackalope Acquisition exceeded the sum of the cash consideration paid and the historical book value of our 50% equity interest in Jackalope (which was remeasured at fair value and derecognized) and, as a result, we recognized a gain of approximately $209.4 million. This gain is included in gain on acquisition in our consolidated statements of operations.

Our consolidated statements of operations include the results of Jackalope since April 9, 2019, the closing date of the acquisition. During the year ended December 31, 2019, we recognized approximately $70.1 million of revenues and $20.9 million of net income related to Jackalope’s operations.

The tables below presents selected unaudited pro forma information as if the Jackalope Acquisition had occurred on January 1, 2017 (in millions). The pro forma information is not necessarily indicative of the financial results that would have occurred if the transaction had been completed as of the dates indicated. The amounts have been calculated after applying our accounting policies and adjusting the results to reflect the depreciation, amortization and accretion expense that would have been charged assuming the fair value adjustments to property, plant and equipment and intangible assets had been made at the beginning of the respective reporting period. The pro forma net income also includes the effects of interest expense on incremental borrowings and recognition of deferred revenue.

Crestwood Equity

	Year Ended December 31,
	2019		2018		2017
Revenues	$	3,202.6	$	3,729.5	$	3,935.4
Net income (loss)	$	313.5	$	45.0	$	(193.0	)

Crestwood Midstream

	Year ended December 31,
	2019		2018		2017
Revenues	$	3,202.6	$	3,729.5	$	3,935.4
Net income (loss)	$	304.2	$	36.6	$	(201.9	)

Divestitures

In October 2018, we sold our West Coast assets to a third party for proceeds of approximately $70.5 million. The West Coast assets included a gas gathering and processing system, fractionator, butamer and various rail and truck terminal and storage facilities located in California, Nevada, Wyoming and Utah. The sale of West Coast resulted in a decrease of $61.8 million of

property, plant and equipment, net, $9.0 million of goodwill and $26.6 million of other assets and liabilities, net. During the year ended December 31, 2018, we recognized a loss from the sale of approximately $26.9 million (including the goodwill write off discussed in Note 2), which is included in loss on long-lived assets, net in our consolidated statement of operations. Our West Coast assets were previously included in our MS&L segment.

In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP, for net proceeds of approximately $223.6 million, and we recognized a gain from the sale of approximately $33.6 million, which is included in loss on long-lived assets, net in our consolidated statement of operations. US Salt was previously included in our MS&L segment.

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Income Taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The (provision) benefit for income taxes for the years ended December 31, 2019, 2018, and 2017 consisted of the following (in millions):

	CEQP									CMLP
	Year Ended December 31,									Year Ended December 31,
	2019			2018			2017			2019			2018			2017 (1)
Current:
Federal	$	(0.1	)	$	(0.5	)	$	(1.1	)	$	0.1		$	0.1		$	—
State	(0.2		)	(0.3		)	(0.2		)	(0.2		)	(0.2		)	—
Total current	(0.3		)	(0.8		)	(1.3		)	(0.1		)	(0.1		)	—
Deferred:
Federal	0.1			0.5			2.1			—			—			—
State	(0.1		)	0.2			—			(0.2		)	0.1			—
Total deferred	—			0.7			2.1			(0.2		)	0.1			—
(Provision) benefit for income taxes	$	(0.3	)	$	(0.1	)	$	0.8		$	(0.3	)	$	—		$	—

(1) For the year ended December 31, 2017, our benefit for income taxes was not material to CMLP’s consolidated statement of operations.

The effective rate differs from the statutory rate for the years ended December 31, 2019, 2018 and 2017, primarily due to the partnerships not being treated as a corporation for federal income tax purposes as discussed in Note 2.

Deferred income taxes related to CEQP’s wholly owned subsidiaries, IPCH Acquisition Corp. and Crestwood Gas Services GP LLC, and our Texas Margin tax which reflects the net tax effects of temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts used for income tax purposes.

Components of our deferred income taxes at December 31, 2019 and 2018 are as follows (in millions).

	CEQP						CMLP
	December 31,						December 31,
	2019			2018			2019			2018
Total deferred tax asset(1)	$	0.2		$	0.2		$	—		$	—
Total deferred tax liability(1)	(2.8		)	(2.8		)	(0.7		)	(0.6		)
Net deferred tax liability	$	(2.6	)	$	(2.6	)	$	(0.7	)	$	(0.6	)

(1) Relates to the basis difference in the stock of a company.

Uncertain Tax Positions. We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the applicable tax authority. Such tax positions, if any, would be recorded as a tax benefit or expense in the current year. We believe that there were no uncertain tax positions that would impact our results of operations for the years ended December 31, 2019, 2018 and 2017 and that no provision for income tax was required for these consolidated financial statements. However, our conclusions regarding the evaluation of uncertain tax positions are subject to review and may change based on factors including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof.

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

The following table presents the changes in the net asset retirement obligations for the years ended December 31, 2019 and 2018 (in millions):

	2019			2018
Net asset retirement obligations at January 1	$	28.1		$	28.1
Liabilities acquired (1)	1.7			—
Liabilities incurred	3.4			1.2
Liabilities settled	(0.1		)	(2.8		)
Accretion expense	1.7			1.6
Net asset retirement obligations at December 31 (2)	$	34.8		$	28.1

(1) Relates to the Jackalope Acquisition, which is further discussed in Note 3.

(2)

Includes $1.5 million and $0.5 million of current ARO liabilities at December 31, 2019 and 2018.

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Long-Term Debt (Tables)

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Components Of Long-Term Debt

Long-term debt consisted of the following at December 31, 2019 and 2018, (in millions):

	December 31,
	2019		2018
Credit Facility	$	557.0	$	578.2
2023 Senior Notes	700.0		700.0
2025 Senior Notes	500.0		500.0
2027 Senior Notes	600.0		—
Other	0.6		1.5
Less: deferred financing costs, net	29.1		26.4
Total debt	2,328.5		1,753.3
Less: current portion	0.2		0.9
Total long-term debt, less current portion	$	2,328.3	$	1,752.4

Schedule of Maturities of Long-term Debt

The aggregate maturities of principal amounts on our outstanding long-term debt and other notes payable as of December 31, 2019 for the next five years and in total thereafter are as follows (in millions):

2020	$	0.2
2021	0.2
2022	0.2
2023	1,257.0
2024	—
Thereafter	1,100.0
Total debt	$	2,357.6

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Schedule II - Crestwood Equity Partners LP - Valuation and Qualifying Accounts (Details) - Allowance for Doubtful Accounts - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
SEC Schedule, 12-09, Movement in Valuation Allowances and Reserves [Roll Forward]
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	$ 0.3	$ 2.4	$ 1.9
Valuation Allowances and Reserves, Charged to Cost and Expense	0.1	0.2	1.5
Valuation Allowances and Reserves, Charged to Other Accounts	0.0	0.0	0.0
SEC Schedule, 12-09, Valuation Allowances and Reserves, Deduction	(0.1)	(2.3)	(1.0)
SEC Schedule, 12-09, Valuation Allowances and Reserves, Amount	$ 0.3	$ 0.3	$ 2.4

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Schedule II - Crestwood Equity Parnters LP - Valuation and Qualifying Accounts

12 Months Ended

Dec. 31, 2019

SEC Schedule, 12-09, Valuation and Qualifying Accounts [Abstract]

Schedule II - Crestwood Equity Partners LP - Valuation and Qualifying Accounts

Schedule II

Crestwood Equity Partners LP

Crestwood Midstream Partners LP

Valuation and Qualifying Accounts

For the Years Ended December 31, 2019, 2018 and 2017

(in millions)

	Balance at beginning of period		Charged to costs and expenses		Other Additions		Deductions (write-offs)			Balance at end of period
Allowance for doubtful accounts
2019	$	0.3	$	0.1	$	—	$	(0.1	)	$	0.3
2018	$	2.4	$	0.2	$	—	$	(2.3	)	$	0.3
2017	$	1.9	$	1.5	$	—	$	(1.0	)	$	2.4

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Segments

12 Months Ended

Dec. 31, 2019

Segment Reporting [Abstract]

Segments

Segments

Financial Information

We have three operating and reportable segments: (i) gathering and processing operations; (ii) storage and transportation operations; and (iii) marketing, supply and logistics operations. Our corporate operations include all general and administrative expenses that are not allocated to our reportable segments. For a further description of our operating and reporting segments, see Note 1. We assess the performance of our operating segments based on EBITDA, which is defined as income before income taxes, plus debt-related costs (net interest and debt expense and loss on modification/extinguishment of debt) and depreciation, amortization and accretion expense.

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

	Year Ended December 31,
	2019		2018		2017
Net income (loss)	$	319.9	$	67.0	$	(166.6	)
Add:
Interest and debt expense, net	115.4		99.2		99.4
Loss on modification/extinguishment of debt	—		0.9		37.7
Provision (benefit) for income taxes	0.3		0.1		(0.8		)
Depreciation, amortization and accretion	195.8		168.7		191.7
EBITDA	$	631.4	$	335.9	$	161.4

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

	Year Ended December 31,
	2019		2018		2017
Net income (loss)	$	310.6	$	58.6	$	(175.5	)
Add:
Interest and debt expense, net	115.4		99.2		99.4
Loss on modification/extinguishment of debt	—		0.9		37.7
Provision for income taxes	0.3		—		—
Depreciation, amortization and accretion	209.9		181.4		202.7
EBITDA	$	636.2	$	340.1	$	164.3

The following tables summarize CEQP’s and CMLP’s reportable segment data for the years ended December 31, 2019, 2018 and 2017 (in millions). Intersegment revenues included in the following tables are accounted for as arms-length transactions that apply our revenue recognition policy described in Note 2. Included in earnings from unconsolidated affiliates below was approximately $42.1 million, $42.3 million and $32.5 million of our proportionate share of interest expense, depreciation and amortization expense and gains (losses) on long-lived assets, net recorded by our equity investments for the years ended December 31, 2019, 2018 and 2017, respectively.

Crestwood Equity

	Year Ended December 31, 2019
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	835.8		$	20.4	$	2,325.7		$	—		$	3,181.9
Intersegment revenues	175.0			14.2		(189.2		)	—			—
Costs of product/services sold	526.1			0.2		2,018.6			—			2,544.9
Operations and maintenance expense	98.7			4.0		36.1			—			138.8
General and administrative expense	—			—		—			103.4			103.4
Gain (loss) on long-lived assets, net	(6.2		)	—		(0.2		)	0.2			(6.2		)
Gain on acquisition	209.4			—		—			—			209.4
Earnings (loss) from unconsolidated affiliates, net	(2.1		)	34.9		—			—			32.8
Other income, net	—			—		—			0.6			0.6
EBITDA	$	587.1		$	65.3	$	81.6		$	(102.6	)	$	631.4
Goodwill	$	126.2		$	—	$	92.7		$	—		$	218.9
Total assets	$	3,715.3		$	980.2	$	624.7		$	29.1		$	5,349.3
Purchases of property, plant and equipment	$	447.7		$	0.1	$	5.8		$	1.9		$	455.5

	Year Ended December 31, 2018
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	946.7		$	17.1	$	2,690.3		$	—		$	3,654.1
Intersegment revenues	192.4			10.5		(202.9		)	—			—
Costs of product/services sold	767.0			0.2		2,362.2			—			3,129.4
Operations and maintenance expense	71.7			3.3		50.8			—			125.8
General and administrative expense	—			—		—			88.1			88.1
Gain (loss) on long-lived assets, net	(3.0		)	—		(27.3		)	1.7			(28.6		)
Earnings from unconsolidated affiliates, net	22.5			30.8		—			—			53.3
Other income, net	—			—		—			0.4			0.4
EBITDA	$	319.9		$	54.9	$	47.1		$	(86.0	)	$	335.9
Goodwill	$	45.9		$	—	$	92.7		$	—		$	138.6
Total assets	$	2,633.4		$	1,004.4	$	612.5		$	44.2		$	4,294.5
Purchases of property, plant and equipment	$	294.7		$	0.6	$	5.6		$	4.6		$	305.5

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			96.5			96.5
Loss on long-lived assets	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			0.5			1.3
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(99.0	)	$	161.4
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

Crestwood Midstream

	Year Ended December 31, 2019
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	835.8		$	20.4	$	2,325.7		$	—		$	3,181.9
Intersegment revenues	175.0			14.2		(189.2		)	—			—
Costs of product/services sold	526.1			0.2		2,018.6			—			2,544.9
Operations and maintenance expense	98.7			4.0		36.1			—			138.8
General and administrative expense	—			—		—			98.2			98.2
Gain (loss) on long-lived assets, net	(6.2		)	—		(0.2		)	0.2			(6.2		)
Gain on acquisition	209.4			—		—			—			209.4
Earnings (loss) from unconsolidated affiliates, net	(2.1		)	34.9		—			—			32.8
Other income, net	—			—		—			0.2			0.2
EBITDA	$	587.1		$	65.3	$	81.6		$	(97.8	)	$	636.2
Goodwill	$	126.2		$	—	$	92.7		$	—		$	218.9
Total assets	$	3,874.7		$	980.2	$	624.7		$	24.4		$	5,504.0
Purchases of property, plant and equipment	$	447.7		$	0.1	$	5.8		$	1.9		$	455.5

	Year Ended December 31, 2018
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	946.7		$	17.1	$	2,690.3		$	—		$	3,654.1
Intersegment revenues	192.4			10.5		(202.9		)	—			—
Costs of product/services sold	767.0			0.2		2,362.2			—			3,129.4
Operations and maintenance expense	71.7			3.3		50.8			—			125.8
General and administrative expense	—			—		—			83.5			83.5
Gain (loss) on long-lived assets, net	(3.0		)	—		(27.3		)	1.7			(28.6		)
Earnings from unconsolidated affiliates, net	22.5			30.8		—			—			53.3
EBITDA	$	319.9		$	54.9	$	47.1		$	(81.8	)	$	340.1
Goodwill	$	45.9		$	—	$	92.7		$	—		$	138.6
Total assets	$	2,807.1		$	1,004.4	$	612.5		$	38.0		$	4,462.0
Purchases of property, plant and equipment	$	294.7		$	0.6	$	5.6		$	4.6		$	305.5

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			93.1			93.1
Loss on long-lived assets, net	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			—			0.8
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(96.1	)	$	164.3
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

Major Customers

For the year ended December 31, 2019, we had revenues from British Petroleum and its affiliates of approximately $333.9 million, reflected primarily in our Marketing, Supply and Logistics segment, which exceeded 10% of the total consolidated revenues at CEQP and CMLP. No customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2018 or 2017 at CEQP or CMLP.

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Equity Plans

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Equity Plan

Equity Plans

Long-term incentive awards are granted under the Crestwood Equity Partners LP Long Term Incentive Plan (Crestwood LTIP) in order to align the economic interests of key employees and directors with those of CEQP’s common unitholders and to provide an incentive for continuous employment. Long-term incentive compensation consist of grants of restricted, phantom and performance units which vest based upon continued service.

The following table summarizes information regarding restricted, phantom and performance unit activity during the years ended December 31, 2019, 2018 and 2017.

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2017	1,292,330		$	24.67
Granted - restricted units	919,411		$	25.69
Granted - phantom units	15,849		$	25.02
Granted - performance units	405,620		$	30.21
Vested - restricted units	(607,115	)	$	28.00
Vested - performance units	(31,106	)	$	30.27
Forfeited - restricted units	(140,137	)	$	23.73
Forfeited - performance units	(24,756	)	$	30.45
Unvested - December 31, 2017	1,830,096		$	25.21
Granted - restricted units	1,144,017		$	25.80
Granted - phantom units	7,750		$	26.10
Granted - performance units	901		$	25.60
Vested - restricted units	(617,807	)	$	23.73
Vested - phantom units	(105,809	)	$	49.45
Vested - performance units	(11,772	)	$	28.87
Forfeited - restricted units	(53,530	)	$	23.36
Forfeited - phantom units	(6	)	$	49.45
Forfeited - performance units	(5,870	)	$	30.45
Unvested - December 31, 2018	2,187,970		$	24.78
Granted - restricted units	988,096		$	31.48
Granted - phantom units	7,164		$	29.03
Granted - performance units	238,263		$	34.21
Vested - restricted units	(985,751	)	$	23.39
Vested - performance units	(32,246	)	$	34.21
Forfeited - restricted units	(47,547	)	$	27.85
Unvested - December 31, 2019	2,355,949		$	28.94

As of December 31, 2019 and 2018, we had total unamortized compensation expense of approximately $34.6 million and $28.0 million related to restricted, phantom, and performance units, which will be amortized during the next three years (or sooner in certain cases, which generally represents the original vesting period of these instruments), except for grants to non-employee directors of our general partner, which vest over one year.  We recognized compensation expense of approximately $45.1 million, $24.3 million and $22.4 million under the Crestwood LTIP during the years ended December 31, 2019, 2018 and 2017, which is included in general and administrative expenses on our consolidated statements of operations.  During the year ended December 31, 2019, compensation expense includes approximately $4.6 million related to equity awards under the Crestwood LTIP that was included in accrued expenses and other liabilities on our consolidated balance sheet. As of February 10, 2020, we had 2,593,885 units available for issuance under the Crestwood LTIP.

Restricted Units. Under the Crestwood LTIP, participants who have been granted restricted units may elect to have us withhold common units to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-vested common units. Any such common units withheld are returned to the Crestwood LTIP on the applicable vesting dates, which correspond to the times at which income is recognized by the employee. When we withhold these common units, we are required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. During the years ended December 31, 2019, 2018, and 2017, we withheld 336,548, 221,576 and 206,600 common units to satisfy employee tax withholding obligations.

Phantom Units. The Crestwood LTIP permits grants of phantom units that entitle the holder thereof to receive upon vesting one CEQP common unit granted pursuant to the Crestwood LTIP and a phantom unit award agreement (the Crestwood Equity

Phantom Unit Agreement). The Crestwood Equity Phantom Unit Agreement provides for vesting to occur at the end of three years following the grant date or, if earlier, upon the named executive officer’s termination without cause or due to death or disability or the named executive officer’s resignation for employee cause (each, as defined in the Crestwood Equity Phantom Unit Agreement). In addition, the Crestwood Equity Phantom Unit Agreement provides for distribution equivalent rights with respect to each phantom unit which are paid in additional phantom units and settled in common units upon vesting of the underlying phantom units.

Performance Units. The Crestwood LTIP permits grants of performance units that are designed to provide an incentive for continuous employment to certain key employees. Performance units vest over a three-year performance period and the number of units issued are based on a performance multiplier ranging between 50% and 200%, determined based on the actual performance in the third year of the performance period compared to pre-established performance goals. The performance goals are based on achieving a specified level of distributable cash flow per unit, Adjusted EBITDA, return on capital invested, and three-year relative total shareholder return. The vesting of performance units is subject to the attainment of certain performance and market goals over a three-year period and entitle a participant to receive common units of Crestwood Equity without payment of an exercise price upon vesting.

Employee Unit Purchase Plan

In August 2018, the board of directors of our general partner approved 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, not to exceed $25,000 for any calendar year. Under the plan, we anticipate purchasing our common units on the open market for the benefit of participating employees based on their payroll deductions. In addition, we may match up to 10% of participating employees’ payroll deductions to purchase additional Crestwood common units for participating employees. The board of directors of our general partner authorized 1,500,000 common units (subject to adjustment as provided in the employee unit purchase plan) to be available for purchase. During the year ended December 31, 2019, 6,341 common units were purchased under the plan. There were no common units purchased under the employee unit purchase plan in 2018.

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Schedule I - Crestwood Equity Partners LP - Parent Only - Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Condensed Financial Statements, Captions [Line Items]
Cash	$ 25.7	$ 0.9
Total current assets	376.4	379.3
Property, plant and equipment, net	2,909.1	2,029.7
Total assets	5,349.3	4,294.5
Accrued expenses	161.7	112.4
Total current liabilities	357.8	332.1
Other long-term liabilities	301.6	173.6
Total partners’ capital	1,932.8	2,033.8
Total liabilities and partners’ capital	5,349.3	4,294.5
Parent Company
Condensed Financial Statements, Captions [Line Items]
Cash	0.2	0.2	$ 0.3	$ 0.3
Total current assets	0.2	0.2
Property, plant and equipment, net	1.0	1.1
Investments in subsidiaries	1,935.9	1,854.7
Other assets	3.1	2.8
Total assets	1,940.2	1,858.8
Accounts payable	0.1	2.6
Accrued expenses	1.3	1.1
Total current liabilities	1.4	3.7
Other long-term liabilities	6.0	2.6
Total partners’ capital	1,932.8	1,852.5
Total liabilities and partners’ capital	$ 1,940.2	$ 1,858.8

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Risk Management (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative [Line Items]
Cash collateral received, net	$ 16.9	$ 14.2
Price Risk Contracts | Maximum
Derivative [Line Items]
Remaining maturity	37 months
Percent of contracts expiring in next twelve months	85.00%
Commodity Contract
Derivative [Line Items]
Gain (loss) reflected in costs of product/services sold	$ 19.5	29.6	$ (31.2)
Cash collateral received, net	$ 0.1	$ 0.1

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Asset Retirement Obligations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Net asset retirement obligation at January 1	$ 28.1	$ 28.1
Liabilities acquired	1.7	0.0
Liabilities incurred	3.4	1.2
Liabilities settled	(0.1)	(2.8)
Accretion expense	(1.7)	(1.6)
Net asset retirement obligation at December 31	34.8	28.1
Current ARO liabilities	$ 1.5	$ 0.5

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Revenues Disaggregation of Revenues (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disaggregation of Revenue [Line Items]
Product revenues	$ 252.3	$ 343.3	$ 234.1
Revenues	3,181.9	3,654.1	$ 3,880.9
Natural Gas Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	163.2	134.9
Crude Oil Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	75.0	38.8
Water Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	79.6	58.0
Natural Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	28.9	10.7
Natural Gas Compression
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	24.9	29.1
Crude Oil Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5.0	4.5
NGL Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	6.3	8.6
Crude Oil Pipeline
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5.2	4.8
Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	12.7	8.8
NGL Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	11.7	26.9
Crude Oil Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	11.0	9.3
Natural Gas Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	95.7	110.1
Crude Oil Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,726.6	1,549.6
NGL Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	680.7	1,306.7
Other revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1.9	0.5
NGL Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		6.1
Water Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.2	0.3
NGL Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3.1
Product and Service, Other
Disaggregation of Revenue [Line Items]
Revenue Not from Contract with Customer	253.3	343.3
Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue including intersegment eliminations	1,010.8	1,139.1
Gathering and Processing Segment | Natural Gas Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	163.2	134.9
Gathering and Processing Segment | Crude Oil Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	75.0	38.8
Gathering and Processing Segment | Water Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	79.6	58.0
Gathering and Processing Segment | Natural Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	28.9	10.7
Gathering and Processing Segment | Natural Gas Compression
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	24.9	29.1
Gathering and Processing Segment | Crude Oil Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1.9	1.8
Gathering and Processing Segment | NGL Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Gathering and Processing Segment | Crude Oil Pipeline
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Gathering and Processing Segment | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	7.0	2.9
Gathering and Processing Segment | NGL Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Gathering and Processing Segment | Crude Oil Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Gathering and Processing Segment | Natural Gas Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	56.8	55.8
Gathering and Processing Segment | Crude Oil Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	532.1	722.9
Gathering and Processing Segment | NGL Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	41.4	84.2
Gathering and Processing Segment | Other revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Gathering and Processing Segment | NGL Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
Gathering and Processing Segment | Water Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Gathering and Processing Segment | NGL Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
Gathering and Processing Segment | Product and Service, Other
Disaggregation of Revenue [Line Items]
Revenue Not from Contract with Customer	0.0	0.0
Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue including intersegment eliminations	34.6	27.6
Storage and Transportation | Natural Gas Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | Crude Oil Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | Water Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | Natural Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | Natural Gas Compression
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | Crude Oil Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5.4	4.2
Storage and Transportation | NGL Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | Crude Oil Pipeline
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	7.9	7.1
Storage and Transportation | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | NGL Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | Crude Oil Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	16.7	14.3
Storage and Transportation | Natural Gas Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | Crude Oil Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | NGL Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | Other revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	4.6	2.0
Storage and Transportation | NGL Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
Storage and Transportation | Water Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Storage and Transportation | NGL Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
Storage and Transportation | Product and Service, Other
Disaggregation of Revenue [Line Items]
Revenue Not from Contract with Customer	0.0	0.0
Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue including intersegment eliminations	2,325.7
Revenues		2,690.3
Marketing Supply and Logistics | Natural Gas Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Marketing Supply and Logistics | Crude Oil Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Marketing Supply and Logistics | Water Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Marketing Supply and Logistics | Natural Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Marketing Supply and Logistics | Natural Gas Compression
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Marketing Supply and Logistics | Crude Oil Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Marketing Supply and Logistics | NGL Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	6.3	8.6
Marketing Supply and Logistics | Crude Oil Pipeline
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Marketing Supply and Logistics | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5.8	5.9
Marketing Supply and Logistics | NGL Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	11.7	26.9
Marketing Supply and Logistics | Crude Oil Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.2
Marketing Supply and Logistics | Natural Gas Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	72.3	70.9
Marketing Supply and Logistics | Crude Oil Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,315.6	978.0
Marketing Supply and Logistics | NGL Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	659.3	1,247.0
Marketing Supply and Logistics | Other revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1.2	0.0
Marketing Supply and Logistics | NGL Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		6.1
Marketing Supply and Logistics | Water Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.2	0.3
Marketing Supply and Logistics | NGL Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3.1
Marketing Supply and Logistics | Product and Service, Other
Disaggregation of Revenue [Line Items]
Revenue Not from Contract with Customer	253.3	343.3
Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenues	(189.2)	(202.9)
Intersegment Eliminations | Natural Gas Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Crude Oil Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Water Gathering
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Natural Gas Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Natural Gas Compression
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Crude Oil Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(2.3)	(1.5)
Intersegment Eliminations | NGL Storage
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Crude Oil Pipeline
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(2.7)	(2.3)
Intersegment Eliminations | Crude Oil Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(0.1)	0.0
Intersegment Eliminations | NGL Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | Crude Oil Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(5.7)	(5.2)
Intersegment Eliminations | Natural Gas Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(33.4)	(16.6)
Intersegment Eliminations | Crude Oil Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(121.1)	(151.3)
Intersegment Eliminations | NGL Product Sales
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(20.0)	(24.5)
Intersegment Eliminations | Other revenue
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(3.9)	(1.5)
Intersegment Eliminations | NGL Processing
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
Intersegment Eliminations | Water Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	0.0	0.0
Intersegment Eliminations | NGL Rail Loading
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		0.0
Intersegment Eliminations | Product and Service, Other
Disaggregation of Revenue [Line Items]
Revenue Not from Contract with Customer	0.0	0.0
Revenue from Contract with Customer
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,928.6	3,310.8
Revenue from Contract with Customer | Gathering and Processing Segment
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	1,010.8	1,139.1
Revenue from Contract with Customer | Storage and Transportation
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	34.6	27.6
Revenue from Contract with Customer | Marketing Supply and Logistics
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,072.4	2,347.0
Revenue from Contract with Customer | Intersegment Eliminations
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ (189.2)	$ (202.9)

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Equity Plans (Tables)

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Disclosure of Share-based Compensation Arrangements by Share-based Payment Award

The following table summarizes information regarding restricted, phantom and performance unit activity during the years ended December 31, 2019, 2018 and 2017.

	Units		Weighted-Average Grant Date Fair Value
Unvested - January 1, 2017	1,292,330		$	24.67
Granted - restricted units	919,411		$	25.69
Granted - phantom units	15,849		$	25.02
Granted - performance units	405,620		$	30.21
Vested - restricted units	(607,115	)	$	28.00
Vested - performance units	(31,106	)	$	30.27
Forfeited - restricted units	(140,137	)	$	23.73
Forfeited - performance units	(24,756	)	$	30.45
Unvested - December 31, 2017	1,830,096		$	25.21
Granted - restricted units	1,144,017		$	25.80
Granted - phantom units	7,750		$	26.10
Granted - performance units	901		$	25.60
Vested - restricted units	(617,807	)	$	23.73
Vested - phantom units	(105,809	)	$	49.45
Vested - performance units	(11,772	)	$	28.87
Forfeited - restricted units	(53,530	)	$	23.36
Forfeited - phantom units	(6	)	$	49.45
Forfeited - performance units	(5,870	)	$	30.45
Unvested - December 31, 2018	2,187,970		$	24.78
Granted - restricted units	988,096		$	31.48
Granted - phantom units	7,164		$	29.03
Granted - performance units	238,263		$	34.21
Vested - restricted units	(985,751	)	$	23.39
Vested - performance units	(32,246	)	$	34.21
Forfeited - restricted units	(47,547	)	$	27.85
Unvested - December 31, 2019	2,355,949		$	28.94

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Revenues (Tables)

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Contract with Customer, Asset and Liability

The following table provides a summary of the opening and closing balances of our contract assets and contract liabilities (in millions):

	December 31,
	2019		2018
Contract assets (non-current)	$	1.2	$	1.0
Contract liabilities (current)(1)	$	8.8	$	12.0
Contract liabilities (non-current)(1)	$	144.7	$	65.4

(1)

During the year ended December 31, 2019, we recognized revenues of approximately $13.3 million that were previously included in contract liabilities (current) at December 31, 2018. The remaining change in our contract liabilities during the year ended December 31, 2019 partially related to approximately $21.5 million of deferred revenues recorded in the purchase price allocation for the Jackalope Acquisition described in more detail in Note 3, and the remainder related primarily to capital reimbursements associated with our revenue contracts and revenue deferrals associated with our contracts with increasing (decreasing) rates.

Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction

The following table summarizes the transaction price allocated to our remaining performance obligations under certain contracts that have not been recognized as of December 31, 2019 (in millions):

2020	$	99.4
2021	86.2
2022	79.3
2023	7.4
2024	3.3
Total	$	275.6

Disaggregation of Revenue

The following tables summarize our revenues from contracts with customers disaggregated by type of product/service sold and by commodity type for each of our segments for the years ended December 31, 2019 and 2018 (in millions). We believe this summary best depicts how the nature, amount, timing and uncertainty of our revenues and cash flows are affected by economic factors.

	Year Ended December 31, 2019
	Gathering and Processing		Storage and Transportation		Marketing, Supply and Logistics		Intersegment Elimination			Total
Revenues:
Topic 606 revenues
Gathering
Natural gas	$	163.2	$	—	$	—	$	—		$	163.2
Crude oil	75.0		—		—		—			75.0
Water	79.6		—		—		—			79.6
Processing
Natural gas	28.9		—		—		—			28.9
Compression
Natural gas	24.9		—		—		—			24.9
Storage
Crude oil	1.9		5.4		—		(2.3		)	5.0
NGLs	—		—		6.3		—			6.3
Pipeline
Crude oil	—		7.9		—		(2.7		)	5.2
Transportation
Crude oil	7.0		—		5.8		(0.1		)	12.7
NGLs	—		—		11.7		—			11.7
Water	—		—		0.2		—			0.2
Rail Loading
Crude oil	—		16.7		—		(5.7		)	11.0
Product Sales
Natural gas	56.8		—		72.3		(33.4		)	95.7
Crude oil	532.1		—		1,315.6		(121.1		)	1,726.6
NGLs	41.4		—		659.3		(20.0		)	680.7
Other	—		4.6		1.2		(3.9		)	1.9
Total Topic 606 revenues	1,010.8		34.6		2,072.4		(189.2		)	2,928.6
Non-Topic 606 revenues(1)	—		—		253.3		—			253.3
Total revenues	$	1,010.8	$	34.6	$	2,325.7	$	(189.2	)	$	3,181.9

(1) Represents revenues primarily related to our commodity-based derivatives. See Note 7 for additional information related to our price risk management activities.

	Year Ended December 31, 2018
	Gathering and Processing		Storage and Transportation		Marketing, Supply and Logistics		Intersegment Elimination			Total
Revenues:
Topic 606 revenues
Gathering
Natural gas	$	134.9	$	—	$	—	$	—		$	134.9
Crude oil	38.8		—		—		—			38.8
Water	58.0		—		—		—			58.0
Processing
Natural gas	10.7		—		—		—			10.7
NGLs	—		—		6.1		—			6.1
Compression
Natural gas	29.1		—		—		—			29.1
Storage
Crude oil	1.8		4.2		—		(1.5		)	4.5
NGLs	—		—		8.6		—			8.6
Pipeline
Crude oil	—		7.1		—		(2.3		)	4.8
Transportation
Crude oil	2.9		—		5.9		—			8.8
NGLs	—		—		26.9		—			26.9
Water	—		—		0.3		—			0.3
Rail Loading
Crude oil	—		14.3		0.2		(5.2		)	9.3
NGLs	—		—		3.1		—			3.1
Product Sales
Natural gas	55.8		—		70.9		(16.6		)	110.1
Crude oil	722.9		—		978.0		(151.3		)	1,549.6
NGLs	84.2		—		1,247.0		(24.5		)	1,306.7
Other	—		2.0		—		(1.5		)	0.5
Total Topic 606 revenues	1,139.1		27.6		2,347.0		(202.9		)	3,310.8
Non-Topic 606 revenues(1)	—		—		343.3		—			343.3
Total revenues	$	1,139.1	$	27.6	$	2,690.3	$	(202.9	)	$	3,654.1

(1)

Represents revenues related to our commodity-based derivatives. See Note 7 for additional information related to our price risk management activities.

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Basis of Presentation and Summary of Significant Accounting Policies (Estimated Useful Lives Of Property, Plant And Equipment) (Details)	12 Months Ended
	Dec. 31, 2019
Gathering systems and pipelines and related assets | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	15 years
Gathering systems and pipelines and related assets | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	20 years
Facilities and equipment | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	3 years
Facilities and equipment | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	25 years
Buildings, land, rights-of-way, storage rights and easements | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	1 year
Buildings, land, rights-of-way, storage rights and easements | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	40 years
Office furniture and fixtures | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Office furniture and fixtures | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	10 years
Vehicles | Minimum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years
Vehicles | Maximum
Property, Plant and Equipment [Line Items]
Property, plant and equipment, useful life	5 years

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Commitments and Contingencies Leases (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Lessee, Lease, Description [Line Items]
Total costs of products/services sold	$ 2,544.9	$ 3,129.4	$ 3,374.7
Lessee, Operating Lease, Liability, Payments, Due Next Twelve Months	20.9
Operating Lease, Payments	22.9
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	4.2
Operations and maintenance	138.8	125.8	$ 136.0
Operating Lease, Expense	$ 28.3
Operating Lease, Weighted Average Remaining Lease Term	4 years 4 months 24 days
Operating lease right-of-use assets, net	$ 53.8
Accrued expenses and other liabilities	161.7	112.4
Operating leases	41.5	0.0
Operating Lease, Liability	59.6
Property, plant and equipment	3,612.5	2,598.1
Less: accumulated depreciation	703.4	568.4
Property, plant and equipment, net	2,909.1	2,029.7
Other long-term liabilities	301.6	$ 173.6
Finance Lease, Liability	$ 8.4
Finance Lease, Weighted Average Remaining Lease Term	2 years 7 months 6 days
Operating Lease, Weighted Average Discount Rate, Percent	5.90%
Finance Lease, Weighted Average Discount Rate, Percent	7.30%
Sublease Income	$ (1.0)
Operating Lease Expense, Net	27.3
Finance Lease, Right-of-Use Asset, Amortization	3.6
Finance Lease, Interest Expense	0.7
Finance Lease Expense	4.3
Short-term Lease, Cost	3.7
Finance Lease, Interest Payment on Liability	0.7
Payments on finance leases	3.5
Right-of-Use Asset Obtained in Exchange for Finance Lease Liability	1.8
Finance Lease, Liability, Payments, Due Next Twelve Months	3.6
Operating and Finance Lease Liability, Due Next Twelve Months	24.5
Lessee, Operating Lease, Liability, Payments, Due Year Two	16.3
Finance Lease, Liability, Payments, Due Year Two	3.6
Operating and Finance Lease Liability Payments, Due Year Two	19.9
Lessee, Operating Lease, Liability, Payments, Due Year Three	11.1
Finance Lease, Liability, Payments, Due Year Three	1.9
Operating and Finance Lease Liability Payments, Due Year Three	13.0
Lessee, Operating Lease, Liability, Payments, Due Year Four	6.7
Finance Lease, Liability, Payments, Due Year Four	0.1
Operating and Finance Lease Liability Payments, Due Year Four	6.8
Lessee, Operating Lease, Liability, Payments, Due Year Five	6.0
Finance Lease, Liability, Payments, Due Year Five	0.0
Operating and Finance Lease Liability Payments, Due Year Five	6.0
Lessee, Operating Lease, Liability, Payments, Due after Year Five	7.5
Finance Lease, Liability, Payments, Due after Year Five	0.0
Operating and Finance Lease Liability Payments, Due after Year Five	7.5
Lessee, Operating Lease, Liability, Payments, Due	68.5
Finance Lease, Liability, Payment, Due	9.2
Operating and Finance Lease Liability, Payments, Due	77.7
Lessee, Operating Lease, Liability, Undiscounted Excess Amount	8.9
Finance Lease, Liability, Undiscounted Excess Amount	0.8
Operating and Finance Lease Liability, Undiscounted Excess Amount	9.7
Operating and Finance Lease Liability	68.0
Operating Leases [Member]
Lessee, Lease, Description [Line Items]
Total costs of products/services sold	17.5
Operations and maintenance	10.8
Operating lease right-of-use assets, net	53.8
Accrued expenses and other liabilities	18.1
Operating leases	41.5
Operating Lease, Liability	59.6
Finance Lease [Member]
Lessee, Lease, Description [Line Items]
Accrued expenses and other liabilities	3.2
Property, plant and equipment	14.9
Less: accumulated depreciation	5.4
Property, plant and equipment, net	9.5
Other long-term liabilities	$ 5.2
Minimum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Remaining Term Of Contract	1 year
Lessee, Finance Lease, Remaining Term Of Contract	1 year
Lessee, Operating and Finance Leases, Discount Rate	3.50%
Lessee, Operating Lease, Renewal Term	1 year
Maximum
Lessee, Lease, Description [Line Items]
Lessee, Operating Lease, Remaining Term Of Contract	20 years
Lessee, Finance Lease, Remaining Term Of Contract	4 years
Lessee, Operating and Finance Leases, Discount Rate	8.30%
Lessee, Operating Lease, Renewal Term	10 years
Jackalope Gas Gathering Services, LLC
Lessee, Lease, Description [Line Items]
Right-of-Use Asset Obtained in Exchange for Operating Lease Liability	$ 2.9

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Income Taxes (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Deferred:
Total deferred	$ 0.0	$ 0.7	$ 2.1
(Provision) benefit for income taxes	(0.3)	(0.1)	0.8
Crestwood Equity Partners LP
Income Tax Contingency [Line Items]
Deferred Tax Assets, Gross	0.2	0.2
Current:
Federal	(0.1)	(0.5)	(1.1)
State	(0.2)	(0.3)	(0.2)
Total current	(0.3)	(0.8)	(1.3)
Deferred:
Federal	0.1	0.5	2.1
State	(0.1)	0.2	0.0
Total deferred	0.0	0.7	2.1
(Provision) benefit for income taxes	(0.3)	(0.1)	0.8
Deferred tax asset:
Total deferred tax liability	(2.8)	(2.8)
Deferred tax liability:
Total deferred tax liability(1)	(2.6)	(2.6)
CMLP
Income Tax Contingency [Line Items]
Deferred Tax Assets, Gross	0.0	0.0
Current:
Federal	0.1	0.1	0.0
State	(0.2)	(0.2)	0.0
Total current	(0.1)	(0.1)	0.0
Deferred:
Federal	0.0	0.0	0.0
State	(0.2)	0.1	0.0
Total deferred	(0.2)	0.1	0.0
(Provision) benefit for income taxes	(0.3)	0.0	$ 0.0
Deferred tax asset:
Total deferred tax liability	(0.7)	(0.6)
Deferred tax liability:
Total deferred tax liability(1)	$ (0.7)	$ (0.6)

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Partners' Capital Net Income (Loss) Attributable to NonControlling Partners (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Limited Partners' Capital Account [Line Items]
Net income (loss) attributable to non-controlling partners in subsidiary	$ 34.8	$ 16.2	$ 25.3
CMLP
Limited Partners' Capital Account [Line Items]
Net income (loss) attributable to non-controlling partners in subsidiary	$ 34.8	$ 16.2	$ 25.3

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Segments (Summary Of Segment Information) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Operating revenues	$ 3,181.9	$ 3,654.1	$ 3,880.9
Intersegment Revenues	0.0	0.0	0.0
Costs of product/services sold	2,544.9	3,129.4	3,374.7
Operations and maintenance	138.8	125.8	136.0
General and administrative	103.4	88.1	96.5
Gain (loss) on long-lived assets, net	(6.2)	(28.6)	(65.6)
Goodwill impairment	0.0	0.0	(38.8)
Loss on contingent consideration	0.0	0.0	(57.0)
Gain on acquisition	209.4	0.0	0.0
Earnings from unconsolidated affiliates, net	32.8	53.3	47.8
Other income, net	0.6	0.4	1.3
EBITDA	631.4	335.9	161.4
Goodwill	218.9	138.6	147.6
Assets	5,349.3	4,294.5
Purchases of property, plant and equipment	455.5	305.5	188.4
CMLP
Segment Reporting Information [Line Items]
Operating revenues	3,181.9	3,654.1	3,880.9
Intersegment Revenues	0.0	0.0	0.0
Costs of product/services sold	2,544.9	3,129.4	3,374.7
Operations and maintenance	138.8	125.8	136.0
General and administrative	98.2	83.5	93.1
Gain (loss) on long-lived assets, net	(6.2)	(28.6)	(65.6)
Goodwill impairment	0.0	0.0	(38.8)
Loss on contingent consideration	0.0	0.0	(57.0)
Gain on acquisition	209.4	0.0	0.0
Earnings from unconsolidated affiliates, net	32.8	53.3	47.8
Other income, net	0.2	0.0	0.8
EBITDA	636.2	340.1	164.3
Goodwill	218.9	138.6
Assets	5,504.0	4,462.0
Purchases of property, plant and equipment	455.5	305.5	188.4
Corporate
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0	0.0
Intersegment Revenues	0.0	0.0	0.0
Costs of product/services sold	0.0	0.0	0.0
Operations and maintenance	0.0	0.0	0.0
General and administrative	103.4	88.1	96.5
Gain (loss) on long-lived assets, net	0.2	1.7	(3.0)
Goodwill impairment			0.0
Loss on contingent consideration			0.0
Gain on acquisition	0.0
Earnings from unconsolidated affiliates, net	0.0	0.0	0.0
Other income, net	0.6	0.4	0.5
EBITDA	(102.6)	(86.0)	(99.0)
Goodwill	0.0	0.0
Assets	29.1	44.2
Purchases of property, plant and equipment	1.9	4.6	6.7
Corporate | CMLP
Segment Reporting Information [Line Items]
Operating revenues	0.0	0.0	0.0
Intersegment Revenues	0.0	0.0	0.0
Costs of product/services sold	0.0	0.0	0.0
Operations and maintenance	0.0	0.0	0.0
General and administrative	98.2	83.5	93.1
Gain (loss) on long-lived assets, net	0.2	1.7	(3.0)
Goodwill impairment			0.0
Loss on contingent consideration			0.0
Gain on acquisition	0.0
Earnings from unconsolidated affiliates, net	0.0	0.0	0.0
Other income, net	0.2		0.0
EBITDA	(97.8)	(81.8)	(96.1)
Goodwill	0.0	0.0
Assets	24.4	38.0
Purchases of property, plant and equipment	1.9	4.6	6.7
Gathering and Processing Segment | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	835.8	946.7	1,688.2
Intersegment Revenues	175.0	192.4	134.5
Costs of product/services sold	526.1	767.0	1,480.8
Operations and maintenance	98.7	71.7	68.4
General and administrative	0.0	0.0	0.0
Gain (loss) on long-lived assets, net	(6.2)	(3.0)	(14.4)
Goodwill impairment			0.0
Loss on contingent consideration			0.0
Gain on acquisition	209.4
Earnings from unconsolidated affiliates, net	(2.1)	22.5	18.9
Other income, net	0.0	0.0	0.8
EBITDA	587.1	319.9	278.8
Goodwill	126.2	45.9
Assets	3,715.3	2,633.4
Purchases of property, plant and equipment	447.7	294.7	162.7
Gathering and Processing Segment | Operating Segments | CMLP
Segment Reporting Information [Line Items]
Operating revenues	835.8	946.7	1,688.2
Intersegment Revenues	175.0	192.4	134.5
Costs of product/services sold	526.1	767.0	1,480.8
Operations and maintenance	98.7	71.7	68.4
General and administrative	0.0	0.0	0.0
Gain (loss) on long-lived assets, net	(6.2)	(3.0)	(14.4)
Goodwill impairment			0.0
Loss on contingent consideration			0.0
Gain on acquisition	209.4
Earnings from unconsolidated affiliates, net	(2.1)	22.5	18.9
Other income, net	0.0		0.8
EBITDA	587.1	319.9	278.8
Goodwill	126.2	45.9
Assets	3,874.7	2,807.1
Purchases of property, plant and equipment	447.7	294.7	162.7
Storage and Transportation | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	20.4	17.1	37.2
Intersegment Revenues	14.2	10.5	6.7
Costs of product/services sold	0.2	0.2	0.3
Operations and maintenance	4.0	3.3	4.2
General and administrative	0.0	0.0	0.0
Gain (loss) on long-lived assets, net	0.0	0.0	0.0
Goodwill impairment			0.0
Loss on contingent consideration			(57.0)
Gain on acquisition	0.0
Earnings from unconsolidated affiliates, net	34.9	30.8	28.9
Other income, net	0.0	0.0	0.0
EBITDA	65.3	54.9	11.3
Goodwill	0.0	0.0
Assets	980.2	1,004.4
Purchases of property, plant and equipment	0.1	0.6	1.3
Storage and Transportation | Operating Segments | CMLP
Segment Reporting Information [Line Items]
Operating revenues	20.4	17.1	37.2
Intersegment Revenues	14.2	10.5	6.7
Costs of product/services sold	0.2	0.2	0.3
Operations and maintenance	4.0	3.3	4.2
General and administrative	0.0	0.0	0.0
Gain (loss) on long-lived assets, net	0.0	0.0	0.0
Goodwill impairment			0.0
Loss on contingent consideration			(57.0)
Gain on acquisition	0.0
Earnings from unconsolidated affiliates, net	34.9	30.8	28.9
Other income, net	0.0		0.0
EBITDA	65.3	54.9	11.3
Goodwill	0.0	0.0
Assets	980.2	1,004.4
Purchases of property, plant and equipment	0.1	0.6	1.3
Marketing Supply and Logistics
Segment Reporting Information [Line Items]
Operating revenues		2,690.3
Marketing Supply and Logistics | Operating Segments
Segment Reporting Information [Line Items]
Operating revenues	2,325.7	2,690.3	2,155.5
Intersegment Revenues	(189.2)	(202.9)	(141.2)
Costs of product/services sold	2,018.6	2,362.2	1,893.6
Operations and maintenance	36.1	50.8	63.4
General and administrative	0.0	0.0	0.0
Gain (loss) on long-lived assets, net	(0.2)	(27.3)	(48.2)
Goodwill impairment			(38.8)
Loss on contingent consideration			0.0
Gain on acquisition	0.0
Earnings from unconsolidated affiliates, net	0.0	0.0	0.0
Other income, net	0.0	0.0	0.0
EBITDA	81.6	47.1	(29.7)
Goodwill	92.7	92.7
Assets	624.7	612.5
Purchases of property, plant and equipment	5.8	5.6	17.7
Marketing Supply and Logistics | Operating Segments | CMLP
Segment Reporting Information [Line Items]
Operating revenues	2,325.7	2,690.3	2,155.5
Intersegment Revenues	(189.2)	(202.9)	(141.2)
Costs of product/services sold	2,018.6	2,362.2	1,893.6
Operations and maintenance	36.1	50.8	63.4
General and administrative	0.0	0.0	0.0
Gain (loss) on long-lived assets, net	(0.2)	(27.3)	(48.2)
Goodwill impairment			(38.8)
Loss on contingent consideration			0.0
Gain on acquisition	0.0
Earnings from unconsolidated affiliates, net	0.0	0.0	0.0
Other income, net	0.0		0.0
EBITDA	81.6	47.1	(29.7)
Goodwill	92.7	92.7
Assets	624.7	612.5
Purchases of property, plant and equipment	$ 5.8	$ 5.6	$ 17.7

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Certain Balance Sheet Information (Intangible Assets) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	$ 1,076.3	$ 770.3
Less: accumulated amortization	271.1	216.5
Total intangible assets, net	805.2	553.8
Customer accounts
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	438.9	438.9
Less: accumulated amortization	134.4	112.1
Gathering systems and pipelines and related assets
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	631.2	325.2
Gathering systems and pipelines and related assets | Jackalope Gas Gathering Services, LLC
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	306.0
Acquired storage contracts
Finite-Lived Intangible Assets [Line Items]
Less: accumulated amortization	4.2	3.6
Trademarks
Finite-Lived Intangible Assets [Line Items]
Intangible assets, Gross	6.2	6.2
Less: accumulated amortization	132.5	100.8
Crestwood Equity Partners LP
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	54.6	43.5	$ 53.7
CMLP
Finite-Lived Intangible Assets [Line Items]
Amortization of Intangible Assets	54.6	42.1	$ 50.6
Less: accumulated amortization	$ 271.1	$ 216.5

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Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Allowance for doubtful accounts	$ 0.3	$ 0.3
Limited partners' units, issued	72,282,942	71,659,385
Limited partners' units, outstanding	72,282,942	71,659,385
Preferred units, issued	71,257,445	71,257,445
Preferred units, outstanding (in units)	71,257,445	71,257,445
CMLP
Allowance for doubtful accounts	$ 0.3	$ 0.3

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Basis of Presentation and Summary of Significant Accounting Policies Inventory (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Inventory [Line Items]
Inventory	$ 53.7	$ 64.6
Natural Gas Liquids
Inventory [Line Items]
Inventory	53.2	64.2
Spare Parts
Inventory [Line Items]
Inventory	$ 0.5	$ 0.4

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Basis of Presentation and Summary of Significant Accounting Policies (Estimated Economic Lives Of Intangible Assets) (Details)	12 Months Ended
	Dec. 31, 2019
Customer Relationships
Finite-Lived Intangible Assets [Line Items]
Weighted-Average Life (years)	20 years
Maximum | Trademarks
Finite-Lived Intangible Assets [Line Items]
Weighted-Average Life (years)	10 years

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Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating activities
Net income (loss)	$ 319.9	$ 67.0	$ (166.6)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion	195.8	168.7	191.7
Amortization of debt-related deferred costs	6.2	6.8	7.2
Unit-based compensation charges	47.0	28.5	25.5
Loss on long-lived assets, net	6.2	28.6	65.6
Gain on acquisition	(209.4)	0.0	0.0
Goodwill impairment	0.0	0.0	38.8
Loss on contingent consideration	0.0	0.0	57.0
Loss on modification/extinguishment of debt	0.0	0.9	37.7
Earnings from unconsolidated affiliates, net, adjusted for cash distributions received	6.9	0.5	(0.1)
Deferred income taxes	0.0	(0.7)	(2.1)
Other	0.0	0.2	0.9
Changes in operating assets and liabilities:
Accounts receivable	42.9	167.8	(170.7)
Inventory	10.9	(24.1)	(9.9)
Prepaid expenses and other current assets	0.1	(3.1)	1.8
Accounts payable, accrued expenses and other liabilities	(23.3)	(138.6)	140.1
Reimbursements of property, plant and equipment	24.8	21.7	19.6
Change in price risk management activities, net	(7.6)	(70.6)	19.4
Net cash provided by operating activities	420.4	253.6	255.9
Investing activities
Acquisition, net of cash acquired (Note 3)	(462.1)	0.0	0.0
Purchases of property, plant and equipment	(455.5)	(305.5)	(188.4)
Investment in unconsolidated affiliates	(61.3)	(64.4)	(58.0)
Capital distributions from unconsolidated affiliates	35.5	49.2	59.9
Net proceeds from sale of assets	0.8	79.5	225.2
Other	(1.1)	0.0	0.0
Net cash provided by (used in) investing activities	(943.7)	(241.2)	38.7
Financing activities
Proceeds from the issuance of long-term debt	2,307.3	2,274.8	2,838.6
Payments on long-term debt	(1,729.5)	(2,015.7)	(2,913.9)
Payments on finance leases	3.5
Payments on capital leases		(1.6)	(2.7)
Payments for deferred financing costs	(9.0)	(5.7)	(1.0)
Redemption of non-controlling interest	0.0	0.0	(202.7)
Net proceeds from issuance of non-controlling interest	235.0	0.0	175.0
Distributions to partners	(172.4)	(170.8)	(167.6)
Distributions to non-controlling partner	(25.0)	(9.9)	(15.2)
Distributions to preferred unitholders	(60.1)	(60.1)	(15.0)
Net proceeds from issuance of common units	0.0	0.0	15.2
Taxes paid for unit-based compensation vesting	(11.0)	(7.4)	(5.5)
Other	0.0	(0.1)	(0.1)
Net cash provided by (used in) financing activities	531.8	3.5	(294.9)
Net change in cash and restricted cash	8.5	15.9	(0.3)
Cash and restricted cash at beginning of period	17.2	1.3	1.6
Cash and restricted cash at end of period	25.7	17.2	1.3
Supplemental disclosure of cash flow information
Cash paid during the period for interest	123.7	97.4	95.1
Cash paid during the period for income taxes	0.6	3.1	3.1
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	(27.7)	0.3	(20.4)
CMLP
Operating activities
Net income (loss)	310.6	58.6	(175.5)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion	209.9	181.4	202.7
Amortization of debt-related deferred costs	6.2	6.8	7.2
Unit-based compensation charges	47.0	28.5	25.5
Loss on long-lived assets, net	6.2	28.6	65.6
Gain on acquisition	(209.4)	0.0	0.0
Goodwill impairment	0.0	0.0	38.8
Loss on contingent consideration	0.0	0.0	57.0
Loss on modification/extinguishment of debt	0.0	0.9	37.7
Earnings from unconsolidated affiliates, net, adjusted for cash distributions received	6.9	0.5	(0.1)
Deferred income taxes	0.2	(0.1)	0.0
Other	0.0	0.2	0.9
Changes in operating assets and liabilities:
Accounts receivable	41.6	169.3	(170.5)
Inventory	10.9	(24.1)	(9.9)
Prepaid expenses and other current assets	0.1	(3.1)	1.8
Accounts payable, accrued expenses and other liabilities	(23.3)	(138.1)	142.0
Reimbursements of property, plant and equipment	24.8	21.7	19.6
Change in price risk management activities, net	(7.6)	(70.6)	19.4
Net cash provided by operating activities	424.1	260.5	262.2
Investing activities
Acquisition, net of cash acquired (Note 3)	(462.1)	0.0	0.0
Purchases of property, plant and equipment	(455.5)	(305.5)	(188.4)
Investment in unconsolidated affiliates	(61.3)	(64.4)	(58.0)
Capital distributions from unconsolidated affiliates	35.5	49.2	59.9
Net proceeds from sale of assets	0.8	79.5	225.2
Other	(1.1)	0.0	0.0
Net cash provided by (used in) investing activities	(943.7)	(241.2)	38.7
Financing activities
Proceeds from the issuance of long-term debt	2,307.3	2,274.8	2,838.6
Payments on long-term debt	(1,729.5)	(2,015.7)	(2,913.9)
Payments on finance leases	3.5
Payments on capital leases		(1.6)	(2.7)
Payments for deferred financing costs	(9.0)	(5.7)	(1.0)
Redemption of non-controlling interest	0.0	0.0	(202.7)
Net proceeds from issuance of non-controlling interest	235.0	0.0	175.0
Distributions to partners	(235.8)	(238.4)	(174.0)
Distributions to non-controlling partner	(25.0)	(9.9)	(15.2)
Taxes paid for unit-based compensation vesting	(11.0)	(7.4)	(5.5)
Other	0.0	0.1	0.2
Net cash provided by (used in) financing activities	528.5	(3.8)	(301.2)
Net change in cash and restricted cash	8.9	15.5	(0.3)
Cash and restricted cash at beginning of period	16.5	1.0	1.3
Cash and restricted cash at end of period	25.4	16.5	1.0
Supplemental disclosure of cash flow information
Cash paid during the period for interest	123.7	97.4	95.1
Cash paid during the period for income taxes	0.6	0.6	0.6
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued expenses	$ (27.7)	$ 0.3	$ (20.4)

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Acquisition and Divestiture (Tables)

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed

The following table summarizes the final valuation of the assets acquired and liabilities assumed at the acquisition date (in millions):

Cash	$	22.5
Other current assets	30.9
Property, plant and equipment	532.9
Intangible assets	306.0
Goodwill	80.3
Current liabilities	(30.4		)
Other long-term liabilities	(21.5		)
Estimated fair value of 100% interest in Jackalope	920.7
Less:
Elimination of equity investment in Jackalope	226.7
Gain on acquisition of Jackalope	209.4
Total purchase price	$	484.6

Business Acquisition, Pro Forma Information

The tables below presents selected unaudited pro forma information as if the Jackalope Acquisition had occurred on January 1, 2017 (in millions). The pro forma information is not necessarily indicative of the financial results that would have occurred if the transaction had been completed as of the dates indicated. The amounts have been calculated after applying our accounting policies and adjusting the results to reflect the depreciation, amortization and accretion expense that would have been charged assuming the fair value adjustments to property, plant and equipment and intangible assets had been made at the beginning of the respective reporting period. The pro forma net income also includes the effects of interest expense on incremental borrowings and recognition of deferred revenue.

Crestwood Equity

	Year Ended December 31,
	2019		2018		2017
Revenues	$	3,202.6	$	3,729.5	$	3,935.4
Net income (loss)	$	313.5	$	45.0	$	(193.0	)

Crestwood Midstream

	Year ended December 31,
	2019		2018		2017
Revenues	$	3,202.6	$	3,729.5	$	3,935.4
Net income (loss)	$	304.2	$	36.6	$	(201.9	)

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Risk Management (Tables)

12 Months Ended

Dec. 31, 2019

Risk Management - Notional Amounts and Terms of Companys Derivative Financial Instruments [Abstract]

Derivatives Not Designated as Hedging Instruments

The following table summarizes the impact to our consolidated statements of operations related to our commodity-based derivatives reflected in operating revenues and costs of product/services sold during the years ended December 31, 2019, 2018 and 2017 (in millions):

	December 31,
	2019		2018		2017
Product revenues	$	252.3	$	343.3	$	234.1
Gain (loss) reflected in costs of product/services sold	$	19.5	$	29.6	$	(31.2	)

Notional Amounts And Terms Of Company's Derivative Financial Instruments

The notional amounts and terms of our derivative financial instruments include the following:

	December 31, 2019		December 31, 2018
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, ethane, butane, heating oil and crude oil (MMBbls)	33.5	36.6	27.8	30.1
Natural gas (Bcf)	3.7	8.7	1.8	1.8

Schedule of Derivative Instruments in Statement of Financial Position, Fair Value

The following table presents the fair value of our commodity derivative instruments with credit-risk-related contingent features and their associated collateral (in millions):

	December 31,
	2019		2018
Aggregate fair value of derivative instruments with credit-risk-related    contingent features(1)	$	1.6	$	2.2
NYMEX-related net derivative liability position	$	28.8	$	9.4
NYMEX-related cash collateral posted	$	40.4	$	21.7
Cash collateral received, net	$	16.9	$	14.2

(1) At December 31, 2019 and 2018, we posted less than $0.1 million of collateral associated with these derivatives.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The (provision) benefit for income taxes for the years ended December 31, 2019, 2018, and 2017 consisted of the following (in millions):

	CEQP									CMLP
	Year Ended December 31,									Year Ended December 31,
	2019			2018			2017			2019			2018			2017 (1)
Current:
Federal	$	(0.1	)	$	(0.5	)	$	(1.1	)	$	0.1		$	0.1		$	—
State	(0.2		)	(0.3		)	(0.2		)	(0.2		)	(0.2		)	—
Total current	(0.3		)	(0.8		)	(1.3		)	(0.1		)	(0.1		)	—
Deferred:
Federal	0.1			0.5			2.1			—			—			—
State	(0.1		)	0.2			—			(0.2		)	0.1			—
Total deferred	—			0.7			2.1			(0.2		)	0.1			—
(Provision) benefit for income taxes	$	(0.3	)	$	(0.1	)	$	0.8		$	(0.3	)	$	—		$	—

(1)

For the year ended December 31, 2017, our benefit for income taxes was not material to CMLP’s consolidated statement of operations.

Schedule of Deferred Tax Assets and Liabilities

Components of our deferred income taxes at December 31, 2019 and 2018 are as follows (in millions).

	CEQP						CMLP
	December 31,						December 31,
	2019			2018			2019			2018
Total deferred tax asset(1)	$	0.2		$	0.2		$	—		$	—
Total deferred tax liability(1)	(2.8		)	(2.8		)	(0.7		)	(0.6		)
Net deferred tax liability	$	(2.6	)	$	(2.6	)	$	(0.7	)	$	(0.6	)

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Long-Term Debt

12 Months Ended

Dec. 31, 2019

Text Block [Abstract]

Long-Term Debt

Long-Term Debt

Long-term debt consisted of the following at December 31, 2019 and 2018, (in millions):

	December 31,
	2019		2018
Credit Facility	$	557.0	$	578.2
2023 Senior Notes	700.0		700.0
2025 Senior Notes	500.0		500.0
2027 Senior Notes	600.0		—
Other	0.6		1.5
Less: deferred financing costs, net	29.1		26.4
Total debt	2,328.5		1,753.3
Less: current portion	0.2		0.9
Total long-term debt, less current portion	$	2,328.3	$	1,752.4

Credit Facility

In October 2018, Crestwood Midstream entered into a Second Amended and Restated Agreement (the CMLP Credit Agreement). The CMLP Credit Agreement provides for a five-year $1.25 billion revolving credit facility (the CMLP Credit Facility), which expires in October 2023 and is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes. The CMLP Credit Facility allows Crestwood Midstream to increase its available borrowings under the facility by $350.0 million, subject to lender approval and the satisfaction of certain other conditions, as described in the CMLP Credit Agreement. The CMLP Credit Facility also includes a sub-limit of up to $25.0 million for same-day swing line advances and a sub-limit up to $350.0 million for letters of credit. Subject to limited exception, the CMLP Credit Facility is guaranteed and secured by substantially all of the equity interests and assets of Crestwood Midstream’s subsidiaries, except for Crestwood Infrastructure, Crestwood Niobrara, Crestwood Northeast, PRBIC and Tres Holdings and their respective subsidiaries. The Company also guarantees Crestwood Midstream’s payment obligations under its $1.25 billion credit agreement.

Prior to amending and restating its credit agreement in October 2018, Crestwood Midstream had a five-year $1.5 billion senior secured revolving credit facility, which would have expired September 2020 (2020 Credit Facility). We recognized a loss on modification of debt of approximately $0.9 million for the year ended December 31, 2018 in conjunction with amending and restating the CMLP Credit Agreement.

Borrowings under the CMLP Credit Facility (other than the swing line loans) bear interest at either:

• the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) Wells Fargo Bank’s prime rate; or (iii) the Eurodollar Rate adjusted for certain reserve requirements plus 1%; plus a margin varying from 0.50% to 1.50% at December 31, 2019 depending on Crestwood Midstream’s most recent consolidated total leverage ratio; or

• the Eurodollar Rate, adjusted for certain reserve requirements plus a margin varying from 1.50% to 2.50% at December 31, 2019 depending on Crestwood Midstream’s most recent consolidated total leverage ratio.

Swing line loans bear interest at the Alternate Base Rate as described above. The unused portion of the CMLP Credit Facility is subject to a commitment fee ranging from 0.25% to 0.45% according to its most recent consolidated total leverage ratio. Interest on the Alternate Base Rate loans is payable quarterly, or if the adjusted Eurodollar Rate applies, interest is payable at certain intervals selected by Crestwood Midstream.

At December 31, 2019, Crestwood Midstream had $661.3 million of available capacity under its credit facility considering the most restrictive covenants in its credit agreement. At December 31, 2019 and 2018, Crestwood Midstream’s outstanding standby letters of credit were $31.7 million and $68.0 million. Borrowings under the credit facility accrue interest at prime or Eurodollar based rates plus applicable spreads, which resulted in interest rates between 3.96% and 6.00% at December 31, 2019 and 4.63% and 6.75% at December 31, 2018. The weighted-average interest rates on outstanding borrowings as of December 31, 2019 and 2018 was 4.00% and 4.79%.

In April 2019, Crestwood Niobrara acquired the remaining 50% equity interest in Jackalope and funded approximately $250 million of the total purchase price through borrowings under Crestwood Midstream’s credit facility. Contemporaneously with the acquisition of the remaining interest in Jackalope, Crestwood Midstream entered into the First Amendment to the CMLP Credit Agreement to modify certain defined terms and calculations, among other things, to account for the Jackalope Acquisition. The CMLP Credit Facility contains various covenants and restrictive provisions that limit our ability to, among other things, (i) incur additional debt; (ii) make distributions on or redeem or repurchase units; (iii) make certain investments and acquisitions; (iv) incur or permit certain liens to exist; (v) merge, consolidate or amalgamate with another company; (vi) transfer or dispose of assets; and (vii) incur a change in control at either Crestwood Equity or Crestwood Midstream, including an acquisition of Crestwood Holdings’ ownership of Crestwood Equity’s general partner by any third party, including Crestwood Holdings’ debtors under an event of default of their debt since Crestwood Equity’s non-economic general partner interest is pledged as collateral under that debt.

Crestwood Midstream is required under its credit agreement to maintain a net debt to consolidated EBITDA ratio (as defined in its credit agreement) of not more than 5.50 to 1.0, a consolidated EBITDA to consolidated interest expense ratio (as defined in its credit agreement) of not less than 2.50 to 1.0, and a senior secured leverage ratio (as defined in its credit agreement) of not more than 3.75 to 1.0. At December 31, 2019, the net debt to consolidated EBITDA was approximately 4.13 to 1.0, the

consolidated EBITDA to consolidated interest expense was approximately 4.47 to 1.0, and the senior secured leverage ratio was 0.98 to 1.0.

If Crestwood Midstream fails to perform its obligations under these and other covenants, the lenders’ credit commitment could be terminated and any outstanding borrowings, together with accrued interest, under the CMLP Credit Facility could be declared immediately due and payable. The CMLP Credit Facility also has cross default provisions that apply to any of its other material indebtedness.

Senior Notes

2023 Senior Notes. The 6.25% Senior Notes due 2023 (the 2023 Senior Notes) mature on April 1, 2023, and interest is payable semi-annually in arrears on April 1 and October 1 of each year.

2025 Senior Notes. The 5.75% Senior Notes due 2025 (the 2025 Senior Notes) mature on April 1, 2025, and interest is payable semi-annually in arrears on April 1 and October 1 of each year. The net proceeds from the private offering of approximately $492 million were used to repay amounts previously outstanding under CMLP’s senior notes due in 2020 and 2022 as discussed below.

2027 Senior Notes. In April, 2019, Crestwood Midstream issued $600 million of 5.625% unsecured senior notes due 2027 (the 2027 Senior Notes). The 2027 Senior Notes mature on May 1, 2027, and interest is payable semi-annually in arrears on May 1 and November 1 of each year, beginning November 1, 2019. The net proceeds from this offering of approximately $591.1 million were used to fund the acquisition of the remaining 50% equity interest in Jackalope.

In general, each series of Crestwood Midstream’s senior notes are fully and unconditionally guaranteed, joint and severally, on a senior unsecured basis by Crestwood Midstream’s domestic restricted subsidiaries (other than Crestwood Midstream Finance Corp., which has no assets). The indentures contain customary release provisions, such as (i) disposition of all or substantially all the assets of, or the capital stock of, a guarantor subsidiary to a third person if the disposition complies with the indentures; (ii) designation of a guarantor subsidiary as an unrestricted subsidiary in accordance with its indentures; (iii) legal or covenant defeasance of a series of senior notes, or satisfaction and discharge of the related indenture; and (iv) guarantor subsidiary ceases to guarantee any other indebtedness of Crestwood Midstream or any other guarantor subsidiary, provided it no longer guarantees indebtedness under the CMLP Credit Facility.

The indentures restricts the ability of Crestwood Midstream and its restricted subsidiaries to, among other things, sell assets; redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units; create or incur certain liens; enter into agreements that restrict distributions or other payments to Crestwood Midstream from its restricted subsidiaries; consolidate, merge or transfer all or substantially all of their assets; engage in affiliate transactions; create unrestricted subsidiaries; and incur a change in control at either Crestwood Equity or Crestwood Midstream, including an acquisition of Crestwood Holdings’ ownership of Crestwood Equity’s general partner by any third party including Crestwood Holdings’ debtors under an event of default of their debt since Crestwood Equity’s non-economic general partner interest is pledged as collateral under that debt. These restrictions are subject to a number of exceptions and qualifications, and many of these restrictions will terminate when the senior notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Rating Services and no default or event of default (each as defined in the respective indentures) under the indentures has occurred and is continuing.

At December 31, 2019, Crestwood Midstream was in compliance with the debt covenants and restrictions in each of its credit agreements discussed above.

Crestwood Midstream’s Credit Facility and senior notes are secured by the net assets of its guarantor subsidiaries. Accordingly, such assets are only available to the creditors of Crestwood Midstream. Crestwood Equity had restricted net assets of approximately $2,099.3 million as of December 31, 2019.

Repayments. During the year ended December 31, 2017, Crestwood Midstream paid approximately $349.9 million and $457.8 million to purchase, redeem and/or cancel all of the principal amounts previously outstanding under CMLP’s senior notes due in 2020 and 2022, respectively. Crestwood Midstream funded the repayments with a combination of net proceeds from the issuance of the 2025 Senior Notes described above and borrowings under the 2020 Credit Facility. In conjunction with these note repayments, Crestwood Midstream (i) recognized a loss on extinguishment of debt of approximately $37.7 million during the year ended December 31, 2017 (including the write off of approximately $6.8 million of deferred financing costs associated

with the senior notes due in 2022); and (ii) paid $5.1 million and $1.0 million of accrued interest on CMLP’s senior notes due in 2020 and 2022, respectively, on the date they were tendered.

Other Obligations

Our non-interest bearing obligations due under noncompetition agreements consist of agreements between Crestwood Midstream and sellers of certain companies acquired in 2014 with payments due through 2022 and imputed interest ranging from 5.02% to 6.75%. Non-interest bearing obligations at December 31, 2019 and 2018 consisted of $0.7 million and $1.7 million in total payments due under these agreements, less unamortized discount based on imputed interest of $0.1 million and $0.2 million, respectively.

Maturities

The aggregate maturities of principal amounts on our outstanding long-term debt and other notes payable as of December 31, 2019 for the next five years and in total thereafter are as follows (in millions):

2020	$	0.2
2021	0.2
2022	0.2
2023	1,257.0
2024	—
Thereafter	1,100.0
Total debt	$	2,357.6

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligation

Asset Retirement Obligations

We have legal obligations associated with our facilities and right-of-way contracts we hold. Where we can reasonably estimate the ARO, we accrue a liability based on an estimate of the timing and amount of settlement. We record changes in these estimates based on changes in the expected amount and timing of payments to settle our obligations. We did not have any material assets that were legally restricted for use in settling asset retirement obligations as of December 31, 2019 and 2018.

The following table presents the changes in the net asset retirement obligations for the years ended December 31, 2019 and 2018 (in millions):

	2019			2018
Net asset retirement obligations at January 1	$	28.1		$	28.1
Liabilities acquired (1)	1.7			—
Liabilities incurred	3.4			1.2
Liabilities settled	(0.1		)	(2.8		)
Accretion expense	1.7			1.6
Net asset retirement obligations at December 31 (2)	$	34.8		$	28.1

(1) Relates to the Jackalope Acquisition, which is further discussed in Note 3.

(2)

Includes $1.5 million and $0.5 million of current ARO liabilities at December 31, 2019 and 2018.

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Commitments and Contingencies (Narrative) (Details) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Sep. 30, 2019 bbl Release	Dec. 31, 2019 USD ($) miles	Dec. 31, 2019 USD ($) miles	Dec. 31, 2014 bbl Release	Dec. 31, 2018 USD ($)	Sep. 15, 2015 USD ($)	May 31, 2015 bbl
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Loss Contingency, Damages Sought, Value			$ 55.0
Loss Contingency Accrual, at Carrying Value		$ 10.7	$ 10.7		$ 0.1
Miles of Water Gathering Pipeline Removed | miles		30	30
Asset Impairment Charges		$ 4.3
Miles of Water Gathering Pipeline Replaced | miles		12	12
Accrual for Environmental Loss Contingencies		$ 6.7	$ 6.7		1.8
Other Growth and Maintenance Contractual Purchase Obligations
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Firm Purchase Commitments		126.6	126.6
Commodity
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Firm Purchase Commitments		792.4	792.4
Purchase Obligation, Due in Next Twelve Months		712.3	712.3
Crestwood Equity Partners LP
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Self-insurance reserves		9.7	9.7		11.3
Self-insurance reserve expected to be paid in next fiscal year		6.2	6.2
CMLP
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Self-insurance reserves		8.3	8.3		$ 9.6
Self-insurance reserve expected to be paid in next fiscal year		5.2	5.2
Maximum
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Loss Contingency, Estimate of Possible Loss		11.1	11.1			$ 1.1
Minimum
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Loss Contingency, Estimate of Possible Loss		$ 6.7	$ 6.7
Fort Berthold Indian Reservation
Purchase Commitment, Excluding Long-term Commitment [Line Items]
Site Contingency, Loss Exposure, Number of Releases of Produced Water | Release	2			3
Site Contingency, Loss Exposure, Release of Produced Water | bbl	5,000			28,000			5,200

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Earnings Per Limited Partner Unit (Schedule of Reconciliation of Earnings Per Share) (Details) - USD ($) $ / shares in Units, shares in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Net Income (Loss) Allocated to Limited Partners	$ 223.6	$ (9.3)	$ (254.4)
Subordinated unitholders’ interest in net income	1.4	0.0	0.0
Net Income (Loss) Available to Common Stockholders, Diluted	$ 225.0	$ (9.3)	$ (254.4)
Basic (units)	71.8	71.2	69.8
Dilutive units (units)	5.1	0.0	0.0
Weighted Average Limited Partnership Units Outstanding, Diluted	76.9	71.2	69.8
Earnings Per Share, Basic	$ 3.11	$ (0.13)	$ (3.64)
Earnings Per Share, Diluted	$ 2.93	$ (0.13)	$ (3.64)
Niobrara Preferred Units [Member]
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Dilutive units (units)	4.3	0.0	0.0
Preferred Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	7.1	7.1	7.0
Subordinated units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	0.0	0.4	0.4
Dilutive units (units)	0.4	0.0	0.0
Performance Shares
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	0.0	0.4	0.3
Dilutive units (units)	0.4	0.0	0.0
Crestwood Niobrara LLC | Preferred Units
Earnings Per Share, Basic, by Common Class, Including Two Class Method [Line Items]
Antidilutive securities excluded from computation of earnings per share	0.0	6.5	7.1

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Partners' Capital (Schedule of Partnership Distributions) (Details) - USD ($) $ / shares in Units, $ in Millions																											12 Months Ended
	Feb. 14, 2020	Feb. 07, 2020	Nov. 14, 2019	Nov. 07, 2019	Aug. 14, 2019	Aug. 07, 2019	May 15, 2019	May 08, 2019	Feb. 14, 2019	Feb. 07, 2019	Nov. 14, 2018	Nov. 07, 2018	Aug. 14, 2018	Aug. 07, 2018	May 15, 2018	May 08, 2018	Feb. 14, 2018	Feb. 07, 2018	Nov. 14, 2017	Nov. 07, 2017	Aug. 14, 2017	Aug. 07, 2017	May 15, 2017	May 08, 2017	Feb. 14, 2017	Feb. 07, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Disclosure Partners Capital Summary Of Quarterly Distributions Of Available Cash [Abstract]
Distribution to limited partner, record date				Nov. 07, 2019		Aug. 07, 2019		May 08, 2019		Feb. 07, 2019		Nov. 07, 2018		Aug. 07, 2018		May 08, 2018		Feb. 07, 2018		Nov. 07, 2017		Aug. 07, 2017		May 08, 2017		Feb. 07, 2017
Distribution to limited partner, distribution date			Nov. 14, 2019		Aug. 14, 2019		May 15, 2019		Feb. 14, 2019		Nov. 14, 2018		Aug. 14, 2018		May 15, 2018		Feb. 14, 2018		Nov. 14, 2017		Aug. 14, 2017		May 15, 2017		Feb. 14, 2017
Distribution Made to Limited Partner, Distributions Paid, Per Unit			$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60		$ 0.60
Distribution amount			$ 43.1		$ 43.1		$ 43.1		$ 43.1		$ 42.7		$ 42.7		$ 42.7		$ 42.7		$ 42.2		$ 41.8		$ 41.8		$ 41.8		$ 172.4	$ 170.8	$ 167.6
Cash distribution | Subsequent Event
Disclosure Partners Capital Summary Of Quarterly Distributions Of Available Cash [Abstract]
Distribution to limited partner, record date		Feb. 07, 2020
Distribution to limited partner, distribution date	Feb. 14, 2020
Distribution declared per limited partner unit	$ 0.625

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Segments (Reconciliation of Net Income (Loss) to EBITDA) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Segment Reporting Information [Line Items]
Net income (loss)	$ 319.9	$ 67.0	$ (166.6)
Interest and debt expense, net	(115.4)	(99.2)	(99.4)
Loss on modification/extinguishment of debt	0.0	0.9	37.7
(Provision) benefit for income taxes	0.3	0.1	(0.8)
Depreciation, amortization and accretion	195.8	168.7	191.7
EBITDA	631.4	335.9	161.4
CMLP
Segment Reporting Information [Line Items]
Net income (loss)	310.6	58.6	(175.5)
Interest and debt expense, net	(115.4)	(99.2)	(99.4)
Loss on modification/extinguishment of debt	0.0	0.9	37.7
(Provision) benefit for income taxes	0.3	0.0	0.0
Depreciation, amortization and accretion	209.9	181.4	202.7
EBITDA	$ 636.2	$ 340.1	$ 164.3

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Acquisitions and Divestitures (Acquisition) (Details) - USD ($) $ in Millions		1 Months Ended		12 Months Ended
	Apr. 09, 2019	Apr. 30, 2019	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 08, 2019
Business Acquisition [Line Items]
Proceeds from Noncontrolling Interests			$ 175.0	$ 235.0	$ 0.0	$ 175.0
Goodwill				80.3
Investments in unconsolidated affiliates				980.4	1,188.2
Gain on acquisition				209.4	0.0	0.0
Revenues				3,181.9	3,654.1	3,880.9
Net income (loss)				319.9	67.0	(166.6)
Revenues				3,202.6	3,729.5	3,935.4
Net income (loss)				313.5	45.0	(193.0)
Jackalope Gas Gathering Services, LLC
Business Acquisition [Line Items]
Business Acquisition, Transaction Costs				2.8
Cash	$ 22.5
Other current assets	30.9
Property, plant and equipment	532.9
Intangible assets	306.0
Goodwill	80.3
Current liabilities	(30.4)
Other long-term liabilities	(21.5)
Estimated fair value of 100% interest in Jackalope	920.7
Gain on acquisition	209.4			$ 209.4
Total purchase price	$ 484.6
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life				17 years
Revenues				$ 70.1
Net income (loss)				20.9
CMLP
Business Acquisition [Line Items]
Proceeds from Noncontrolling Interests				235.0	0.0	175.0
Investments in unconsolidated affiliates				980.4	1,188.2
Gain on acquisition				209.4	0.0	0.0
Revenues				3,181.9	3,654.1	3,880.9
Net income (loss)				310.6	58.6	(175.5)
Revenues				3,202.6	3,729.5	3,935.4
Net income (loss)				$ 304.2	36.6	$ (201.9)
Crestwood Niobrara LLC
Business Acquisition [Line Items]
Proceeds from Noncontrolling Interests		$ 235.0
Crestwood Niobrara LLC | Williams Partners LP
Business Acquisition [Line Items]
Additional voting interest acquired	50.00%
Business Acquisition, Percentage of Voting Interest After Acquisition	100.00%
Crestwood Niobrara LLC | Jackalope Gas Gathering Services, LLC
Business Acquisition [Line Items]
Proceeds from Noncontrolling Interests		$ 235.0
Valuation Technique, Discounted Cash Flow
Business Acquisition [Line Items]
Business Combination Discount Rate	12.00%
Jackalope Gas Gathering Services, LLC
Business Acquisition [Line Items]
Equity method ownership percentage	50.00%	50.00%		0.00%			50.00%
Investments in unconsolidated affiliates	$ 226.7			$ 0.0	$ 210.2
Jackalope Gas Gathering Services, LLC | Jackalope Gas Gathering Services, LLC
Business Acquisition [Line Items]
Investments in unconsolidated affiliates	$ 226.7

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Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Assets
Cash	$ 25.7	$ 0.9
Restricted cash	0.0	16.3
Accounts receivable, less allowance for doubtful accounts	242.2	251.5
Inventory	53.7	64.6
Assets from price risk management activities	43.2	34.7
Prepaid expenses and other current assets	11.6	11.3
Total current assets	376.4	379.3
Property, plant and equipment	3,612.5	2,598.1
Less: accumulated depreciation	703.4	568.4
Property, plant and equipment, net	2,909.1	2,029.7
Intangible assets	1,076.3	770.3
Less: accumulated amortization	271.1	216.5
Intangible assets, net	805.2	553.8
Goodwill	218.9	138.6
Operating lease right-of-use assets, net	53.8
Investments in unconsolidated affiliates	980.4	1,188.2
Other non-current assets	5.5	4.9
Total assets	5,349.3	4,294.5
Current liabilities:
Accounts payable	189.2	213.0
Accrued expenses and other liabilities	161.7	112.4
Liabilities from price risk management activities	6.7	5.8
Current portion of long-term debt	0.2	0.9
Total current liabilities	357.8	332.1
Long-term debt, less current portion	2,328.3	1,752.4
Operating leases	41.5	0.0
Other long-term liabilities	301.6	173.6
Deferred income taxes	2.6	2.6
Liabilities	2,990.3	2,260.7
Commitments and contingencies (Note 15)
Interest of non-controlling partner in subsidiary (Note 12)	426.2
Interest of non-controlling partner in subsidiary (Note 12)
Partners' capital	1,320.8	1,240.5
Preferred units	612.0	612.0
Total CEQP/CMLP partners’ capital	1,932.8	1,852.5
Interest of non-controlling partner in subsidiary (Note 12)		181.3
Total partners’ capital	1,932.8	2,033.8
Total liabilities and capital	5,349.3	4,294.5
CMLP
Assets
Cash	25.4	0.2
Restricted cash	0.0	16.3
Accounts receivable, less allowance for doubtful accounts	241.9	249.9
Inventory	53.7	64.6
Assets from price risk management activities	43.2	34.7
Prepaid expenses and other current assets	11.6	11.3
Total current assets	375.8	377.0
Property, plant and equipment	3,942.6	2,928.2
Less: accumulated depreciation	875.1	725.9
Property, plant and equipment, net	3,067.5	2,202.3
Intangible assets	1,076.3	770.3
Less: accumulated amortization	271.1	216.5
Intangible assets, net	805.2	553.8
Goodwill	218.9	138.6
Operating lease right-of-use assets, net	53.8
Investments in unconsolidated affiliates	980.4	1,188.2
Other non-current assets	2.4	2.1
Total assets	5,504.0	4,462.0
Current liabilities:
Accounts payable	186.6	210.5
Accrued expenses and other liabilities	160.4	111.3
Liabilities from price risk management activities	6.7	5.8
Current portion of long-term debt	0.2	0.9
Total current liabilities	353.9	328.5
Long-term debt, less current portion	2,328.3	1,752.4
Other long-term liabilities	295.6	171.0
Deferred income taxes	0.7	0.6
Liabilities	2,978.5	2,252.5
Interest of non-controlling partner in subsidiary (Note 12)	426.2
Interest of non-controlling partner in subsidiary (Note 12)
Total CEQP/CMLP partners’ capital	2,099.3	2,028.2
Interest of non-controlling partner in subsidiary (Note 12)		181.3
Total partners’ capital	2,099.3	2,209.5
Total liabilities and capital	$ 5,504.0	$ 4,462.0

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Consolidated Statement of Partners' Capital - USD ($) $ in Millions	Total	CMLP	Preferred Units	Common Unit Capital	Common Unit Capital CMLP	Limited Partners	Limited Partners CMLP	Non-Controlling Partner	Non-Controlling Partner CMLP	Total Partners’ Capital	Total Partners’ Capital CMLP	Subordinated units	Common units	Preferred Units
Balance at the beginning of the period at Dec. 31, 2016			$ 564.5			$ 1,782.0	$ 2,550.7	$ 192.5	$ 192.5	$ 2,539.0	$ 2,743.2
Balance at the beginning of the period (in units) at Dec. 31, 2016												400,000	69,100,000
Preferred units balance at the beginning of the period (in units) at Dec. 31, 2016														66,500,000
Increase (Decrease) in Partners' Capital [Roll Forward]
Proceeds from the issuance of common units				$ 15.2						15.2
Redemption of non-controlling interest								(202.7)	(202.7)	(202.7)	(202.7)
Issuance of common units (in units)	633,271												600,000
Unit-based compensation charges						25.5	25.5			25.5	25.5
Unit-based compensation charges (in units)													800,000
Taxes paid for unit-based compensation vesting						(5.5)	(5.5)			(5.5)	(5.5)
Taxes paid for unit-based compensation vesting (in units)													(200,000)
Distributions to partners			(15.0)			(167.6)	(174.0)	(15.2)	(15.2)	(197.8)	(189.2)
Issuance of non-controlling interest								175.0	175.0	175.0	175.0
Distributions to partners (in units)														4,800,000
Change in fair value of Suburban Propane Partners, L.P. units						(0.8)				(0.8)
Other				(0.9)	$ (0.5)			0.1	0.1	(0.8)	(0.4)
Net income (loss)	$ (166.6)	$ (175.5)	62.5			(254.4)	(200.8)	25.3	25.3	(166.6)	(175.5)
Balance at the beginning of the period (in units) at Dec. 31, 2017												400,000	70,300,000
Preferred units balance at the end of the period (in units) at Dec. 31, 2017														71,300,000
Balance at the end of the period at Dec. 31, 2017			612.0			1,393.5	2,195.4	175.0	175.0	2,180.5	2,370.4
Increase (Decrease) in Partners' Capital [Roll Forward]
Issuance of common units (in units)	0
Unit-based compensation charges						28.5	28.5	(9.9)		28.5	28.5
Unit-based compensation charges (in units)													1,100,000
Taxes paid for unit-based compensation vesting						(7.4)	(7.4)			(7.4)	(7.4)
Taxes paid for unit-based compensation vesting (in units)													(200,000)
Distributions to partners			(60.1)			(170.8)	(238.4)		(9.9)	(240.8)	(248.3)
Change in fair value of Suburban Propane Partners, L.P. units						(0.7)				(0.7)
Other				(0.8)	0.2					(0.8)	0.2
Net income (loss)	$ 67.0	58.6	60.1			(9.3)	42.4	16.2	16.2	67.0	58.6
Balance at the beginning of the period (in units) at Dec. 31, 2018												400,000	71,200,000
Preferred units balance at the end of the period (in units) at Dec. 31, 2018	71,257,445													71,300,000
Balance at the end of the period at Dec. 31, 2018	$ 1,852.5	2,028.2	612.0			1,240.5	2,028.2	181.3	181.3	2,033.8	2,209.5
Increase (Decrease) in Partners' Capital [Roll Forward]
Preferred units, issued	71,257,445
Issuance of common units (in units)	0
Unit-based compensation charges						42.4	42.4	(6.6)		42.4	42.4
Unit-based compensation charges (in units)													1,000,000.0
Taxes paid for unit-based compensation vesting						(11.0)	(11.0)			(11.0)	(11.0)
Taxes paid for unit-based compensation vesting (in units)													(300,000)
Distributions to partners			(60.1)			(172.4)	(235.8)		(6.6)	(239.1)	(242.4)
Change in fair value of Suburban Propane Partners, L.P. units						0.3				0.3
Non-controlling interest reclassification (Note 12)	$ 178.8							(178.8)	(178.8)	(178.8)	(178.8)
Other				(4.0)	(0.3)			0.1	0.1	(3.9)	(0.2)
Net income (loss)	$ 319.9	310.6	60.1			225.0	275.8	4.0	4.0	289.1	279.8
Balance at the beginning of the period (in units) at Dec. 31, 2019												400,000	71,900,000
Preferred units balance at the end of the period (in units) at Dec. 31, 2019	71,257,445													71,300,000
Balance at the end of the period at Dec. 31, 2019	$ 1,932.8	$ 2,099.3	$ 612.0			$ 1,320.8	$ 2,099.3	$ 0.0	$ 0.0	1,932.8	2,099.3
Increase (Decrease) in Partners' Capital [Roll Forward]
Preferred units, issued	71,257,445
Cumulative effect of accounting change (Note 2)				$ 7.5	$ 7.5					$ 7.5	$ 7.5

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Basis of Presentation and Summary of Significant Accounting Policies (Goodwill, by Reporting Unit) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 09, 2019
Goodwill [Line Items]
Goodwill	$ 80.3
Goodwill [Roll Forward]
Beginning Balance	138.6	$ 147.6
Goodwill Impairments during the Period	0.0	0.0	$ 38.8
Goodwill, Transfers		0.0
Goodwill, Written off Related to Sale of Business Unit	(9.0)
Ending Balance	218.9	138.6	147.6
Goodwill, Other Increase (Decrease)		(9.0)
Arrow
Goodwill [Roll Forward]
Beginning Balance	45.9	45.9
Goodwill Impairments during the Period			0.0
Ending Balance	45.9	45.9	45.9
West Coast
Goodwill [Line Items]
Impairment of intangible assets		0.8
Goodwill [Roll Forward]
Beginning Balance	0.0	0.0
Goodwill Impairments during the Period			2.4
Ending Balance		0.0	0.0
NGL Marketing and Logistics
Goodwill [Roll Forward]
Beginning Balance	92.7
Goodwill, Transfers		101.7
Goodwill, Written off Related to Sale of Business Unit		(9.0)
Ending Balance	92.7	92.7
Supply and Logistics
Goodwill [Roll Forward]
Beginning Balance	0.0	101.7
Goodwill Impairments during the Period			0.0
Goodwill, Transfers		(101.7)
Ending Balance		0.0	101.7
Storage and Terminals
Goodwill [Roll Forward]
Beginning Balance	0.0	0.0
Goodwill Impairments during the Period			36.4
Ending Balance		0.0	0.0
Powder River Basin [Member]
Goodwill [Line Items]
Goodwill	80.3
Goodwill [Roll Forward]
Ending Balance	80.3
CMLP
Goodwill [Roll Forward]
Beginning Balance	138.6
Goodwill Impairments during the Period	0.0	0.0	$ 38.8
Ending Balance	218.9	$ 138.6
Williams Partners LP | Crestwood Niobrara LLC
Goodwill [Line Items]
Additional voting interest acquired				50.00%
Arrow | Marketing Supply and Logistics
Goodwill [Line Items]
Gain (Loss) on Sale of Assets and Asset Impairment Charges	$ 4.3

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Certain Balance Sheet Information (Amortization and Interest Expense, Fiscal Year Maturity) (Details) $ in Millions	Dec. 31, 2019 USD ($)
Finite-Lived Intangible Assets [Line Items]
2020	$ 58.9
2021	58.9
2022	58.9
2023	55.0
2024	$ 50.1

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Earnings Per Limited Partner Unit (Tables)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Schedule of Antidilutive Securities Excluded from Computation of Earnings Per Share

The following table summarizes information regarding the weighted-average of common units excluded during the years ended December 31, 2019, 2018 and 2017 (in millions):

	Year Ended December 31,
	2019	2018	2017
Preferred units (1)	7.1	7.1	7.0
Crestwood Niobrara’s preferred units(1)	—	6.5	7.1
Subordinated units(2)	—	0.4	0.4
Stock-based compensation performance units(2)	—	0.4	0.3

(1) See Note 12 for additional information regarding the potential conversion of our preferred units and Crestwood Niobrara’s preferred units to common units.

(2) For a description of our subordinated and stock-based compensation performance units, see Note 12 and Note 13, respectively.

The table below shows CEQP’s net income (loss) per limited partner unit based on the number of basic and diluted limited partner units outstanding for the year ended December 31, 2019, 2018 and 2017 (in millions, except per unit data):

	Year Ended December 31,
	2019		2018			2017
Common unitholders’ interest in net income (loss)	$	223.6	$	(9.3	)	$	(254.4	)
Net income attributable to subordinated units	1.4		—			—
Diluted net income (loss)	$	225.0	$	(9.3	)	$	(254.4	)
Weighted-average limited partners’ units outstanding - basic	71.8		71.2			69.8
Dilutive effect of Crestwood Niobrara preferred units	4.3		—			—
Dilutive effect of stock-based compensation performance units	0.4		—			—
Dilutive effect of subordinated units	0.4		—			—
Weighted-average limited partners’ units outstanding - diluted	76.9		71.2			69.8
Basic earnings per unit:
Net income (loss) per limited partner unit	$	3.11	$	(0.13	)	$	(3.64	)
Diluted earnings per unit:
Net income (loss) per limited partner unit	$	2.93	$	(0.13	)	$	(3.64	)

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Basis of Presentation and Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Schedule of Inventory, Current

Inventory consisted of the following at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Crude oil and NGLs	$	53.2	$	64.2
Spare parts	0.5		0.4
Total inventory	$	53.7	$	64.6

Estimated Useful Lives Of Property, Plant And Equipment

Depreciation is computed by the straight-line method over the estimated useful lives of the assets, as follows:

	Years
Gathering systems and pipelines	15 - 20
Facilities and equipment	3 - 25
Buildings, rights-of-way and easements	1 - 40
Office furniture and fixtures	5 - 10
Vehicles	5

Intangible Assets, Useful life

Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:

	Weighted-Average Life (years)
Customer accounts and revenue contracts	20
Trademarks	10

Intangible assets at CEQP and CMLP consisted of the following at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Customer accounts	$	438.9	$	438.9
Gas gathering, compression and processing contracts (1)	631.2		325.2
Trademarks	6.2		6.2
	1,076.3		770.3
Less: accumulated amortization	271.1		216.5
Total intangible assets, net	$	805.2	$	553.8

(1) Includes $306.0 million related to a revenue contract acquired from the Jackalope Acquisition, which is further discussed in Note 3.

The following table summarizes total accumulated amortization of CEQP’s and CMLP’s intangible assets at December 31, 2019 and 2018 (in millions):

	December 31,
	2019		2018
Customer accounts	$	134.4	$	112.1
Gas gathering, compression and processing contracts	132.5		100.8
Trademarks	4.2		3.6
Total accumulated amortization	$	271.1	$	216.5

Schedule of Goodwill

The following table summarizes the goodwill of our various reporting units (in millions):

	Goodwill Impairments during the Year Ended December 31, 2017		Goodwill at January 1, 2018		Other				Impact of Sale of West Coast				Goodwill at December 31, 2018		Goodwill Addition during the Year Ended December 31, 2019			Goodwill at December 31, 2019
G&P
Arrow	$	—	$	45.9	$	—			$	—			$	45.9	$	—		$	45.9
Powder River Basin	—		—		—				—				—		80.3		(3)	80.3
MS&L
NGL Marketing and Logistics	—		—		101.7			(1)	(9.0		)	(2)	92.7		—			92.7
West Coast	2.4		—		—				—				—		—			—
Supply and Logistics	—		101.7		(101.7		)	(1)	—				—		—			—
Storage and Terminals	36.4		—		—				—				—		—			—
Total	$	38.8	$	147.6	$	—			$	(9.0	)		$	138.6	$	80.3		$	218.9

(1) Reflects the combination of the MS&L reporting units into one NGL Marketing and Logistics reporting unit as further discussed below.

(2) In October 2018, we sold our West Coast assets and wrote off the goodwill attributable to these assets as further discussed below.

(3) In April 2019, we acquired the remaining 50% equity interest in Jackalope from Williams. See Note 3 for a further discussion of the acquisition.

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Investments in Unconsolidated Affiliates (Tables)

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Net Investments and Earnings (Loss) From Unconsolidated Affiliates

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

	Ownership Percentage			Investment				Earnings (Loss) from Unconsolidated Affiliates
	December 31,			December 31,				Year Ended December 31,
	2019			2019		2018		2019			2018		2017
Stagecoach Gas Services LLC	50.00	%		$	814.4	$	830.4	$	34.2		$	29.3	$	25.3
Jackalope Gas Gathering Services, L.L.C.(1)	—	%	(1)	—		210.2		3.7			18.1		10.5
Crestwood Permian Basin Holdings LLC(2)	50.00	%		121.8		104.3		(5.8		)	4.4		8.4
Tres Palacios Holdings LLC	50.01	%		35.9		35.0		0.9			—		2.2
Powder River Basin Industrial Complex, LLC	50.01	%		8.3		8.3		(0.2		)	1.5		1.4
Total				$	980.4	$	1,188.2	$	32.8		$	53.3	$	47.8

(1) On April 9, 2019, Crestwood Niobrara acquired Williams’ 50% equity interest in Jackalope and, as a result, Crestwood Niobrara controls and owns 100% of the equity interests in Jackalope. See Note 3 for a further discussion of this acquisition.

(2) Pursuant to the Crestwood Permian limited liability company agreement, we were allocated 100% of Crestwood New Mexico’s earnings through June 30, 2018. Effective July 1, 2018, our equity earnings from Crestwood New Mexico is based on our ownership percentage of Crestwood Permian, which is currently 50%.

Equity Method Investments

Financial Position Data

	December 31,
	2019										2018
	Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity		Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity
Stagecoach(1)	$	50.6	$	1,686.3	$	3.9	$	1.5	$	1,731.5	$	50.1	$	1,725.1	$	4.2	$	0.9	$	1,770.1
Crestwood    Permian(2)	15.9		386.8		16.3		72.1		314.3		17.7		372.6		16.8		94.7		278.8
Other(3)	11.7		277.9		21.0		121.1		147.5		59.3		658.0		17.4		129.6		570.3
Total	$	78.2	$	2,351.0	$	41.2	$	194.7	$	2,193.3	$	127.1	$	2,755.7	$	38.4	$	225.2	$	2,619.2

(1) As of December 31, 2019, our equity in the underlying net assets of Stagecoach Gas exceeded our investment balance by approximately $51.3 million. This excess amount is entirely attributable to goodwill and, as such, is not subject to amortization.

(2) As of December 31, 2019, the difference of approximately $11.5 million between our equity in Crestwood Permian’s net assets and our investment balance is not subject to amortization.

(3) Includes our Tres Holdings and PRBIC equity investments at December 31, 2019 and 2018, and our Jackalope equity investment at December 31, 2018. As of December 31, 2019, our equity in the underlying net assets of Tres Holdings and PRBIC exceeded our investment balance by approximately $24.0 million and $5.5 million, respectively.

Operating Results Data

	Year Ended December 31,
	2019							2018						2017
	Operating Revenues		Operating Expenses		Net  Income (Loss)			Operating Revenues		Operating Expenses		Net  Income		Operating Revenues		Operating Expenses		Net  Income
Stagecoach	$	163.8	$	83.6	$	80.6		$	171.4	$	79.3	$	92.1	$	168.6	$	77.7	$	91.1
Crestwood Permian	64.8		76.0		(11.1		)	82.2		81.3		5.7		87.3		74.1		14.1
Other(1)	55.1		49.9		5.1			116.9		81.5		35.6		94.5		69.5		24.8
Total	$	283.7	$	209.5	$	74.6		$	370.5	$	242.1	$	133.4	$	350.4	$	221.3	$	130.0

(1) Includes our Jackalope (prior to the acquisition of the remaining 50% interest from Williams in April 2019), Tres Holdings and PRBIC equity investments. We amortize the excess basis in certain of our equity investments as an increase in our earnings from unconsolidated affiliates. We recorded amortization of the excess basis in our Jackalope equity investment of less than $0.1 million for each of the years ended December 31, 2019, 2018 and 2017, which we amortized over the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake). We recorded amortization of the excess basis in our Tres Holdings equity investment of approximately $1.3 million for each of the years ended December 31, 2019, 2018 and 2017, which we amortize over the life of Tres Palacios’ sublease agreement. We recorded amortization of the excess basis in our PRBIC equity investment of approximately $0.4 million, $0.5 million and $0.6 million for the years ended December 31, 2019, 2018 and 2017, which we amortize over the life of PRBIC’s property, plant and equipment.

Distributions and Contributions

	Distributions						Contributions
	Year Ended December 31,						Year Ended December 31,
	2019		2018		2017		2019		2018		2017
Stagecoach Gas	$	52.3	$	48.7	$	47.3	$	2.1	$	—	$	0.8
Jackalope	11.6		32.4		26.3		24.4		49.1		3.5
Crestwood Permian(1)	5.0		14.7		23.4		28.3		12.6		117.5
Tres Holdings(2)	6.3		5.3		9.0		6.3		2.5		5.6
PRBIC(3)	—		1.9		1.6		0.2		0.2		—
Total	$	75.2	$	103.0	$	107.6	$	61.3	$	64.4	$	127.4

(1) On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico Pipeline LLC (Crestwood New Mexico) at our historical book value of approximately $69.4 million. This contribution was treated as a non-cash transaction between entities under common control.

(2) Tres Holdings is required, within 30 days following the end of each quarter, to make quarterly distributions of its available cash (as defined in its limited

liability company agreement) to its members based on their respective ownership percentage.

(3) PRBIC is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage.

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Earnings Per Limited Partner Unit

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Earnings Per Limited Partner Unit

Earnings Per Limited Partner Unit

Our net income (loss) attributable to Crestwood Equity Partners is allocated to the subordinated and limited partner unitholders based on their ownership percentage after giving effect to net income attributable to the preferred units. We calculate basic net income per limited partner unit using the two-class method. Diluted net income per limited partner unit is computed using the treasury stock method, which considers the impact to net income or loss attributable to Crestwood Equity Partners and limited partner units from the potential issuance of limited partner units.

We exclude potentially dilutive securities from the determination of diluted earnings per unit (as well as their related income statement impacts) when their impact on net income attributable to Crestwood Equity Partners per limited partner unit is anti-dilutive. The following table summarizes information regarding the weighted-average of common units excluded during the years ended December 31, 2019, 2018 and 2017 (in millions):

	Year Ended December 31,
	2019	2018	2017
Preferred units (1)	7.1	7.1	7.0
Crestwood Niobrara’s preferred units(1)	—	6.5	7.1
Subordinated units(2)	—	0.4	0.4
Stock-based compensation performance units(2)	—	0.4	0.3

(1) See Note 12 for additional information regarding the potential conversion of our preferred units and Crestwood Niobrara’s preferred units to common units.

(2) For a description of our subordinated and stock-based compensation performance units, see Note 12 and Note 13, respectively.

The table below shows CEQP’s net income (loss) per limited partner unit based on the number of basic and diluted limited partner units outstanding for the year ended December 31, 2019, 2018 and 2017 (in millions, except per unit data):

	Year Ended December 31,
	2019		2018			2017
Common unitholders’ interest in net income (loss)	$	223.6	$	(9.3	)	$	(254.4	)
Net income attributable to subordinated units	1.4		—			—
Diluted net income (loss)	$	225.0	$	(9.3	)	$	(254.4	)
Weighted-average limited partners’ units outstanding - basic	71.8		71.2			69.8
Dilutive effect of Crestwood Niobrara preferred units	4.3		—			—
Dilutive effect of stock-based compensation performance units	0.4		—			—
Dilutive effect of subordinated units	0.4		—			—
Weighted-average limited partners’ units outstanding - diluted	76.9		71.2			69.8
Basic earnings per unit:
Net income (loss) per limited partner unit	$	3.11	$	(0.13	)	$	(3.64	)
Diluted earnings per unit:
Net income (loss) per limited partner unit	$	2.93	$	(0.13	)	$	(3.64	)

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Investments in Unconsolidated Affiliates

12 Months Ended

Dec. 31, 2019

Equity Method Investments and Joint Ventures [Abstract]

Investments in Unconsolidated Affiliates

Investments in Unconsolidated Affiliates

Net Investments and Earnings (Loss)

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

	Ownership Percentage			Investment				Earnings (Loss) from Unconsolidated Affiliates
	December 31,			December 31,				Year Ended December 31,
	2019			2019		2018		2019			2018		2017
Stagecoach Gas Services LLC	50.00	%		$	814.4	$	830.4	$	34.2		$	29.3	$	25.3
Jackalope Gas Gathering Services, L.L.C.(1)	—	%	(1)	—		210.2		3.7			18.1		10.5
Crestwood Permian Basin Holdings LLC(2)	50.00	%		121.8		104.3		(5.8		)	4.4		8.4
Tres Palacios Holdings LLC	50.01	%		35.9		35.0		0.9			—		2.2
Powder River Basin Industrial Complex, LLC	50.01	%		8.3		8.3		(0.2		)	1.5		1.4
Total				$	980.4	$	1,188.2	$	32.8		$	53.3	$	47.8

(1) On April 9, 2019, Crestwood Niobrara acquired Williams’ 50% equity interest in Jackalope and, as a result, Crestwood Niobrara controls and owns 100% of the equity interests in Jackalope. See Note 3 for a further discussion of this acquisition.

(2) Pursuant to the Crestwood Permian limited liability company agreement, we were allocated 100% of Crestwood New Mexico’s earnings through June 30, 2018. Effective July 1, 2018, our equity earnings from Crestwood New Mexico is based on our ownership percentage of Crestwood Permian, which is currently 50%.

Description of Investments

Stagecoach Gas Services LLC

Crestwood Pipeline and Storage Northeast LLC, our wholly-owned subsidiary, owns a 50% equity interest in Stagecoach Gas Services LLC (Stagecoach Gas), and Con Edison Gas Pipeline and Storage Northeast, LLC (CEGP) owns the remaining 50% equity interest in Stagecoach Gas. We account for our 50% equity interest in Stagecoach Gas under the equity method of accounting. Our Stagecoach Gas investment is included in our storage and transportation segment.

Pursuant to the Stagecoach Gas limited liability company agreement, we may be required to make payments of up to $57 million to CEGP after December 31, 2020 if certain criteria are not met by Stagecoach Gas by December 31, 2020, including achieving certain performance targets on growth capital projects. These growth capital projects depend on the construction of other third-party expansion projects, and during 2017, those third-party projects experienced regulatory and other delays that caused Stagecoach Gas to delay its growth capital projects. As a result, our consolidated balance sheets reflect an other long-term liability of $57 million at December 31, 2019 and 2018, and our consolidated income statement for the year ended December 31, 2017 reflects a $57 million loss on contingent consideration related to this obligation.

Jackalope Gas Gathering Services, L.L.C.

On April 9, 2019, Crestwood Niobrara, our consolidated subsidiary, acquired Williams’ 50% equity interest in Jackalope and, as a result, Crestwood Niobrara controls and owns 100% of the equity interests in Jackalope. As a result of this transaction, we eliminated our historical equity investment in Jackalope of approximately $226.7 million as of April 9, 2019 and began consolidating Jackalope’s operations. Our Jackalope investment was included in our gathering and processing segment.

On January 1, 2018, Jackalope adopted the provisions of Topic 606, and we recorded a $9.5 million decrease to our equity method investment and a corresponding decrease to our partners’ capital to reflect our proportionate share of the cumulative effect of accounting change recorded by Jackalope related to the new standard. In addition, our earnings from unconsolidated affiliates decreased by approximately $9.7 million during the year ended December 31, 2018 to reflect our proportionate share of Jackalope’s deferred revenues related to the new standard.

Crestwood Permian Basin Holdings LLC

Crestwood Infrastructure, our wholly-owned subsidiary, owns a 50% equity interest in Crestwood Permian and an affiliate of First Reserve owns the remaining 50% equity interest in Crestwood Permian. We manage and account for our 50% ownership interest in Crestwood Permian, which is a VIE, under the equity method of accounting as we exercise significant influence, but do not control Crestwood Permian and we are not its primary beneficiary due to First Reserve’s rights to exercise control over the entity. Our Crestwood Permian investment is included in our gathering and processing segment.

Prior to October 2017, Crestwood Permian owned 100% of the equity interest of Crestwood Permian Basin LLC (Crestwood Permian Basin). Crestwood Permian Basin has a long-term agreement with SWEPI LP (SWEPI), a subsidiary of Royal Dutch Shell plc, to construct, own and operate a natural gas gathering system (the Nautilus gathering system) in SWEPI’s operated position in the Delaware Permian. In conjunction with the Crestwood Permian Basin’s agreement with SWEPI, Crestwood Permian granted Shell Midstream Partners L.P. (Shell Midstream), a subsidiary of Royal Dutch Shell plc, an option to purchase up to 50% equity interest in Crestwood Permian Basin. In October 2017, Shell Midstream exercised its option and purchased a 50% equity interest in Crestwood Permian Basin from Crestwood Permian for approximately $37.9 million in cash. Crestwood Permian distributed to us approximately $18.9 million of the cash proceeds received.

CEQP issued a guarantee in conjunction with the Crestwood Permian Basin gas gathering agreement with SWEPI described above, under which CEQP agreed to fund 100% of the costs to build the Nautilus gathering system if Crestwood Permian failed to do so. In conjunction with the expiration of that guarantee during 2019, a guarantee became effective that would require CEQP to pay up to $10 million if Crestwood Permian fails to honor its obligations to Crestwood Permian Basin in the event Crestwood Permian Basin fails to satisfy its obligations under its gas gathering agreement with SWEPI. We do not believe this guarantee is probable of resulting in future losses based on our assessment of the nature of the guarantee, the financial condition of the guaranteed party and the period of time that the guarantee has been outstanding, and as a result, we have not recorded a liability on our balance sheet at December 31, 2019 and 2018.

Tres Palacios Holdings LLC

Crestwood Midstream owns a 50.01% ownership interest in Tres Palacios Holdings LLC (Tres Holdings) and is the operator of Tres Palacios Gas Storage LLC (Tres Palacios) and its assets. Brookfield Infrastructure Group owns the remaining 49.99% ownership interest in Tres Holdings. We account for our investment in Tres Holdings under the equity method of accounting. Our Tres Holdings investment is included in our storage and transportation segment.

Powder River Basin Industrial Complex, LLC

Crestwood Crude Logistics LLC, our wholly-owned subsidiary, owns a 50% ownership interest in PRBIC which we account for under the equity method of accounting. Twin Eagle Powder River Basin, LLC owns the remaining 50% ownership interest in PRBIC. Our PRBIC investment is included in our storage and transportation segment

Summarized Financial Information of Unconsolidated Affiliates

Below is summarized financial information for our significant unconsolidated affiliates (in millions; amounts represent 100% of unconsolidated affiliate information):

Financial Position Data

	December 31,
	2019										2018
	Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity		Current Assets		Non-Current Assets		Current Liabilities		Non-Current Liabilities		Members’ Equity
Stagecoach(1)	$	50.6	$	1,686.3	$	3.9	$	1.5	$	1,731.5	$	50.1	$	1,725.1	$	4.2	$	0.9	$	1,770.1
Crestwood    Permian(2)	15.9		386.8		16.3		72.1		314.3		17.7		372.6		16.8		94.7		278.8
Other(3)	11.7		277.9		21.0		121.1		147.5		59.3		658.0		17.4		129.6		570.3
Total	$	78.2	$	2,351.0	$	41.2	$	194.7	$	2,193.3	$	127.1	$	2,755.7	$	38.4	$	225.2	$	2,619.2

(1) As of December 31, 2019, our equity in the underlying net assets of Stagecoach Gas exceeded our investment balance by approximately $51.3 million. This excess amount is entirely attributable to goodwill and, as such, is not subject to amortization.

(2) As of December 31, 2019, the difference of approximately $11.5 million between our equity in Crestwood Permian’s net assets and our investment balance is not subject to amortization.

(3) Includes our Tres Holdings and PRBIC equity investments at December 31, 2019 and 2018, and our Jackalope equity investment at December 31, 2018. As of December 31, 2019, our equity in the underlying net assets of Tres Holdings and PRBIC exceeded our investment balance by approximately $24.0 million and $5.5 million, respectively.

Operating Results Data

	Year Ended December 31,
	2019							2018						2017
	Operating Revenues		Operating Expenses		Net  Income (Loss)			Operating Revenues		Operating Expenses		Net  Income		Operating Revenues		Operating Expenses		Net  Income
Stagecoach	$	163.8	$	83.6	$	80.6		$	171.4	$	79.3	$	92.1	$	168.6	$	77.7	$	91.1
Crestwood Permian	64.8		76.0		(11.1		)	82.2		81.3		5.7		87.3		74.1		14.1
Other(1)	55.1		49.9		5.1			116.9		81.5		35.6		94.5		69.5		24.8
Total	$	283.7	$	209.5	$	74.6		$	370.5	$	242.1	$	133.4	$	350.4	$	221.3	$	130.0

(1) Includes our Jackalope (prior to the acquisition of the remaining 50% interest from Williams in April 2019), Tres Holdings and PRBIC equity investments. We amortize the excess basis in certain of our equity investments as an increase in our earnings from unconsolidated affiliates. We recorded amortization of the excess basis in our Jackalope equity investment of less than $0.1 million for each of the years ended December 31, 2019, 2018 and 2017, which we amortized over the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake). We recorded amortization of the excess basis in our Tres Holdings equity investment of approximately $1.3 million for each of the years ended December 31, 2019, 2018 and 2017, which we amortize over the life of Tres Palacios’ sublease agreement. We recorded amortization of the excess basis in our PRBIC equity investment of approximately $0.4 million, $0.5 million and $0.6 million for the years ended December 31, 2019, 2018 and 2017, which we amortize over the life of PRBIC’s property, plant and equipment.

Distributions and Contributions

	Distributions						Contributions
	Year Ended December 31,						Year Ended December 31,
	2019		2018		2017		2019		2018		2017
Stagecoach Gas	$	52.3	$	48.7	$	47.3	$	2.1	$	—	$	0.8
Jackalope	11.6		32.4		26.3		24.4		49.1		3.5
Crestwood Permian(1)	5.0		14.7		23.4		28.3		12.6		117.5
Tres Holdings(2)	6.3		5.3		9.0		6.3		2.5		5.6
PRBIC(3)	—		1.9		1.6		0.2		0.2		—
Total	$	75.2	$	103.0	$	107.6	$	61.3	$	64.4	$	127.4

(1) On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico Pipeline LLC (Crestwood New Mexico) at our historical book value of approximately $69.4 million. This contribution was treated as a non-cash transaction between entities under common control.

(2) Tres Holdings is required, within 30 days following the end of each quarter, to make quarterly distributions of its available cash (as defined in its limited

liability company agreement) to its members based on their respective ownership percentage.

(3) PRBIC is required to make quarterly distributions of its available cash to its members based on their respective ownership percentage.

Stagecoach Gas. Stagecoach Gas is required, within 30 days following the end of each quarter, to distribute its available cash (as defined in its limited liability company agreement) to its members. Pursuant to the Stagecoach limited liability company agreement, our share of Stagecoach’s available cash increased from 40% to 50% effective July 1, 2019. Prior to July 1, 2019, Stagecoach Gas distributed 40% of its available cash to us and prior to July 1, 2018, Stagecoach Gas distributed 35% of its available cash to us. Because our ownership and distribution percentages differed prior to July 1, 2019, equity earnings from Stagecoach Gas were determined using the Hypothetical Liquidation at Book Value (HLBV) method. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount of cash an equity investment would distribute to its members if the equity investment were to liquidate all of its assets, as valued in accordance with GAAP. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is the members’ share of the earnings or losses from the equity investment

for the period, which approximates how earnings are allocated under the terms of the limited liability company agreement. In January 2020, we received a cash distribution from Stagecoach Gas of approximately $15.5 million.

Crestwood Permian. Crestwood Permian is required, within 30 days following the end of each quarter to distribute 100% of its available cash (as defined in its limited liability company agreement) to its members based on their respective ownership percentages. Pursuant to Crestwood Permian's limited liability company agreement, we received 100% of Crestwood New Mexico's available cash (as defined in the limited liability company agreement) through June 30, 2018, and subsequent to June 30, 2018, our distributions are based on the members respective ownership percentages. Because our ownership and distribution percentages differed prior to June 30, 2018, equity earnings from Crestwood Permian were determined using the HLBV method discussed above. In January 2020, we received a cash distribution from Crestwood Permian of approximately $3.8 million.

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Revenues

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

Revenues

Contract Assets and Contract Liabilities

Our contract assets and contract liabilities are reported in a net position on a contract-by-contract basis at the end of each reporting period. Our receivables related to our revenue contracts accounted for under Topic 606 totaled $225.0 million and $209.7 million for both CEQP and CMLP at December 31, 2019 and 2018, and are included in accounts receivable on our consolidated balance sheets. Our contract assets are included in other non-current assets on our consolidated balance sheets. Our contract liabilities primarily consist of current and non-current deferred revenues. On our consolidated balance sheets, our current deferred revenues are included in accrued expenses and other liabilities and our non-current deferred revenues are included in other long-term liabilities. The majority of revenues associated with our deferred revenues is expected to be recognized as the performance obligations under the related contracts are satisfied over the next 17 years.

The following table provides a summary of the opening and closing balances of our contract assets and contract liabilities (in millions):

	December 31,
	2019		2018
Contract assets (non-current)	$	1.2	$	1.0
Contract liabilities (current)(1)	$	8.8	$	12.0
Contract liabilities (non-current)(1)	$	144.7	$	65.4

(1) During the year ended December 31, 2019, we recognized revenues of approximately $13.3 million that were previously included in contract liabilities (current) at December 31, 2018. The remaining change in our contract liabilities during the year ended December 31, 2019 partially related to approximately $21.5 million of deferred revenues recorded in the purchase price allocation for the Jackalope Acquisition described in more detail in Note 3, and the remainder related primarily to capital reimbursements associated with our revenue contracts and revenue deferrals associated with our contracts with increasing (decreasing) rates.

The following table summarizes the transaction price allocated to our remaining performance obligations under certain contracts that have not been recognized as of December 31, 2019 (in millions):

2020	$	99.4
2021	86.2
2022	79.3
2023	7.4
2024	3.3
Total	$	275.6

Our remaining performance obligations presented in the table above exclude estimates of variable rate escalation clauses in our contracts with customers, and is generally limited to fixed-fee and percentage-of-proceeds service contracts which have fixed pricing and minimum volume terms and conditions. Our remaining performance obligations generally exclude, based on the following practical expedients that we elected to apply, disclosures for (i) variable consideration allocated to a wholly-unsatisfied promise to transfer a distinct service that forms part of the identified single performance obligation; (ii) unsatisfied performance obligations where the contract term is one year or less; and (iii) contracts for which we recognize revenues as amounts are invoiced.

Disaggregation of Revenues

The following tables summarize our revenues from contracts with customers disaggregated by type of product/service sold and by commodity type for each of our segments for the years ended December 31, 2019 and 2018 (in millions). We believe this summary best depicts how the nature, amount, timing and uncertainty of our revenues and cash flows are affected by economic factors.

	Year Ended December 31, 2019
	Gathering and Processing		Storage and Transportation		Marketing, Supply and Logistics		Intersegment Elimination			Total
Revenues:
Topic 606 revenues
Gathering
Natural gas	$	163.2	$	—	$	—	$	—		$	163.2
Crude oil	75.0		—		—		—			75.0
Water	79.6		—		—		—			79.6
Processing
Natural gas	28.9		—		—		—			28.9
Compression
Natural gas	24.9		—		—		—			24.9
Storage
Crude oil	1.9		5.4		—		(2.3		)	5.0
NGLs	—		—		6.3		—			6.3
Pipeline
Crude oil	—		7.9		—		(2.7		)	5.2
Transportation
Crude oil	7.0		—		5.8		(0.1		)	12.7
NGLs	—		—		11.7		—			11.7
Water	—		—		0.2		—			0.2
Rail Loading
Crude oil	—		16.7		—		(5.7		)	11.0
Product Sales
Natural gas	56.8		—		72.3		(33.4		)	95.7
Crude oil	532.1		—		1,315.6		(121.1		)	1,726.6
NGLs	41.4		—		659.3		(20.0		)	680.7
Other	—		4.6		1.2		(3.9		)	1.9
Total Topic 606 revenues	1,010.8		34.6		2,072.4		(189.2		)	2,928.6
Non-Topic 606 revenues(1)	—		—		253.3		—			253.3
Total revenues	$	1,010.8	$	34.6	$	2,325.7	$	(189.2	)	$	3,181.9

(1) Represents revenues primarily related to our commodity-based derivatives. See Note 7 for additional information related to our price risk management activities.

	Year Ended December 31, 2018
	Gathering and Processing		Storage and Transportation		Marketing, Supply and Logistics		Intersegment Elimination			Total
Revenues:
Topic 606 revenues
Gathering
Natural gas	$	134.9	$	—	$	—	$	—		$	134.9
Crude oil	38.8		—		—		—			38.8
Water	58.0		—		—		—			58.0
Processing
Natural gas	10.7		—		—		—			10.7
NGLs	—		—		6.1		—			6.1
Compression
Natural gas	29.1		—		—		—			29.1
Storage
Crude oil	1.8		4.2		—		(1.5		)	4.5
NGLs	—		—		8.6		—			8.6
Pipeline
Crude oil	—		7.1		—		(2.3		)	4.8
Transportation
Crude oil	2.9		—		5.9		—			8.8
NGLs	—		—		26.9		—			26.9
Water	—		—		0.3		—			0.3
Rail Loading
Crude oil	—		14.3		0.2		(5.2		)	9.3
NGLs	—		—		3.1		—			3.1
Product Sales
Natural gas	55.8		—		70.9		(16.6		)	110.1
Crude oil	722.9		—		978.0		(151.3		)	1,549.6
NGLs	84.2		—		1,247.0		(24.5		)	1,306.7
Other	—		2.0		—		(1.5		)	0.5
Total Topic 606 revenues	1,139.1		27.6		2,347.0		(202.9		)	3,310.8
Non-Topic 606 revenues(1)	—		—		343.3		—			343.3
Total revenues	$	1,139.1	$	27.6	$	2,690.3	$	(202.9	)	$	3,654.1

(1)

Represents revenues related to our commodity-based derivatives. See Note 7 for additional information related to our price risk management activities.

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Employee Benefit Plan

12 Months Ended

Dec. 31, 2019

Postemployment Benefits [Abstract]

Employee Benefit Plans

Employee Benefit Plan

A 401(k) plan is available to all of our employees after meeting certain requirements. The plan permits employees to make contributions up to 90% of their salary, up to statutory limits, which was $19,000 in 2019, $18,500 in 2018 and $18,000 in 2017. We match 100% of participants basic contribution up to 6% of eligible compensation. Employees may participate in the plans immediately and certain employees are not eligible for matching contributions until after a 90-day waiting period. Aggregate matching contributions made by us were $4.7 million, $4.6 million and $4.0 million during the years ended December 31, 2019, 2018 and 2017.

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Schedule I - Crestwood Equity Partners LP - Parent Only - Distributions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Parent Company
Dividends received from CMLP	$ 235.8	$ 238.4	$ 174.0

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Basis of Presentation and Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Use of Estimates

Use of Estimates

The preparation of our consolidated financial statements in conformity with GAAP requires the use of estimates and assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these consolidated financial statements. Actual results can differ from those estimates.

Cash and Restricted Cash

Cash

We consider all highly liquid investments with an original maturity of less than three months to be cash.

Restricted Cash

On January 1, 2018, we adopted the provisions of ASU 2016-18, Statement of Cash Flows (Topic 230): Restricted Cash (a consensus of the FASB Emerging Issues Task Force) which changed the classification and presentation of restricted cash in the statement of cash flows. The standard requires us to include restricted cash in our total cash when reconciling the beginning of period and end of period amounts shown on our consolidated statements of cash flows. The retrospective application of this ASU did not have an impact on our consolidated statement of cash flows for the year ended December 31, 2017.

Our restricted cash represents cash held under the terms of certain contractual agreements and is classified as current on our consolidated balance sheets. The $16.3 million decrease in restricted cash during the year ended December 31, 2019 and the $16.3 million increase in restricted cash during the year ended December 31, 2018 is included in operating activities (change in accounts payable, accrued expenses and other liabilities) in the consolidated statements of cash flows.

Inventory

Inventory

Our inventory is stated at the lower of cost or net realizable value and cost is computed predominantly using the average cost method.

Property, Plant and Equipment

Property, Plant and Equipment

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

	Years
Gathering systems and pipelines	15 - 20
Facilities and equipment	3 - 25
Buildings, rights-of-way and easements	1 - 40
Office furniture and fixtures	5 - 10
Vehicles	5

We evaluate our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset

and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds the fair value of the asset, which is typically based on discounted cash flow projections using assumptions as to revenues, costs and discount rates typical of third party market participants, which is a Level 3 fair value measurement.

During 2019 and 2017, we recorded impairments of our property, plant and equipment and we reflected these impairments in long on long-lived assets in our consolidated statements of operations. We did not record impairments of our property, plant and equipment during the year ended December 31, 2018. During 2019, we incurred $4.3 million of impairments of our property, plant and equipment related to certain of our water gathering facilities in our Arrow operations which is further discussed in Note 15. During 2017, we incurred $81.4 million of impairments of our property, plant and equipment related to our MS&L West Coast operations, which resulted from decreasing the forecasted cash flows to be generated by those operations. At December 31, 2017, our estimates of fair value considered a number of factors, including the potential value if we sold the asset, a 12% discount rate and projected cash flows, which is a Level 3 fair value measurement. During 2018, we sold our MS&L West Coast operations for $70.5 million, and recorded a loss on long-lived assets of approximately $26.9 million (including $9.0 million related to the write off of goodwill). See “Goodwill” below and Note 3 for further information on the sale of these assets.

Projected cash flows of our property, plant and equipment are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, constructions costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.

Identifiable Intangible Assets

Identifiable Intangible Assets

Our identifiable intangible assets consist of customer accounts, trademarks and certain revenue contracts. These intangible assets have arisen primarily from acquisitions. We amortize certain of our revenue contracts based on the projected cash flows associated with these contracts if the projected cash flows are readily determinable, otherwise we amortize our revenue contracts on a straight-line basis.  We recognize acquired intangible assets separately if the benefit of the intangible asset is obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or exchanged, regardless of the acquirer’s intent to do so.

Goodwill

Goodwill

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

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

Lessee, Leases

Leases

We maintain leases in the ordinary course of our business activities. Our leases include those for office buildings, crude oil railroad cars, certain vehicles and other operating facilities and equipment. We also sublease certain of our crude oil railroad cars and trucks to a third party. We do not have any material leases where we are considered to be the lessor. Our lease agreements do not contain any material residual value guarantees or material restrictive covenants.

Prior to January 1, 2019, we classified our leases as either capital or operating leases under ASC Topic 840, Leases (Topic 840). We recognized assets (included in property, plant and equipment) and liabilities (included in accrued expenses and other liabilities and other long-term liabilities) related to our capital leases on our consolidated balance sheets. We also recognized depreciation expense and interest expense related to our capital leases on our consolidated statements of operations. The majority of our lease arrangements were classified as operating leases, under which we did not recognize assets or liabilities on our consolidated balance sheets, but rather recognized lease payments on our consolidated statements of operations as either costs of product/services sold or operations and maintenance expense on a straight-line basis over the lease term.

On January 1, 2019, we adopted the provisions of ASC Topic 842, Leases (Topic 842), which revises the accounting for leases by requiring certain leases to be recognized as assets and liabilities on the balance sheet, and requiring companies to disclose additional information about their leasing arrangements. We adopted the standard using the modified retrospective method. Based on the practical expedients allowed for in the standard, we did not reassess the current GAAP classification of leases, easements and rights of way that existed as of January 1, 2019, and we did not utilize the hindsight method in determining the assets and liabilities to be recorded for our existing leases on January 1, 2019. The adoption of this standard required us to make significant judgments on whether our revenue and expenditure-related contracts were considered to be leases (or contain leases) under Topic 842, and if contracts were considered to be leases whether they should be considered operating leases or finance leases under the new standard. We do not have any material revenue contracts that are considered leases under Topic 842.

Investment in Unconsolidated Affiliate

Investments in Unconsolidated Affiliates

Equity method investments in which we exercise significant influence, but do not control and are not the primary beneficiary, are accounted for using the equity method of accounting. Differences in the basis of investments and the separate net asset values of the investees, if any, are amortized into net income or loss over the remaining useful lives of the underlying assets and liabilities, except for the excess related to goodwill. We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, or if we decide to sell an investment in unconsolidated affiliate, we adjust the carrying values of the asset downward, if necessary, to their estimated fair values.

Asset Retirement Obligations

Asset Retirement Obligations

An asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. We record a liability for legal or contractual obligations to retire our long-lived assets associated with our facilities and right-of-way contracts we hold. We record a liability in the period the obligation is incurred and estimable. An ARO is initially recorded at its estimated fair value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the fair value of the liability as a result of the passage of time, which we record as depreciation, amortization and accretion expense on our consolidated statements of operations.

We have various obligations to remove property, plant and equipment on rights-of-way and leases for which we cannot currently estimate the fair value of those obligations because the associated assets have indeterminate lives. An asset retirement obligation liability (and related assets), if any, will be recorded for these obligations once sufficient information is available to reasonably estimate the fair value of the obligations.

Revenue Recognition

Revenue Recognition

We provide gathering, processing, compression, storage, fractionation, and transportation (consisting of pipelines, truck and rail terminals, truck/trailer units and rail cars) services and we sell commodities (including crude oil, natural gas, NGLs and water) under various contracts. These contracts include:

• Fixed-fee contracts. Under these contracts, we do not take title to the underlying crude oil, natural gas, NGLs and water but charge our customers a fixed-fee for the services we provide, which can be a firm reservation charge and/or a charge per volume gathered, processed, compressed, stored, loaded and/or transported (which, in certain contracts, can be subject to a minimum level of volumes);

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

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

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

On January 1, 2018, we adopted the provisions of ASU 2014-09, Revenue from Contracts with Customers (Topic 606), which outlines a single comprehensive model for entities to use in accounting for revenue arising from contracts with customers. We adopted the standard using the modified retrospective method for all revenue contracts that involve revenue generating

activities that occur after January 1, 2018. Results for reporting periods beginning after January 1, 2018 are presented under the new standard, while amounts prior to January 1, 2018 continue to be reported in accordance with our historic accounting under Revenue Recognition (Topic 605).

Prior to January 1, 2018, we recognized revenues for services and products when all of the following criteria were met under Topic 605: (i) services had been rendered or products delivered or sold; (ii) persuasive evidence of an exchange arrangement existed; (iii) the price for services was fixed or determinable; and (iv) collectability was reasonably assured. We recorded deferred revenue when we received amounts from our customers but had not yet met the criteria listed above. We recognized deferred revenue in our consolidated statement of operations when the criteria had been met and all services had been rendered.

Beginning January 1, 2018, we recognize revenues for services and products under revenue contracts as our obligations to perform services or deliver/sell products under the contracts are satisfied. A contract’s transaction price is allocated to each performance obligation in the contract and recognized as revenue when, or as, the performance obligation is satisfied. Our fixed-fee contracts and our percentage-of-proceeds service contracts primarily have a single performance obligation to deliver a series of distinct goods or services that are substantially the same and have the same pattern of transfer to our customers. For performance obligations associated with these contracts, we recognize revenues over time utilizing the output method based on the actual volumes of products delivered/sold or services performed, because the single performance obligation is satisfied over time using the same performance measure of progress toward satisfaction of the performance obligation. The transaction price under certain of our fixed-fee contracts and percentage-of-proceeds service contracts includes variable consideration that varies primarily based on actual volumes that are delivered under the contracts. Because the variable consideration specifically relates to our efforts to transfer the services and/or products under the contracts, we allocate the variable consideration entirely to the distinct service utilizing the allocation exception guidance under Topic 606, and accordingly recognize the variable consideration as revenues at the time the good or service is transferred to the customer.

Certain of our fixed-fee contracts contain minimum volume features under which the customers must utilize our services to gather, compress or load a specified quantity of crude oil or natural gas or pay a deficiency fee based on the difference between actual volumes and the contractual minimum volume. We recognize revenues from these contracts when actual volumes are gathered, compressed or loaded and the likelihood of a customer exercising its remaining rights to make up the deficient volumes under minimum volume commitments becomes remote.

We recognize revenues at a point in time for performance obligations associated with our percentage-of proceeds product contracts and purchase and sale contracts, and these revenues are recognized because control of the underlying product is transferred to the customer when the distinct good is provided to the customer.

The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our performance obligations requires significant judgments and assumptions, including our evaluation of the timing of when control of the underlying good or service has transferred to our customers and the relative standalone selling price of goods and services provided to customers under contracts with multiple performance obligations. Actual results can significantly vary from those judgments and assumptions. We did not have any material contracts with multiple performance obligations or under which we receive material amounts of non-cash consideration during the year ended December 31, 2019.

Contract Assets and Contract Liabilities. Amounts due from our customers under our revenue contracts are typically billed as the service is being provided or on a weekly, bi-weekly or monthly basis and are due within 30 days of billing. Under certain of our contracts, we recognize revenues in excess of billings which we present as contract assets on our consolidated balance sheets.

Under certain contracts, we may be entitled to receive payments in advance of satisfying our performance obligations under the contract. We recognize a liability for these payments in excess of revenue recognized and present it as deferred revenue or contract liabilities on our consolidated balance sheets. Our deferred revenue primarily relates to:

• Capital Reimbursements. Certain contracts in our G&P segment require that our customers reimburse us for capital expenditures related to the construction of long-lived assets utilized to provide services to them under the revenue contracts. Because we consider these amounts as consideration from customers associated with ongoing services to be provided to customers, we defer these upfront payments in deferred revenue and recognize the amounts in revenue over the life of the associated revenue contract as the performance obligations are satisfied under the contract. On January 1, 2018, we recorded an $87.6 million increase to our property, plant and equipment, net, a $69.1 million increase to our deferred revenue liability and an $18.5 million increase to partners’ capital as a result of applying the cumulative impact of adopting the new standard on these types of contracts.

•

Contracts with Increasing (Decreasing) Rates per Unit. Certain contracts in our G&P, S&T and MS&L segments have fixed rates per volume that increase and/or decrease over the life of the contract once certain time periods or thresholds are met. We record revenues on these contracts ratably per unit over the life of the contract based on the remaining performance obligations to be performed, which can result in the deferral of revenue for the difference between the consideration received and the ratable revenue recognized. On January 1, 2018, we recorded a $1.5 million increase to our deferred revenue liability and a corresponding decrease to partners’ capital as a result of applying the cumulative impact of adopting the new standard on these types of contracts.

Credit Risk and Concentrations

Credit Risk and Concentrations

Inherent in our contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing credit risk and have established control procedures, which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate.

Income Taxes

Income Taxes

Crestwood Equity is a master limited partnership and Crestwood Midstream is a limited partnership. Partnerships are generally not subject to federal income tax, although publicly-traded partnerships are treated as corporations for federal income tax purposes and therefore are subject to federal income tax, unless the partnership generates at least 90% of its gross income from qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a partnership for federal income tax purposes. We satisfy the qualifying income requirement and are treated as a partnership for federal and state income tax purposes. Our consolidated earnings are included in the federal and state income tax returns of our partners. However, legislation in certain states allows for taxation of partnerships, and as such, certain state taxes have been included in our accompanying financial statements as income taxes due to the nature of the tax in those particular states as discussed below. In addition, federal and state income taxes are provided on the earnings of the subsidiaries incorporated as taxable entities. We are required to recognize deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities are determined based on the differences between the financial reporting and tax basis of assets and liabilities using expected rates in effect for the year in which the differences are expected to reverse.

We are responsible for the Texas Margin tax computed on the Texas franchise tax returns. The margin tax qualifies as an income tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial statement assets and liabilities and their tax basis attributable to such tax.

Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation requirements under the partnership agreement.

Environmental Costs and Other Contingencies

Environmental Costs and Other Contingencies

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

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

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

Price Risk Management Activities

Price Risk Management Activities

We utilize certain derivative financial instruments to (i) manage our exposure to commodity price risk, specifically, the related change in the fair value of inventory, as well as the variability of cash flows related to forecasted transactions; (ii) ensure the availability of adequate physical supply of commodity; and (iii) manage our exposure to the interest rate risk associated with fixed and variable rate borrowings. We record all derivative instruments on the balance sheet at their fair values as either assets or liabilities measured at fair value. Changes in the fair value of these derivative financial instruments are recorded through current earnings.

Unit-Based Compensation

Unit-Based Compensation

Long-term incentive awards are granted under the Crestwood Equity incentive plan. Unit-based compensation awards consist of restricted units that are valued at the closing market price of CEQP’s common units on the date of grant, which reflects the fair value of such awards. For those awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense. We generally recognize the expense associated with the award over the vesting period on a straight line basis.

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Schedule I - Crestwood Equity Partners LP - Parent Only - Statement of Operations (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Condensed Financial Statements, Captions [Line Items]
Revenues	$ 3,181.9	$ 3,654.1	$ 3,880.9
Operating income (loss)	402.2	113.5	(79.4)
Other income, net	0.6	0.4	1.3
Net income (loss)	319.9	67.0	(166.6)
Parent Company
Condensed Financial Statements, Captions [Line Items]
Revenues	0.0	0.0	0.0
Costs and Expenses	5.3	6.1	6.7
Operating income (loss)	(5.3)	(6.1)	(6.7)
Loss from unconsolidated affiliates	290.0	56.5	(185.7)
Other income, net	0.4	0.4	0.5
Net income (loss)	$ 285.1	$ 50.8	$ (191.9)

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Fair Value Measurements (Schedule of Carrying Values and Estimated Fair Values of Senior Notes) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
2023 Senior Notes | Crestwood Midstream Senior Notes
Debt Instrument [Line Items]
Carrying Amount	$ 700.0	$ 700.0
2023 Senior Notes | CMLP | Crestwood Midstream Senior Notes
Debt Instrument [Line Items]
Fair Value	714.0	668.1
Carrying Amount	695.1	693.6
2025 Senior Notes | Crestwood Midstream Senior Notes
Debt Instrument [Line Items]
Carrying Amount	500.0	500.0
2025 Senior Notes | CMLP | Crestwood Midstream Senior Notes
Debt Instrument [Line Items]
Fair Value	514.4	466.2
Carrying Amount	494.4	493.4
2027 Senior Notes | CMLP
Debt Instrument [Line Items]
Fair Value	610.1	0.0
Carrying Amount	$ 592.1	$ 0.0

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Investments in Unconsolidated Affiliates Table (Details) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Oct. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Apr. 30, 2019	Apr. 09, 2019	Apr. 08, 2019	Jul. 01, 2018
Schedule of Equity Method Investments [Line Items]
Investments in unconsolidated affiliates		$ 980.4	$ 1,188.2
Earnings from unconsolidated affiliates, net		32.8	53.3	$ 47.8
Distributions		75.2	103.0	107.6
Contributions				127.4
Contributions		61.3	64.4	58.0
Current Assets		78.2	127.1
Non-Current Assets		2,351.0	2,755.7
Current Liabilities		41.2	38.4
Non-Current Liabilities		194.7	225.2
Members’ Equity		2,193.3	2,619.2
Operating Revenues		283.7	370.5	350.4
Operating Expenses		209.5	242.1	221.3
Net Income (Loss)		$ 74.6	133.4	130.0
Stagecoach Gas Services LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage		50.00%						50.00%
Investments in unconsolidated affiliates		$ 814.4	830.4
Earnings from unconsolidated affiliates, net		34.2	29.3	25.3
Distributions		52.3	48.7	47.3
Contributions		2.1	0.0	0.8
Current Assets		50.6	50.1
Non-Current Assets		1,686.3	1,725.1
Current Liabilities		3.9	4.2
Non-Current Liabilities		1.5	0.9
Members’ Equity		1,731.5	1,770.1
Operating Revenues		163.8	171.4	168.6
Operating Expenses		83.6	79.3	77.7
Net Income (Loss)		80.6	92.1	91.1
Difference between carrying amount and underlying equity		51.3
Crestwood Permian Basin LLC
Schedule of Equity Method Investments [Line Items]
Operating Revenues		64.8	82.2	87.3
Operating Expenses		76.0	81.3	74.1
Net Income (Loss)		(11.1)	5.7	14.1
Difference between carrying amount and underlying equity		$ 11.5
Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage		0.00%			50.00%	50.00%	50.00%
Investments in unconsolidated affiliates		$ 0.0	210.2			$ 226.7
Earnings from unconsolidated affiliates, net		3.7	18.1	10.5
Distributions		11.6	32.4	26.3
Operating Revenues		55.1	116.9	94.5
Operating Expenses		49.9	81.5	69.5
Net Income (Loss)		5.1	35.6	24.8
Amortization		0.1	0.1	0.1
Other Equity Method Investments
Schedule of Equity Method Investments [Line Items]
Current Assets		11.7	59.3
Non-Current Assets		277.9	658.0
Current Liabilities		21.0	17.4
Non-Current Liabilities		121.1	129.6
Members’ Equity		$ 147.5	570.3
Crestwood Permian Basin Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage		50.00%
Investments in unconsolidated affiliates		$ 121.8	104.3
Earnings from unconsolidated affiliates, net		(5.8)	4.4	8.4
Distributions	$ 18.9	5.0	14.7	23.4
Contributions				117.5
Contributions		28.3	12.6
Current Assets		15.9	17.7
Non-Current Assets		386.8	372.6
Current Liabilities		16.3	16.8
Non-Current Liabilities		72.1	94.7
Members’ Equity		$ 314.3	278.8
Tres Palacios Holdings LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage		50.01%
Investments in unconsolidated affiliates		$ 35.9	35.0
Earnings from unconsolidated affiliates, net		0.9	0.0	2.2
Distributions		6.3	5.3	9.0
Contributions		6.3	2.5	5.6
Difference between carrying amount and underlying equity		24.0
Amortization		$ 1.3	1.3	1.3
Powder River Basin Industrial Complex, LLC
Schedule of Equity Method Investments [Line Items]
Equity method ownership percentage		50.01%
Investments in unconsolidated affiliates		$ 8.3	8.3
Earnings from unconsolidated affiliates, net		(0.2)	1.5	1.4
Distributions		0.0	1.9	1.6
Contributions		0.2	0.2	0.0
Difference between carrying amount and underlying equity		5.5
Amortization		0.4	0.5	0.6
Crestwood Niobrara LLC | Jackalope Gas Gathering Services, LLC
Schedule of Equity Method Investments [Line Items]
Contributions		$ 24.4	$ 49.1	$ 3.5
Crestwood Niobrara LLC | Williams Partners LP
Schedule of Equity Method Investments [Line Items]
Additional voting interest acquired						50.00%

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Condensed Consolidating Financial Information (Balance Sheet) (Details) - USD ($) $ in Millions	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash	$ 25.7	$ 0.9
Restricted cash	0.0	16.3
Accounts receivable	242.2	251.5
Inventory	53.7	64.6
Total current assets	376.4	379.3
Property, plant and equipment, net	2,909.1	2,029.7
Operating lease right-of-use assets, net	53.8
Investments in unconsolidated affiliates	980.4	1,188.2
Other non-current assets	5.5	4.9
Total assets	5,349.3	4,294.5
Current liabilities:
Accounts payable	189.2	213.0
Total current liabilities	357.8	332.1
Long-term liabilities:
Long-term debt, less current portion	2,328.3	1,752.4
Other long-term liabilities	301.6	173.6
Deferred income taxes	2.6	2.6
Liabilities	2,990.3	2,260.7
Interest of non-controlling partner in subsidiary (Note 12)		181.3
Partners' Capital	1,932.8	1,852.5
Total partners’ capital	1,932.8	2,033.8
Total liabilities and capital	5,349.3	4,294.5
Eliminations
Current assets:
Cash	0.0	0.0
Restricted cash		0.0
Accounts receivable	0.0	(16.3)
Inventory	0.0	0.0
Other	0.0	0.0
Total current assets	0.0	(16.3)
Property, plant and equipment, net	0.0	0.0
Goodwill and intangible assets, net	0.0	0.0
Operating lease right-of-use assets, net	0.0
Investments in consolidated affiliates	(4,451.6)	(3,800.4)
Investments in unconsolidated affiliates	0.0	0.0
Other non-current assets	0.0	0.0
Total assets	(4,451.6)	(3,816.7)
Current liabilities:
Accounts payable	0.0	(16.3)
Total current liabilities	0.0	0.0
Total current liabilities	0.0	(16.3)
Long-term liabilities:
Long-term debt, less current portion	0.0	0.0
Other long-term liabilities	0.0	0.0
Deferred income taxes	0.0	0.0
Liabilities	0.0	(16.3)
Interest of non-controlling partner in subsidiary (Note 12)	0.0	0.0
Partners' Capital	(4,451.6)	(3,800.4)
Total partners’ capital		(3,800.4)
Total liabilities and capital	(4,451.6)	(3,816.7)
Parent Company, Crestwood Midstream Partners, LP | Reportable Legal Entities
Current assets:
Cash	1.8	0.2
Restricted cash		16.3
Accounts receivable	0.0	0.0
Inventory	0.0	0.0
Other	0.0	0.0
Total current assets	1.8	16.5
Property, plant and equipment, net	0.0	0.0
Goodwill and intangible assets, net	0.0	0.0
Operating lease right-of-use assets, net	0.0
Investments in consolidated affiliates	4,451.6	3,800.4
Investments in unconsolidated affiliates	0.0	0.0
Other non-current assets	0.0	0.0
Total assets	4,453.4	3,816.9
Current liabilities:
Accounts payable	0.0	16.3
Total current liabilities	25.8	20.0
Total current liabilities	25.8	36.3
Long-term liabilities:
Long-term debt, less current portion	2,328.3	1,752.4
Other long-term liabilities	0.0	0.0
Deferred income taxes	0.0	0.0
Liabilities	2,354.1	1,788.7
Interest of non-controlling partner in subsidiary (Note 12)	0.0	0.0
Partners' Capital	2,099.3	2,028.2
Total partners’ capital		2,028.2
Total liabilities and capital	4,453.4	3,816.9
Guarantor Subsidiaries | Reportable Legal Entities
Current assets:
Cash	0.0	0.0
Restricted cash		0.0
Accounts receivable	229.1	246.3
Inventory	53.7	64.6
Other	54.6	46.0
Total current assets	337.4	356.9
Property, plant and equipment, net	2,331.3	2,202.3
Goodwill and intangible assets, net	650.7	692.4
Operating lease right-of-use assets, net	51.0
Investments in consolidated affiliates	0.0	0.0
Investments in unconsolidated affiliates	0.0	0.0
Other non-current assets	1.9	2.1
Total assets	3,372.3	3,253.7
Current liabilities:
Accounts payable	175.9	210.5
Total current liabilities	123.9	81.8
Total current liabilities	299.8	292.3
Long-term liabilities:
Long-term debt, less current portion	0.0	0.0
Other long-term liabilities	174.8	114.0
Deferred income taxes	0.7	0.6
Liabilities	475.3	406.9
Interest of non-controlling partner in subsidiary (Note 12)	0.0	0.0
Partners' Capital	2,897.0	2,846.8
Total partners’ capital		2,846.8
Total liabilities and capital	3,372.3	3,253.7
Non-Guarantor Subsidiaries | Reportable Legal Entities
Current assets:
Cash	23.6	0.0
Restricted cash		0.0
Accounts receivable	12.8	19.9
Inventory	0.0	0.0
Other	0.2	0.0
Total current assets	36.6	19.9
Property, plant and equipment, net	736.2	0.0
Goodwill and intangible assets, net	373.4	0.0
Operating lease right-of-use assets, net	2.8
Investments in consolidated affiliates	0.0	0.0
Investments in unconsolidated affiliates	980.4	1,188.2
Other non-current assets	0.5	0.0
Total assets	2,129.9	1,208.1
Current liabilities:
Accounts payable	10.7	0.0
Total current liabilities	17.6	16.2
Total current liabilities	28.3	16.2
Long-term liabilities:
Long-term debt, less current portion	0.0	0.0
Other long-term liabilities	120.8	57.0
Deferred income taxes	0.0	0.0
Liabilities	149.1	73.2
Interest of non-controlling partner in subsidiary (Note 12)	426.2	181.3
Partners' Capital	1,554.6	953.6
Total partners’ capital		1,134.9
Total liabilities and capital	2,129.9	1,208.1
CMLP
Current assets:
Cash	25.4	0.2
Restricted cash		16.3
Accounts receivable	241.9	249.9
Inventory	53.7	64.6
Other	54.8	46.0
Total current assets	375.8	377.0
Property, plant and equipment, net	3,067.5	2,202.3
Goodwill and intangible assets, net	1,024.1	692.4
Operating lease right-of-use assets, net	53.8
Investments in consolidated affiliates	0.0	0.0
Investments in unconsolidated affiliates	980.4	1,188.2
Other non-current assets	2.4	2.1
Total assets	5,504.0	4,462.0
Current liabilities:
Accounts payable	186.6	210.5
Total current liabilities	167.3	118.0
Total current liabilities	353.9	328.5
Long-term liabilities:
Long-term debt, less current portion	2,328.3	1,752.4
Other long-term liabilities	295.6	171.0
Deferred income taxes	0.7	0.6
Liabilities	2,978.5	2,252.5
Interest of non-controlling partner in subsidiary (Note 12)	426.2	181.3
Partners' Capital	2,099.3	2,028.2
Total partners’ capital		2,209.5
Total liabilities and capital	$ 5,504.0	$ 4,462.0

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Basis of Presentation and Summary of Significant Accounting Policies (Narrative) (Details) - USD ($) $ in Millions		1 Months Ended	12 Months Ended
	Jun. 21, 2017	Oct. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2019	Jul. 01, 2018	Jan. 01, 2018
Summary Of Significant Accounting Policies [Line Items]
Increase (decrease) in restricted cash			$ (16.3)	$ 16.3
Operating leases			41.5	0.0
Property, plant and equipment, net			2,909.1	2,029.7
Inventory			53.7	64.6
Contribution of Property	$ 69.4
Net proceeds from sale of assets			0.8	79.5	$ 225.2
Debt Issuance Costs, Net			29.1	26.4
Property, plant and equipment			$ 3,612.5	2,598.1
Percentage of gross income from qualifying sources required to be subject to federal income tax, minimum			90.00%
Goodwill impairment			$ 0.0	0.0	38.8
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification			0.7
Goodwill, Written off Related to Sale of Business Unit			9.0
Liabilities, Current			357.8	332.1
Operating lease right-of-use assets, net			53.8
Accrued expenses and other liabilities			161.7	112.4
Other long-term liabilities			301.6	173.6
West Coast
Summary Of Significant Accounting Policies [Line Items]
Impairment of intangible assets				0.8
Goodwill impairment					2.4
Natural Gas Liquids
Summary Of Significant Accounting Policies [Line Items]
Inventory			53.2	64.2
CMLP
Summary Of Significant Accounting Policies [Line Items]
Property, plant and equipment, net			3,067.5	2,202.3
Inventory			53.7	64.6
Net proceeds from sale of assets			0.8	79.5	225.2
Property, plant and equipment			3,942.6	2,928.2
Goodwill impairment			0.0	0.0	$ 38.8
Goodwill, Impaired, Accumulated Impairment Loss			1,399.3
Liabilities, Current			353.9	328.5
Operating lease right-of-use assets, net			53.8
Accrued expenses and other liabilities			160.4	111.3
Other long-term liabilities			295.6	171.0
Crestwood Equity Partners LP
Summary Of Significant Accounting Policies [Line Items]
Property, plant and equipment, net			2,909.1	2,029.7
Property, plant and equipment			3,612.5	2,598.1
Goodwill, Impaired, Accumulated Impairment Loss			1,656.5
Accrued expenses and other liabilities			161.7	$ 112.4
Crestwood Permian Basin Holdings LLC
Summary Of Significant Accounting Policies [Line Items]
Guarantee to third party amount			$ 10.0
Equity method ownership percentage			50.00%
Crestwood Permian Basin Holdings LLC | Crestwood Equity Partners LP
Summary Of Significant Accounting Policies [Line Items]
Equity method ownership percentage					50.00%
Stagecoach Gas Services LLC
Summary Of Significant Accounting Policies [Line Items]
Equity method ownership percentage			50.00%				50.00%
Stagecoach Gas Services LLC | CMLP
Summary Of Significant Accounting Policies [Line Items]
Equity method ownership percentage			50.00%
Measurement Input, Discount Rate
Summary Of Significant Accounting Policies [Line Items]
Fair Value Inputs				12.00%
Measurement Input, Discount Rate | Minimum
Summary Of Significant Accounting Policies [Line Items]
Fair Value Inputs				10.00%
Measurement Input, Discount Rate | Maximum
Summary Of Significant Accounting Policies [Line Items]
Fair Value Inputs				12.00%
Accounting Standards Update 2014-09
Summary Of Significant Accounting Policies [Line Items]
Property, plant and equipment, net								$ 87.6
West Coast | Marketing Supply and Logistics
Summary Of Significant Accounting Policies [Line Items]
Property, Plant and Equipment, Gross, Period Increase (Decrease)		$ (61.8)
Disposal Group, Including Discontinued Operation, Consideration		$ 70.5
Gain (Loss) on Sale of Assets and Asset Impairment Charges			$ 26.9	$ 81.4
Operating Leases [Member]
Summary Of Significant Accounting Policies [Line Items]
Operating leases			41.5
Operating lease right-of-use assets, net			53.8
Accrued expenses and other liabilities			18.1
Operating Leases [Member] | Accounting Standards Update 2016-02
Summary Of Significant Accounting Policies [Line Items]
Operating leases						$ 48.9
Operating lease right-of-use assets, net						67.5
Accrued expenses and other liabilities						18.6
Finance Lease [Member]
Summary Of Significant Accounting Policies [Line Items]
Property, plant and equipment, net			9.5
Property, plant and equipment			14.9
Accrued expenses and other liabilities			3.2
Other long-term liabilities			$ 5.2
Finance Lease [Member] | Accounting Standards Update 2016-02
Summary Of Significant Accounting Policies [Line Items]
Property, plant and equipment						1.6
Accrued expenses and other liabilities						0.3
Other long-term liabilities						$ 1.3

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Partners' Capital (Tables)

12 Months Ended

Dec. 31, 2019

Distribution Made to Limited Liability Company (LLC) Member [Line Items]

Schedule of Distributions Made to Members or Limited Partners, by Distribution

A summary of CEQP’s limited partner quarterly cash distributions for the years ended December 31, 2019, 2018 and 2017 is presented below:

Record Date	Payment Date	Per Unit Rate		Cash Distributions  (in millions)
2019
February 7, 2019	February 14, 2019	$	0.60	$	43.1
May 8, 2019	May 15, 2019	0.60		43.1
August 7, 2019	August 14, 2019	0.60		43.1
November 7, 2019	November 14, 2019	0.60		43.1
				$	172.4
2018
February 7, 2018	February 14, 2018	$	0.60	$	42.7
May 8, 2018	May 15, 2018	0.60		42.7
August 7, 2018	August 14, 2018	0.60		42.7
November 7, 2018	November 14, 2018	0.60		42.7
				$	170.8
2017
February 7, 2017	February 14, 2017	$	0.60	$	41.8
May 8, 2017	May 15, 2017	0.60		41.8
August 7, 2017	August 14, 2017	0.60		41.8
November 7, 2017	November 14, 2017	0.60		42.2
				$	167.6

Consolidation, Less than Wholly Owned Subsidiary, Parent Ownership Interest, Effects of Changes, Net

The following table shows the change in our non-controlling interest in subsidiary at December 31, 2019 (in millions):

Balance at April 9, 2019(1)	$	—
Reclassification of Series A-2 Preferred Units	178.8
Issuance of Series A-3 Preferred Units	235.0
Distributions to non-controlling partner	(18.4		)
Net income attributable to non-controlling partner(2)	30.8
Balance at December 31, 2019	$	426.2

(1) For further detail related to our non-controlling interest in subsidiary for the period December 31, 2018 to April 8, 2019, see our consolidated statements of partners’ capital.

(2) We adjust the carrying amount of our non-controlling interest to its redemption value each period through net income attributable to non-controlling partner.

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Segments (Tables)

12 Months Ended

Dec. 31, 2019

Segment Reporting Information [Line Items]

Reconciliation of Net Income (Loss) to Earnings Before Interest, Taxes, Depreciation and Amortization]

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

	Year Ended December 31,
	2019		2018		2017
Net income (loss)	$	319.9	$	67.0	$	(166.6	)
Add:
Interest and debt expense, net	115.4		99.2		99.4
Loss on modification/extinguishment of debt	—		0.9		37.7
Provision (benefit) for income taxes	0.3		0.1		(0.8		)
Depreciation, amortization and accretion	195.8		168.7		191.7
EBITDA	$	631.4	$	335.9	$	161.4

Reportable Segments

Crestwood Equity

	Year Ended December 31, 2019
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	835.8		$	20.4	$	2,325.7		$	—		$	3,181.9
Intersegment revenues	175.0			14.2		(189.2		)	—			—
Costs of product/services sold	526.1			0.2		2,018.6			—			2,544.9
Operations and maintenance expense	98.7			4.0		36.1			—			138.8
General and administrative expense	—			—		—			103.4			103.4
Gain (loss) on long-lived assets, net	(6.2		)	—		(0.2		)	0.2			(6.2		)
Gain on acquisition	209.4			—		—			—			209.4
Earnings (loss) from unconsolidated affiliates, net	(2.1		)	34.9		—			—			32.8
Other income, net	—			—		—			0.6			0.6
EBITDA	$	587.1		$	65.3	$	81.6		$	(102.6	)	$	631.4
Goodwill	$	126.2		$	—	$	92.7		$	—		$	218.9
Total assets	$	3,715.3		$	980.2	$	624.7		$	29.1		$	5,349.3
Purchases of property, plant and equipment	$	447.7		$	0.1	$	5.8		$	1.9		$	455.5

	Year Ended December 31, 2018
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	946.7		$	17.1	$	2,690.3		$	—		$	3,654.1
Intersegment revenues	192.4			10.5		(202.9		)	—			—
Costs of product/services sold	767.0			0.2		2,362.2			—			3,129.4
Operations and maintenance expense	71.7			3.3		50.8			—			125.8
General and administrative expense	—			—		—			88.1			88.1
Gain (loss) on long-lived assets, net	(3.0		)	—		(27.3		)	1.7			(28.6		)
Earnings from unconsolidated affiliates, net	22.5			30.8		—			—			53.3
Other income, net	—			—		—			0.4			0.4
EBITDA	$	319.9		$	54.9	$	47.1		$	(86.0	)	$	335.9
Goodwill	$	45.9		$	—	$	92.7		$	—		$	138.6
Total assets	$	2,633.4		$	1,004.4	$	612.5		$	44.2		$	4,294.5
Purchases of property, plant and equipment	$	294.7		$	0.6	$	5.6		$	4.6		$	305.5

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			96.5			96.5
Loss on long-lived assets	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			0.5			1.3
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(99.0	)	$	161.4
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4

CMLP

Segment Reporting Information [Line Items]

Reconciliation of Net Income (Loss) to Earnings Before Interest, Taxes, Depreciation and Amortization]

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

	Year Ended December 31,
	2019		2018		2017
Net income (loss)	$	310.6	$	58.6	$	(175.5	)
Add:
Interest and debt expense, net	115.4		99.2		99.4
Loss on modification/extinguishment of debt	—		0.9		37.7
Provision for income taxes	0.3		—		—
Depreciation, amortization and accretion	209.9		181.4		202.7
EBITDA	$	636.2	$	340.1	$	164.3

Reportable Segments

Crestwood Midstream

	Year Ended December 31, 2019
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	835.8		$	20.4	$	2,325.7		$	—		$	3,181.9
Intersegment revenues	175.0			14.2		(189.2		)	—			—
Costs of product/services sold	526.1			0.2		2,018.6			—			2,544.9
Operations and maintenance expense	98.7			4.0		36.1			—			138.8
General and administrative expense	—			—		—			98.2			98.2
Gain (loss) on long-lived assets, net	(6.2		)	—		(0.2		)	0.2			(6.2		)
Gain on acquisition	209.4			—		—			—			209.4
Earnings (loss) from unconsolidated affiliates, net	(2.1		)	34.9		—			—			32.8
Other income, net	—			—		—			0.2			0.2
EBITDA	$	587.1		$	65.3	$	81.6		$	(97.8	)	$	636.2
Goodwill	$	126.2		$	—	$	92.7		$	—		$	218.9
Total assets	$	3,874.7		$	980.2	$	624.7		$	24.4		$	5,504.0
Purchases of property, plant and equipment	$	447.7		$	0.1	$	5.8		$	1.9		$	455.5

	Year Ended December 31, 2018
	Gathering and Processing			Storage and Transportation		Marketing, Supply and Logistics			Corporate			Total
Revenues	$	946.7		$	17.1	$	2,690.3		$	—		$	3,654.1
Intersegment revenues	192.4			10.5		(202.9		)	—			—
Costs of product/services sold	767.0			0.2		2,362.2			—			3,129.4
Operations and maintenance expense	71.7			3.3		50.8			—			125.8
General and administrative expense	—			—		—			83.5			83.5
Gain (loss) on long-lived assets, net	(3.0		)	—		(27.3		)	1.7			(28.6		)
Earnings from unconsolidated affiliates, net	22.5			30.8		—			—			53.3
EBITDA	$	319.9		$	54.9	$	47.1		$	(81.8	)	$	340.1
Goodwill	$	45.9		$	—	$	92.7		$	—		$	138.6
Total assets	$	2,807.1		$	1,004.4	$	612.5		$	38.0		$	4,462.0
Purchases of property, plant and equipment	$	294.7		$	0.6	$	5.6		$	4.6		$	305.5

	Year Ended December 31, 2017
	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics			Corporate			Total
Revenues	$	1,688.2		$	37.2		$	2,155.5		$	—		$	3,880.9
Intersegment revenues	134.5			6.7			(141.2		)	—			—
Costs of product/services sold	1,480.8			0.3			1,893.6			—			3,374.7
Operations and maintenance expense	68.4			4.2			63.4			—			136.0
General and administrative expense	—			—			—			93.1			93.1
Loss on long-lived assets, net	(14.4		)	—			(48.2		)	(3.0		)	(65.6		)
Goodwill impairment	—			—			(38.8		)	—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—			—			(57.0		)
Earnings from unconsolidated affiliates, net	18.9			28.9			—			—			47.8
Other income, net	0.8			—			—			—			0.8
EBITDA	$	278.8		$	11.3		$	(29.7	)	$	(96.1	)	$	164.3
Purchases of property, plant and equipment	$	162.7		$	1.3		$	17.7		$	6.7		$	188.4