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•	natural gas facilities with approximately 2.5 Bcf/d of gathering capacity and 516 MMcf/d of processing capacity;

•	NGL facilities with approximately 20,000 Bbls/d of fractionation capacity and 2.8 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 more than 294,000 Bbls/d of NGLs; and

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

•	natural gas facilities with approximately 0.1 Bcf/d of gathering capacity, 120 MMcf/d of processing capacity, 79.3 Bcf of certificated working storage capacity, and 1.4 Bcf/d of transportation capacity; and

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

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

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

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(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.

(2)

In March 2015, Quicksilver Resources Inc. (Quicksilver) filed for bankruptcy protection. In April 2016, BlueStone Natural Resources II (BlueStone) acquired from Quicksilver its Barnett production assets and we entered into new 10-year gathering and processing agreements with BlueStone. Eni SpA and Tokyo Gas own approximately 27.5% and 25%, respectively, of BlueStone’s Barnett assets. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations, “Our Company.”

(3)	Effective January 1, 2017, Jackalope and Chesapeake replaced the cost-of-service based contract with a new 20-year fixed fee gathering and processing contract that includes minimum revenue guarantees for a five to seven year period.

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

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

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

•	Steuben - a FERC-certificated 6.2 Bcf single-cycle, depleted reservoir storage facility owned and operated by a subsidiary of Stagecoach Gas. A 15-mile, 12-inch diameter pipeline lateral connects the storage facility to the

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

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

(3)	Tres Palacios is interconnected to Florida Gas Transmission Company, LLC, Kinder Morgan Tejas Pipeline, L.P., Houston Pipe Line Company, 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.

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North-South Facilities - include compression and appurtenant facilities installed to expand transportation capacity on the Stagecoach north and south pipeline laterals. The bi-directional interstate facilities provide more than 528 MMcf/d of firm interstate transportation capacity to shippers. The North-South Facilities generate fee-based revenues under a negotiated rate structure authorized by the FERC.

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MARC I Pipeline - a 39-mile, 30-inch diameter interstate natural gas pipeline that connects the North-South Facilities and TGP’s 300 Line in Bradford County, Pennsylvania, with Transco’s Leidy Line in Lycoming County, Pennsylvania. The bi-directional pipeline provides more than 855 MMcf/d of firm interstate transportation capacity to shippers. The MARC I Pipeline generates fee-based revenues under a negotiated rate structure authorized by the FERC.

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

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(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.

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

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

•	The Clean Air Act, which restricts the emission of air pollutants from many sources and imposes various pre-construction, monitoring and reporting requirements and which serves as a legal basis for the EPA in adopting 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 and more detailed Environmental Impact Statements that may be made available for public review and comment;

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

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

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•	adverse changes in general global economic conditions;

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

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

•	competition from imported supplies and alternate fuels;

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

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

•	adoption of various energy efficiency and conservation measures; and

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

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

•	if the current downturn persists, based on current market conditions, it is unlikely that we could issue equity 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.

•	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.

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

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

•	result in an event of default if we fail to satisfy debt obligations or fail to comply with the financial and other restrictive covenants contained in the agreements governing our indebtedness, which event of default could result in

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

•	increase our cost of borrowing;

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

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

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

•	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.

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

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

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

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

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

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•	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.

•	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.

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•	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.

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

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

•	operator error;

•	inadvertent damage from construction, farm and utility equipment;

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

•	fires and explosions;

•	cyber intrusions; and

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

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

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

•	prevailing economic and market conditions;

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

•	changes in tax laws;

•	the level of competition from other midstream companies;

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

•	the level of capital expenditures we make;

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

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

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

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•	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.

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•	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.

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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.

•	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;

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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.

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

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

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

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

(2)

The weighted average number of units outstanding is calculated based on the presumption that the common and subordinated units issued to acquire Legacy Crestwood GP (the accounting predecessor) were outstanding for the entire period prior to the June 19, 2013 acquisition. On the date of the acquisition, all of our limited partner units were considered outstanding. In addition, on November 23, 2015, CEQP completed a 1-for-10 reverse split of its common units. The accounting standards related to earnings per share requires an entity to restate earnings per share when a stock dividend or stock split occurs, and as such, the earnings per unit for the years ended December 31, 2014, 2013, 2013 and 2012 were restated to reflect the 1-for-10 reverse split.

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

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

(5)

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

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

(7)	During 2014 and 2013, we recorded a loss on contingent consideration which reflects the fair value of an earn-out premium associated with the original acquisition of our Marcellus G&P assets from Antero in 2012.

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

(9)	Significant transaction and environmental-related costs and other items for the years ended December 31, 2016, 2015, 2014 and 2013, primarily include costs incurred related to our historical cost savings initiatives, the Simplification Merger, and mergers, acquisitions and joint venture transactions.

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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.

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

•	governmental legislation and regulations;

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

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

•	weather conditions;

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

•	economic conditions;

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

•	environmental claims;

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

•	interest rates; and

•	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.

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•	natural gas facilities with approximately 2.5 Bcf/d of gathering capacity and 516 MMcf/d of processing capacity;

•	NGL facilities with approximately 20,000 Bbls/d of fractionation capacity and 2.8 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 more than 294,000 Bbls/d of NGLs; and

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

•	natural gas facilities with approximately 0.1 Bcf/d of gathering capacity, 120 MMcf/d of processing capacity, 79.3 Bcf of certificated working storage capacity, and 1.4 Bcf/d of transportation capacity; and

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

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

•	Marcellus. We own and operate natural gas gathering and compression systems in Harrison, Doddridge and Barbour Counties, West Virginia. These systems have a total gathering capacity of 875 MMcf/d and 138,080 horsepower of compression;

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

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

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

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Delaware Permian. We own and operate 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 our customers in Eddy County, New Mexico. We also own a 50% interest in the Crestwood Permian joint venture with an affiliate of First Reserve, which we account for under the equity method of accounting. Crestwood Permian, which we operate, is the Nautilus gathering system for SWEPI’s gas production in an area of dedication (approximately 100,000 acres) in Loving, Reeves and Ward Counties, Texas. The Nautilus gathering system, which is initially designed to gather approximately 250 MMcf/d, is supported by a 20-year gathering agreement. Crestwood Permian expects to invest a total of approximately $180 million in the Nautilus gathering system, with the targeted initial in-service date on or before July 1, 2017; and

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

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

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PRB Niobrara. PRBIC, our 50% equity method investment, owns an integrated crude oil loading, storage and pipeline terminal, located in Douglas County, Wyoming, which provides a market for crude oil production from the PRB Niobrara. The joint venture, which is operated by our joint venture partner, Twin Eagle, sources crude oil production from Chesapeake and other PRB Niobrara producers. PRBIC includes 20,000 Bbls/d of rail loading capacity and

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Marcellus. Stagecoach Gas, our 50% equity method investment, owns four natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake) and three transportation pipelines (North/South Facilities, MARC I and the East Pipeline) located in or near the dry portion of the Marcellus Shale. The natural gas storage facilities provide 40.9 Bcf of certificated firm storage capacity and 1.4 Bcf/d of firm transportation capacity to producers, utilities, marketers and other customers. The location of these assets relative to New York City and other premium demand markets along the East Coast, together with the formation of our joint venture with a subsidiary of Consolidated Edison, helps to insulate our operations from production and commodity price changes that can impact storage and transportation operators in other geographic regions; and

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Texas Gulf Coast. Tres Holdings, our 50.01% equity method investment owns a FERC-certificated 38.4 Bcf multi-cycle, salt dome natural gas storage facility. The Tres Palacios storage facility’s 63-mile, dual 24-inch diameter header system (including a 52-mile north pipeline lateral and an approximate 11-mile south pipeline lateral) interconnects with 11 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan Inc.’s Houston central processing plant.

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West Coast. Our West Coast NGL operations provide processing, fractionation, storage, transportation and marketing services to producers, refiners and other customers. We separate NGLs from natural gas, deliver to local natural gas pipelines, retain NGLs for further processing at our fractionation facility, provide butane isomerization and refrigerated storage services, as well as provide to Western US refineries for motor fuel production;

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

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

•	Trucking. Our Trucking operations consist of a fleet of owned and leased trucks with 48,000 Bbls/d of crude oil and produced water transportation capacity and 219,000 Bbls/d of NGL transportation capacity. We provide hauling services to customers in North Dakota, Montana, Wyoming, Texas, New Mexico, Indiana, Mississippi, New Jersey, Ohio, Utah and California; and

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

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In June 2016, we formed a joint venture with a subsidiary of Consolidated Edison to own and further develop our natural gas storage and transportation operations in the Northeast. We retired with proceeds from the joint venture transaction approximately $936 million of indebtedness (including approximately $623 million of borrowings under our credit facility and approximately $313 million of senior notes), which substantially reduced our financial leverage and improved our liquidity. As one of the largest utilities in the Northeast natural gas demand market, Consolidated Edison offers substantial market insight and commercial expertise that should better position our joint venture to capture incremental growth opportunities in one of our core markets;

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In September 2016, we made our first large-scale strategic commitment to the Delaware Permian Basin when we entered into a long-term agreement with SWEPI to construct and operate the Nautilus gathering system to gather SWEPI’s gas production in 100,000 acre area of dedication in the core of this shale play. The Delaware Permian in West Texas continues to emerge as one of the most prolific resource basins in North America. Favorable wellhead economics for producers across multiple target drilling horizons should create a substantial inventory of future wells to be developed in the coming years, which creates significant midstream growth opportunities for companies like us;

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In October 2016, we entered into a joint venture with an affiliate of First Reserve to fund the Nautilus gathering system and other potential growth projects in the Delaware Permian Basin. Our Crestwood Permian joint venture is consistent with our strategy of de-risking investments and raising capital for growth projects on attractive terms. With the Nautilus gathering system and certain gathering and transmission projects we are working to develop in the area, we expect this joint venture will help us to establish a scalable asset base in the core of the Delaware Permian extending from southern New Mexico down through Loving, Ward, Reeves and Culberson Counties, Texas; and

•	Throughout 2016, we declared quarterly distributions of $0.60 per common unit (or $2.40 per common unit annually), a 56% reduction of the distribution compared to the fourth quarter of 2015. The distribution reduction increases our ability to reinvest capital in our business (including expansions and new growth projects) and to further retire indebtedness to strengthen our balance sheet.

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

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During 2015 and 2014, we incurred $8.5 million and $33.2 million of impairments of our property, plant and equipment related to our Granite Wash gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our major customer of those assets has declared bankruptcy and has ceased any substantial drilling in the Granite Wash in the near future given current and future anticipated market conditions related to natural gas and NGLs.

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

•

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

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

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

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

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

•	Increase in distributions to partners of $48.3 million for the year ended December 31, 2016 compared to 2015, and $69.0 million for the year ended December 31, 2015 compared to 2014, primarily due to the increase in the number of limited partner units outstanding as a result of the Simplification Merger;

•	Decrease in distributions paid to non-controlling partners of $219.0 million in 2016 compared to 2015 and $62.3 million in 2015 compared to 2014 due primarily to the Simplification Merger;

•	$58.8 million and $430.5 million net proceeds from the issuance of Crestwood Midstream’s Class A Preferred Units in 2015 and 2014, respectively, prior to the completion of the Simplification Merger; and

•	$53.9 million net proceeds from the issuance of Crestwood Niobrara preferred equity to GE in 2014.

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•	$468.4 million increase in net repayments of amounts outstanding under our credit facilities in 2016 compared to 2015;

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

•	$312.9 million repayments of a portion of Crestwood Midstream’s 2020 Senior Notes and 2022 Senior Notes in 2016;

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

•	$363.6 million redemption of Crestwood Midstream’s 2019 Senior Notes in 2015.

(1)	$77.0 million of our long-term debt is variable interest rate debt at Alternate Base rate or Eurodollar rate plus an applicable spread. These rates plus their applicable spreads were between 3.21% and 5.25% at December 31, 2016. These rates have been applied for each period presented in the table.

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

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

(4)

Primarily related to growth and maintenance contractual purchase obligations in our G&P segment, the development of a rail terminal project, certain upgrades to the US Salt facility, and environmental obligations included in other current liabilities on our balance sheet. Other contractual purchase obligations are defined as legally enforceable agreements to purchase goods or services that have fixed or minimum quantities and fixed or minimum variable price provisions, and that detail approximate timing of the underlying obligations.

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

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

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

•	William C. Gautreaux, our President and Chief Marketing Officer, Marketing, Supply and Logistics Group; and

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

•	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.

•	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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•	Evaluations of the CEO completed by the board members;

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

•	Business performance of the Company relative to established targets.

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*	New to peer group

•	base salary;

•	incentive awards;

•	long-term incentive plan awards; and

•	retirement and health benefits.

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*	Peers include Boardwalk Pipeline Partners LP, EQT Midstream Partners LP, DCP Midstream, LP, Enable Midstream Partners, EnLink Midstream Partners LP, Summit Midstream Partners LP, Tallgrass Energy Partners, Targa Resources Group and Western Gas Partners LP.

•	Robert Halpin received a $75,000 bonus and a $50,000 restricted unit award;

•	Heath Deneke received a $50,000 bonus and a $50,000 restricted unit award; and

•	William Moore received a $100,000 bonus and a $200,000 restricted unit award.

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

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

•	Increased Mr. Deneke’s annual equity grant target to 250% of base salary;

•	Increased Mr. Gautreaux’s annual equity grant target to 237.5% of base salary; and

•	Increased Mr. Moore’s annual equity grant target to 175% of base salary.

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(1)

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

(3)

Amounts paid pursuant to our annual incentive program were previously reported in the “Bonus” column. We have since concluded that it is more appropriate to include such amounts in the “Non-Equity Incentive Plan Compensation” column. Accordingly, the “Bonus” column now reflects only discretionary amount paid for project completion bonuses and individual performance bonuses as described in the Compensation Discussion and

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(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.” Any annual bonus amount paid over and above what is called for by actual KPI performance is reported in the “Bonus” column of the Summary Compensation Table.

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

(3)	Unit award amounts reflect the aggregate grant date fair value of unit awards granted during 2016 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 value of the awards.

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(1)

Mr. Phillips’ restricted units vest as follows: 37,883 on January 15, 2017, 8,619 on January 16, 2017, 1,740 on January 17, 2017, 10,017 on February 26, 2017, 37,883 on January 15, 2018, 38,481 on January 16, 2018, and 37,884 on January 15, 2019; Mr. Halpin’s restricted units vest as follows: 19,279 on January 15, 2017, 2,763 on January 16, 2017, 382 on January 17, 2017, 737 on June 6, 2017, 1,095 on August 15, 2017, 19,279 on January 15, 2018, 14,971 on January 16, 2018, 738 on June 6, 2018, 19,279 on January 15, 2019 and 738 on June 6, 2019; Mr. Deneke’s restricted units vest as follows: 22,893 on January 15, 2017, 4,006 on January 16, 2017, 808 on January 17, 2017, 1,475 on June 6, 2017, 22,894 on January 15, 2018, 20,431 on January 16, 2018, 1,475 on June 6, 2018, 22,894 on January 15, 2019 and 1,476 on June 6, 2019; Mr. Gautreaux’s restricted units vest as follows: 20,661 on January 15, 2017, 3,005 on January 16, 2017, 2,426 on January 17, 2017, 20,662 on January 15, 2018, 3,004 on January 16, 2018 and 20,662 on January 15, 2019 and Mr. Moore’s restricted units vest as follows: 12,145 on January 15, 2017, 2,579 on January 16, 2017, 1,561 on January 17, 2017, 2,951 on June 6, 2017, 12,146 on January 15, 2018, 2,578 on January 16, 2018, 2,951 on June 6, 2018, 12,146 on January 15, 2019 and 2,951 on June 6, 2019. All of the phantom units for Messrs. Phillips, Halpin and Deneke will vest on January 16, 2018.

(2)	Market value for CEQP units based on the NYSE closing price of $25.55 on December 30, 2016.

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(1)

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

(2)	The amounts reflected in the table above include the value of restricted units and phantom units which would be subject to accelerated vesting upon a change of control or termination without “employer cause” or the named executive officer resigns due to “employee cause.” The value reflected for the restricted units is based on the NYSE closing price of $25.55 for CEQP units on December 30, 2016.

(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.

(1)

Reflects the value of restricted unit awards, calculated in accordance with ASC 718, disregarding estimated forfeitures. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13 for a discussion of the assumptions used to determine the FASB ASC Topic 718 value of the awards. These restricted unit grants will vest on the first anniversary of grant. As of December 31, 2016, our non-employee directors held the following restricted unit awards: Mr. Bledsoe, Mr. France, Mr. Gfeller, Mr. Lumpkins, Mr. Sherman and Mr. Somerhalder II each held 3,849 restricted units.

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

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

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

•	each of the directors of our general partner; and

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

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(3)

Preferred Units are held in various Magnetar funds as follows: MTP Energy Master Fund Ltd. (17,018,064), MTP Energy CM LLC (8,580,228), MTP Energy Opportunities Fund LLC (4,084,330), Magnetar Structured Credit Fund, LP (1,689,299), Magnetar Constellation Fund IV LLC (1,410,454), Compass HTV LLC (1,351,765), Magnetar Capital Fund II LP (1,156,235), Blackwell Partners LLC (843,754), Magnetar Global Event Drive Fund LLC (840,608), Magnetar Andromeda Select Fund LLC (680,699), Hipparchus Fund LP (273,844) and Spectrum Opportunities Fund LP (191,165). The address for Magnetar Financial LLC is 1603 Orrington Avenue, 13th Floor, Evanston, IL 60201.

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

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

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

(8)	According to a Schedule 13G/A filed by Oppenheimer Funds, Inc., with the SEC on January 31, 2017, Oppenheimer Funds, Inc. has shared voting and dispositive power over 5,324,018 common units. The address of Oppenheimer Funds, Inc. is Two World Financial Center, 225 Liberty Street, New York, NY 10281.

(9)	According to a Schedule 13G filed by UBS Group AG, with the SEC on February 7, 2017, UBS Group AG has shared voting power and dispositive power over 4,070,611 common units. The address of UBS Group AG is Bahnhofstrasse 45, PO Box CH-8021, Zurich Switzerland.

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(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.

•	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.

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

•	the related person’s interest in the transaction;

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

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

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

•	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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(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.

(2)	Includes fees primarily associated with joint venture transactions and the Simplification Merger.

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

1.	Financial Statements:

2.	Financial Statement Schedules:

3.	Exhibits:

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(b)	Exhibits.

(c)	Financial Statement Schedules.

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•

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

•

Storage and Transportation: our storage and transportation (S&T) operations provide crude oil and natural gas storage and transportation services to producers, utilities and other customers. This segment primarily includes (i) our integrated crude oil loading, storage and pipeline terminal located in the heart of the Bakken and Three Forks Shale oil-producing areas in Williams County, North Dakota (the COLT Hub); and (ii) joint ventures that own regulated natural gas storage and transportation facilities in New York and Pennsylvania, natural gas storage facilities in Texas and a crude-by-rail terminal in Wyoming.

•

Marketing, Supply and Logistics: our marketing, supply and logistics (MS&L) operations provide NGL and crude oil storage, marketing and transportation services to producers, refiners, marketers and other customers. This segment primarily includes (i) our fleet of rail and rolling stock, which includes our rail-to-truck NGL terminals located in Florida, Nevada, New Jersey, New York, Rhode Island and Wyoming, our truck terminal located in Utah, and our truck maintenance facilities located in Indiana, Mississippi, New Jersey and Ohio; (ii) our West Coast processing and fractionation operations located near Bakersfield, California; (iii) our NGL storage facilities in Bath, New York and Seymour, Indiana; (iv) our crude oil and produced water transportation assets; and (v) our solution-mining and salt production company (US Salt).

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During 2015 and 2014, we incurred $8.5 million and $13.2 million of impairments of our property, plant and equipment related to our Granite Wash gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our major customer of those assets declared bankruptcy and ceased substantial drilling in the Granite Wash in the near future given current and future anticipated market conditions related to normal gas and NGLs. The fair value of our property, plant and equipment related to our Granite Wash operations was $11.2 million as of December 31, 2015.

•

During 2015, Crestwood Equity incurred a $354.4 million impairment of its property, plant and equipment related to its Barnett gathering and processing operations, which resulted from the actions of our primary customer in the Barnett Shale, Quicksilver Resources, Inc. (Quicksilver), related to its filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015. The fair value of our property, plant and equipment related to our Barnett operations was $298.5 million as of December 31, 2015. Crestwood Midstream did not record an impairment of its property, plant and equipment related to its gathering and processing assets in the Barnett Shale as the sum of the undiscounted cash flows expected to result from the use of the assets and their eventual disposition exceeded the carrying value of the property, plant and equipment by over 30%. As a result, Crestwood Midstream’s property, plant and equipment exceeds Crestwood Equity’s property, plant and equipment related to its gathering and processing assets in the Barnett Shale as of December 31, 2016 and 2015.

•

During 2015, we incurred $61.9 million and $45.7 million of impairments of property, plant and equipment related to our Fayetteville and Haynesville gathering and processing operations, respectively, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas. The fair value of our property, plant and equipment related to our Fayetteville and Haynesville operations was $59.3 million and $3.8 million, respectively, as of December 31, 2015.

•

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

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During 2016, we incurred a $31.4 million impairment of intangible assets related to our MS&L Trucking operations, which resulted from the impact of increased competition on our Trucking business and the loss of several key customer relationships that were acquired in 2013 to which the intangible assets related. The fair value of our intangible assets related to our MS&L Trucking operations was $3.7 million as of December 31, 2016.

•	During 2015, Crestwood Equity fully impaired $238.9 million of its intangible assets related to its Barnett gathering and processing operations, which resulted from the actions of our primary customer in the Barnett Shale, Quicksilver, related to filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015.

•

During 2015, we fully impaired $70.9 million and $6.0 million of intangible assets related to our Fayetteville and Haynesville gathering and processing operations, respectively, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas.

•

During 2014, we fully impaired $20 million of intangible assets related to our Granite Wash gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our major customer of those assets declared bankruptcy and ceased substantial drilling in the Granite Wash in the near future given current and future anticipated market conditions related to natural gas and NGLs.

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(1)	In December 2016, we acquired four NGL terminals for our MS&L segment for approximately $7.2 million with total goodwill of approximately $2.4 million. This acquisition was not material to our consolidated financial statements as of and for the year ended December 31, 2016.

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

(2)	During the year ended December 31, 2015, we recorded additional equity earnings of approximately $3.2 million related to a gain associated with the adjustment of our member’s capital account by our equity investee.

(3)

During the year ended December 31, 2015, we recorded impairments of our PRBIC and Jackalope equity investments of approximately $23.4 million and $51.4 million. For a further discussion of these impairments, see Note 2. During the year ended December 31, 2016, we recorded a reduction of our equity earnings from PRBIC of approximately $5.8 million related to impairments recorded by our equity investee.

(1)	As of December 31, 2016, our equity in the underlying net assets of Stagecoach Gas exceeded our investment balance by approximately $51.4 million. This excess amount is entirely attributable to goodwill and, as such, is not subject to amortization. Our Stagecoach Gas investment is included in our storage and transportation segment.

(2)

Includes our Jackalope, Tres Holdings LLC (Tres Holdings), PRBIC and Crestwood Permian Basin Holdings (Crestwood Permian) investments. As of December 31, 2016, our equity in the underlying net assets of Jackalope, Tres Holdings and PRBIC exceeded our investment balance by approximately $0.8 million, $27.8 million and $15.3 million, respectively. As of December 31, 2016, our investment balance in Crestwood Permian approximated our equity in the underlying net assets. Our Tres Holdings and PRBIC investments are included in our storage and transportation segment and our Crestwood Permian investment is included in our gathering and processing segment.

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(1)

Includes our Jackalope, Tres Holdings, PRBIC and Crestwood Permian investments. We recorded amortization of our Jackalope excess basis of less than $0.1 million, $3.0 million and $3.1 million for the years ended December 31, 2016, 2015 and 2014, which we amortize over 20 years, which represents the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake). We recorded amortization of our Tres Holdings excess basis of $1.3 million for both the years ended December 31, 2016 and 2015, which we amortize over the life of Tres Palacios Gas Storage LLC’s (Tres Palacios) sublease agreement. We recorded amortization of our PRBIC excess basis of approximately $1.6 million for the year ended December 31, 2016, which we amortize over the life of PRBIC’s property, plant and equipment and its agreement with Chesapeake. We reflect the amortization of our excess basis as an increase in earnings from our consolidated affiliates.

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•

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.

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

(2)	Amount is reflected in other assets on CEQP’s consolidated balance sheets.

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•	the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) Wells Fargo Bank’s prime rate; or (iii) the Eurodollar Rate adjusted for certain reserve requirements plus 1%; plus a margin varying from 0.75% to 1.75% depending on Crestwood Midstream’s most recent consolidated total leverage ratio; or

•	the Eurodollar Rate, adjusted for certain reserve requirements plus a margin varying from 1.75% to 2.75% depending on Crestwood Midstream’s most recent consolidated total leverage ratio.

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•	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;

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

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(3)	Includes $3.2 million and $0.1 million unit-based compensation charges allocated from Crestwood Holdings to CEQP and CMLP during the years ended December 31, 2016 and 2015.

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(1)

Amount includes goodwill and intangible asset impairments of $109.7 million and $84.3 million during the three months ended March 31, 2016 and December 31, 2016. Amount includes goodwill, property, plant and equipment and intangible asset impairments of approximately $281.0 million, $610.8 million and $1,332.3 million during the three months ended June 30, 2015, September 30, 2015 and December 31, 2015, respectively. See Note 2 for a further discussion of our impairments recorded during 2016 and 2015.

(2)

Amount includes goodwill and intangible asset impairments of $109.7 million and $84.3 million during the three months ended March 31, 2016 and December 31, 2016. Amount includes goodwill, property, plant and equipment and intangible asset impairments of approximately $68.6 million, $610.8 million and $694.3 million during the three months ended June 30, 2015, September 30, 2015 and December 31, 2015, respectively. See Note 2 for a further discussion of our impairments recorded during 2016 and 2015.

(3)	Amount includes impairments of our PRBIC and Jackalope equity investments of $23.4 million and $51.4 million during the three months ended December 31, 2015. See Note 2 for a further discussion of these impairments recorded during 2015.

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(1)	Dividend requirement of preferred securities issued by our consolidated subsidiary was paid in units and therefore were not considered a fixed charge for purposes of this computation.

(2)

For purposes of computing the ratio of earnings to fixed charges, "earnings" consists of pretax income from continuing operations before adjustment for non-controlling interest and income from equity investee plus fixed charges (excluding capitalized interest) and amortized capitalized interest. "Fixed charges" represents interest incurred (whether expensed or capitalized), amortization of debt costs and that portion of rental expense on operating leases deemed to be the equivalent of interest.

(3)	Earnings for the years ended December 31, 2016, 2015, 2014 and 2013 were inadequate to cover fixed charges by approximately $208.8 million,$2,330.3 million, $33.6 million and $57.8 million.

(1)	Dividend requirement of preferred securities issued by our consolidated subsidiary was paid in units and therefore were not considered a fixed charge for purposes of this computation.

(2)

For purposes of computing the ratio of earnings to fixed charges, "earnings" consists of pretax income from continuing operations before adjustment for non-controlling interest and income from equity investee plus fixed charges (excluding capitalized interest) and amortized capitalized interest. "Fixed charges" represents interest incurred (whether expensed or capitalized), amortization of debt costs and that portion of rental expense on operating leases deemed to be the equivalent of interest.

(3)	Earnings for the years ended December 31, 2016, 2015, 2014 and 2013 were inadequate to cover fixed charges by approximately $214.5 million, $1,435.8 million, $8.5 million and $19.9 million.

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(1)	Registration Statement (Form S-8 No. 333-201534);

(2)	Registration Statement (Form S-8 No. 333-148619);

(3)	Registration Statement (Form S-8 No. 333-131767);

(4)	Registration Statement (Form S-8 No. 333-83872);

(5)	Registration Statement (Form S-3ASR No. 333-194777); and

(6)	Registration Statement (Form S-3 No. 333-210146)

(1)	Registration Statement (Form S-3 No. 333-197327);

(2)	Registration Statement (Form S-3 No. 333-194778);

(3)	Registration Statement (Form S-3 No. 333-185946);

(4)	Registration Statement (Form S-8 No. 333-178659); and

(5)	Registration Statement (Form S-3ASR No. 333-194776)

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.

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.

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.

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.

(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.

(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.

(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.

(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.