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CEQP Crestwood Equity Partners

Filed: 25 Feb 21, 7:00pm
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, 2020

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 numberState or other jurisdiction of incorporation or organization(I.R.S. Employer Identification No.)
Crestwood Equity Partners LP001-34664Delaware43-1918951
Crestwood Midstream Partners LP001-35377Delaware20-1647837
 
811 Main StreetSuite 3400HoustonTexas77002
(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 classTrading SymbolName of each exchange on which registered
Crestwood Equity Partners LPCommon Units representing limited partnership interestsCEQPNew York Stock Exchange
Crestwood Equity Partners LPPreferred Units representing limited partner interestsCEQP-PNew York Stock Exchange
Crestwood Midstream Partners LPNoneNoneNone
Securities registered pursuant to Section 12(g) of the Act:
Crestwood Equity Partners LPNone
Crestwood Midstream Partners LPNone
Indicate by check mark if registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act. 
Crestwood Equity Partners LPYesNo
Crestwood Midstream Partners LPYesNo
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 LPYesNo
Crestwood Midstream Partners LPYesNo
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 LPYesNo
Crestwood Midstream Partners LPYesNo


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 LPYesNo
Crestwood Midstream Partners LPYesNo 
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 LPLarge accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting companyEmerging growth company
Crestwood Midstream Partners LPLarge accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting companyEmerging 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.
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 LPYesNo
Crestwood Midstream Partners LPYesNo
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (June 30, 2020).
Crestwood Equity Partners LP$0.7 billion
Crestwood Midstream Partners LPNaN
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date (February 12, 2021).
Crestwood Equity Partners LP$22.31 per common unit74,306,787
Crestwood Midstream Partners LPNoneNaN

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the following documents are incorporated by reference into the indicated parts of this report:
Crestwood Equity Partners LPNone
Crestwood Midstream Partners LPNone
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


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GLOSSARY

The terms below are common to our industry and used throughout this report.
/dper day
AODArea of dedication, which means the acreage dedicated to a company by an oil and/or natural gas producer under one or more contracts.
ASUAccounting Standards Update
Barrels (Bbls)One barrel of petroleum products equal to 42 U.S. gallons.
Base gasA 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.
BcfOne billion cubic feet of natural gas. A standard volume measure of natural gas products.
CycleA complete withdrawal and injection of working gas. Cycling refers to the process of completing one cycle.
EPAEnvironmental Protection Agency
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
GAAPGenerally Accepted Accounting Principles
Gas storage capacityThe 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.
HPHorsepower
HubGeographic location of a storage facility and multiple pipeline interconnections
Hub servicesWith 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 rateThe rate at which a customer is permitted to inject natural gas into a natural gas storage facility.
MBblsOne thousand barrels
MMBblsOne million barrels
MMcfOne million cubic feet of natural gas
Natural gasA gaseous mixture of hydrocarbon compounds, primarily methane together with varying quantities of ethane, propane, butane and other gases.
Natural Gas ActFederal 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).
NYSENew York Stock Exchange
SECSecurities and Exchange Commission
Withdrawal rateThe rate at which a customer is permitted to withdraw gas from a natural gas storage facility.
Working gasNatural 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 capacitySee gas storage capacity (above).

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FORWARD-LOOKING INFORMATION

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;
outbreak of illness, pandemic or any other public health crisis, including the COVID-19 pandemic;
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;
the availability of storage for hydrocarbons;
the ability of members of the Organization of Petroleum Exporting Countries (OPEC) and other oil-producing countries to agree and maintain oil price and production controls;
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;
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.

Additional discussion of factors that may affect our forward-looking statements appear elsewhere in this report, including Part I, Item 1A. Risk Factors and Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations. When considering forward-looking statements, you should keep in mind the factors described in this section and the other sections referenced above. These factors could cause our actual results to differ materially from those contained in any forward-looking statement. Except as required by applicable laws, we do not intend to update these forward-looking statements and information.

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SUMMARY RISK FACTORS

Our business is subject to varying degrees of risk and uncertainty. Investors should consider the risks and uncertainties summarized below, as well as the risks and uncertainties discussed in Part I, Item 1A. Risk Factors of this Annual Report on Form 10-K. Additional risks not presently known to us or that we currently deem immaterial may also affect us. If any of these risks occur, our business, financial condition or results of operations could be materially and adversely affected.

Our business is subject to the following principal risks and uncertainties:
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.
The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.
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 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 growth projects we complete may not perform as anticipated.
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.
A substantial portion of our revenue is derived from our operations in the Bakken shale, and due to such geographic concentration, adverse developments in the Bakken could impact our financial condition and results of operations.
Our gathering and processing operations depend, in part, on drilling and production decisions of others.
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.
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.
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.
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.
Changes in future business conditions could cause our long-lived assets and goodwill to become impaired, and our financial condition and results of operations could suffer if we record future impairments of long-lived assets and goodwill.
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.
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.
A change of control could result in us facing substantial repayment obligations under our revolving credit facility and indentures governing our senior notes.
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.
We operate joint ventures that may limit our operational flexibility.
We may not be able to renew or replace expiring contracts.
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.
Risks Related to Regulatory Matters
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.
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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 operations are subject to compliance with environmental and operational health and safety laws and regulations that may expose us to significant costs and liabilities.
Risks Related to our Tax Matters
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 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.
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.
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.
Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
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.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
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.
Risks Inherent to an Investment in our Equity
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.
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.
We may issue additional common units without common unitholder approval, which would dilute existing common unit holder ownership interests.
Unitholders have less ability to elect or remove management than holders of common stock in a corporation.
Common unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.
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.
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.
The control of our general partner may be transferred to a third party without unitholder consent.
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.
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
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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, 2020.

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 NGL, crude oil, natural gas and produced water gathering, processing, storage, disposal 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, we have equity investments in joint ventures through which we operate certain of their respective assets.


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Ownership Structure

We conduct our operations and own our operating assets through subsidiaries and joint ventures. The diagram below reflects a simplified version of our ownership structure as of December 31, 2020:
ceqp-20201231_g1.jpg

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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 Segment

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

Below is a summary of our gathering and processing operating assets, including those of our joint venture:

natural gas facilities with approximately 2.9 Bcf/d of gathering capacity and 1.2 Bcf/d of processing capacity;
crude oil facilities with approximately 150,000 Bbls/d of gathering capacity and 266,000 Bbls of storage capacity; and
produced water facilities with approximately 180,000 Bbls/d of gathering and disposal capacity.

The table below details certain information about our G&P operations (including our equity investment and its operations) as of December 31, 2020:

Shale Play
(State)
CountiesPipeline (Miles)Gathering Capacity2020 Average Gathering VolumesCompression (HP)Number of In-Service Processing PlantsProcessing Capacity
(MMcf/d)
Gross
Acreage Dedication
Bakken
North Dakota
McKenzie and Dunn
796(1)
150 MMcf/d - natural gas gathering
150 MBbls/d - crude oil gathering
120 MBbls/d - produced water gathering and disposal
 118 MMcf/d - natural gas gathering
113 MBbls/d - crude oil gathering
89 MBbls/d - produced water gathering and disposal
82,4802150150,000
Powder River Basin
Wyoming
Converse328252 MMcf/d100 MMcf/d85,6882345272,000
Marcellus
West Virginia
Harrison and Doddridge72875 MMcf/d 256 MMcf/d130,180140,000
Barnett
Texas
Hood, Somervell, Tarrant, Johnson and Denton441925 MMcf/d222 MMcf/d153,4651425140,000
Delaware Permian (2)
New Mexico/Texas
Eddy (New Mexico) Loving, Reeves, Ward and Culberson (Texas)
311(3)
650 MMcf/d - natural gas gathering
60 MBbls/d - produced water gathering and disposal
194 MMcf/d - natural gas gathering
34 MBbls/d - produced water gathering and disposal
78,180(4)
2255329,000

(1)Consists of 305 miles of natural gas gathering pipeline, 202 miles of crude oil gathering pipeline, and 289 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)Consists of 297 miles of natural gas gathering pipeline and 14 miles of produced water gathering pipeline.
(4)Includes 45,000 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.

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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 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’s, 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.  In addition, the Arrow system has 266,000 Bbls of crude oil working storage capacity and multiple pipeline take-away outlets, salt water disposal wells and a natural gas processing facility (Bear Den). The Bear Den facility and associated pipelines at the Arrow system 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

We own and operate the Jackalope gas gathering system in Converse County, Wyoming, which connects to 153 well pads and is supported by a long-term gathering and processing agreement with Chesapeake Energy Corporation (Chesapeake) that has a remaining contract term of 16 years. Effective February 1, 2021, the gas gathering and processing agreement was amended to revise its rates and provide minimum revenue guarantees for three years.

Marcellus

We own and operate natural gas gathering and compression systems in Harrison and Doddridge Counties, West Virginia. These systems consist of 72 miles of low pressure gathering lines and nine compression and dehydration stations with 130,180 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. The agreement associated with our Victoria compressor station provides for a minimum volume commitment of approximately 50% of the throughput capacity through April 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.

Delaware Permian

Our gathering and processing segment includes our 50% equity interest in Crestwood Permian, a joint venture between Crestwood Infrastructure Holdings LLC (Crestwood Infrastructure), our wholly-owned subsidiary, and an affiliate of First Reserve. Crestwood Permian owns (i) 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; (ii) a 200 MMcf/d natural gas processing facility in Orla, Texas, (the Orla plant); (iii) the Orla Express Pipeline, a 33 mile, 20-inch high pressure line connecting the existing Willow Lake system with the Orla plant; and (iv) a produced water gathering and disposal system capable of handling 60,000 Bbls/d of produced water in Culberson and Reeves Counties, Texas.

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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.

Crestwood Permian 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 owns the Nautilus gathering system which includes 94 receipt point meters, 156 miles of pipeline, a 41-mile high pressure header system, 45,000 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. 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. In addition, 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 table below summarizes certain contract information of our G&P operations (including our equity investment and its operations) as of December 31, 2020:

Shale Play
Type of Contracts(1)
Weighted Average Remaining Contract Terms (in years)Major Customers
BakkenMixed9Devon Energy Corporation, Rimrock Oil & Gas, LP, XTO Energy Inc., Bruin E&P Partners, LLC
Powder River BasinFixed-fee16Chesapeake
MarcellusFixed-fee11Antero Resources Corporation
BarnettMixed5Blackbeard Operating, LLC, Newark Acquisition I L.P.
Delaware PermianFixed-fee13SWEPI, Mewbourne Oil Company (Mewbourne)
Mixed3Mewbourne, Concho Resources

(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, disposal, 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 remaining terms ranging from 1-16 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.

Storage and Transportation Segment

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, three natural gas pipeline systems and crude oil facilities.

Below is a summary of our storage and transportation operating assets, including those of our joint ventures:

natural gas facilities with approximately 75.8 Bcf of certificated working storage capacity and 1.8 Bcf/d of operational transportation capacity; and
crude oil facilities with approximately 1.6 MMBbls of storage capacity and 180,000 Bbls/d of rail loading capacity.

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COLT Hub

The COLT Hub consists of our integrated crude oil loading, storage and pipeline terminal located in the heart of the Bakken and Three Forks Shale oil-producing areas in Williams County, North Dakota. The COLT Hub has approximately 1.2 MMBbls of crude oil storage capacity and 160,000 Bbls/d of rail loading capacity. 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 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.

Northeast Storage Facilities

Our storage and transportation segment includes our 50% equity interest in Stagecoach Gas Services LLC (Stagecoach Gas), a joint venture between our wholly-owned subsidiary, Crestwood Pipeline and Storage Northeast LLC (Crestwood Northeast) and Con Edison Gas Pipeline and Storage Northeast, LLC, a wholly-owned subsidiary of Consolidated Edison, Inc. (Consolidated Edison).

The Stagecoach Gas joint venture owns and operates four natural gas storage facilities located in New York and Pennsylvania near major shale plays and demand markets. The Stagecoach Gas natural gas storage facilities have low maintenance costs, long useful lives, 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. The Stagecoach storage facility also connects to UGI Energy Services, LLC’s (UGI) Sunbury Pipeline and Transcontinental Gas Pipe Line Corporation’s (Transco) Leidy Line through the MARC I Pipeline.

Thomas Corners - a FERC-certificated 7.0 Bcf single-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 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 Transmission Inc.’s (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), a joint venture between CMLP Tres Manager LLC, our wholly-owned subsidiary, and Brookfield Infrastructure Group which owns the remaining 49.99% equity interest in Tres Holdings. 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, 24-inch diameter header system (including a 38-mile dual 24-inch diameter system, a 20-mile north pipeline lateral and an approximate 5-mile south pipeline lateral) interconnects with 12 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan’s Houston central processing plant.

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The table below provides additional information about our S&T equity investments’ natural gas storage facilities as of December 31, 2020:
Storage Facility /
Location
Certificated Working Gas Storage Capacity
(Bcf)
Certificated Maximum Injection Rate
(MMcf/d)
Certificated Maximum Withdrawal Rate
(MMcf/d)
Stagecoach
Tioga County, NY;
Bradford County, PA
26.2250500
Thomas Corners
Steuben County, NY
7.070140
Seneca Lake
Schuyler County, NY
1.573145
Steuben
Steuben County, NY
6.23060
Northeast Storage Total40.9423845
Tres Palacios34.91,0002,500
Total75.81,4233,345

Stagecoach Gas Transportation Facilities

Stagecoach Gas owns three natural gas pipeline systems located in New York and Pennsylvania with an aggregate operational transportation capacity of 1.8 Bcf/d. 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 intrastate 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.

PRBIC Rail Loading Facility

Our storage and transportation segment includes our 50.01% equity interest in Powder River Basin Industrial Complex, LLC (PRBIC), a joint venture between Crestwood Crude Logistics LLC, our wholly-owned subsidiary and Twin Eagle Resources Management LLC (Twin Eagle). PRBIC owns an integrated crude oil loading, storage and pipeline terminal located in Douglas County, Wyoming. PRBIC, which is operated by Twin Eagle, sources crude oil production from Powder River Basin producers. The PRBIC facility 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, L.P.’s (Plains) Rocky Mountain Pipeline system.

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The table below summarizes certain contract information about our S&T operations (including our equity investments) as of December 31, 2020:
Facility
Type of Contracts(1)
Contract VolumesWeighted Average Remaining Contract TermsMajor Customers
COLTFirm
307 MBbls/d(2)
Less than 1 yearBritish Petroleum (BP), Flint Hills Resources, Sunoco Logistics
Stagecoach Gas:
North-South FacilitiesFirm608 MMcf/d2 yearsSouthwestern Energy, Consolidated Edison
MARC I PipelineFirm1,101 MMcf/d1 yearChesapeake, Alta Energy Marketing, Equinor Natural Gas LLC
Twin Tier PipelineFirm30 MMcf/dLess than 1 yearNY State Electric & Gas Corp
StagecoachFirm21.6 Bcf2 yearsConsolidated Edison, New Jersey Natural Gas, Morgan Stanley Capital Group
Thomas CornersFirm6.2 BcfLess than 1 yearTenaska Gas Storage, LLC (Tenaska), Castleton Commodities International, LLC, DXT Commodities, Vitol
Seneca LakeFirm1.5 BcfLess than 1 yearSequent Energy Management (Sequent), NY State Electric & Gas Corp, DTE Energy Trading
SteubenFirm5.2 Bcf1 yearSequent, Tenaska
Tres PalaciosFirm30.5 Bcf1 yearHartree Partners LP, BP
PRBICFirm230MBbls1 yearSinclair Oil Corporation

(1)Firm contracts represent take-or-pay contracts whereby our customers agree to pay for a specified amount of storage or transportation capacity, whether or not the capacity is utilized.
(2)Consists of 22 MBbls/d of rail loading and transportation volumes and 285 MBbls/d of storage volumes.

The cash flows from our S&T operations are predominantly fee-based under contracts with remaining terms ranging from 1-5 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 have 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 Segment

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, terminals and contracted storage and pipeline capacity to provide integrated supply and logistics solutions to producers, refiners and other customers.

Our marketing, supply and logistics operating assets include:

A fleet of rail and rolling stock with approximately 1.6 MMBbls/d of NGL pipeline, terminal and transportation capacity, which also includes our rail-to-truck terminals located in Michigan, Indiana, Ohio, New Hampshire, Pennsylvania, New Jersey, New York, Rhode Island, North Carolina, South Carolina and Mississippi. We provide hauling services to customers primarily in the Central Mid-Continent and East Coast of the United States.
Storage facilities with approximately 10 MMBbls of NGL storage capacity. Our storage facilities are located in Pennsylvania, South Carolina, Mississippi, Michigan, New York and Indiana, with receipts and deliveries that are supported by both rail cars and third party pipelines, allowing truck and rail access to local markets.

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.

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Major Customers

For the years ended December 31, 2020 and 2018, no customer accounted for more than 10% of our total consolidated revenues. For the year ended December 31, 2019, British Petroleum and its affiliates accounted for approximately 10% of our total consolidated revenues.

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.

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 under the Hazardous Liquid Pipeline Safety Act of 1979, as amended (HLPSA).

These federal statutes and PHMSA 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 to comprehensively evaluate certain high risk areas, known as high consequence areas (HCAs), high-population areas (also known as moderate consequence areas (MCAs), as well as Class 3 and Class 4 areas, which are determined by specific population densities near our pipeline), certain drinking water sources and unusually sensitive ecological areas, along our
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pipelines, and take additional safety measures to protect people and property in these areas. Integrity management programs require more frequent inspections and other preventative measures to ensure pipeline safety in HCAs and MCAs.

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.

Legislation in the past decade has resulted in more stringent mandates for pipeline safety and has charged PHMSA with developing and adopting regulations that impose increased pipeline safety requirements on pipeline operators. In particular, the NGPSA and HLPSA were amended by the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (2011 Pipeline Safety Act) and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Pipeline Safety Act). 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. The 2016 Pipeline Safety Act extended PHMSA’s statutory mandate through September 2019 and, among other things, required PHMSA to complete certain of its outstanding mandates under the 2011 Pipeline Safety Act and develop new safety standards for natural gas storage facilities. More recently, in December 2020, Congress passed the Fiscal Year 2021 Omnibus Appropriations Bill, made effective on December 27, 2020, pursuant to which Congress adopted the “Protecting Our Infrastructure of Pipelines and Enhancing Safety (PIPES) Act of 2020.” The PIPES Act of 2020 reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several proposed regulatory actions that among, other things, will require operators of non-rural gas gathering lines and new and existing transmission and distribution pipeline facilities to conduct certain leak detection and repair programs and to require facility inspection and maintenance plans to align with those regulations.

Several rulemakings were adopted or made effective during 2020, which further impose added pipeline safety requirements on operators.

Natural Gas Storage Facilities. In February 2020, PHMSA published a final rule that amended the minimum safety issues applicable to natural gas storage facilities, including wells, wellbore tubing and casing. The final rule replaces an interim rule first adopted by PHMSA in December 2016 that was subject to a series of delays in full implementation between 2016 and 2019 as PHMSA reconsidered aspects of the rulemaking. The February 2020 rule was further amended in July 2020 to include certain applicable reporting requirements that had been deleted when the February 2020 rule was published.
Gas Mega Rulemakings. In October 2019, PHMSA published the first of three expected final rules relating to new or more stringent requirements for certain natural gas pipelines that had originally been proposed by the agency in 2016 as a single rulemaking, known as the “Gas Mega Rule.” The October 2019 final rule, made effective in July 2020, imposes numerous requirements, including maximum allowable operating pressure (MAOP) reconfirmation through re-verification of all historical records for pipelines in service, which re-certification process may require natural gas pipelines installed before 1970 (previously excluded from certain pressure testing obligations) to be pressure tested, the periodic assessment of additional pipeline mileage outside of HCAs (that is, in MCAs as well as Class 3 and Class 4 areas), the reporting of exceedances of MAOP and the consideration of seismicity as a risk factor in integrity management. Additional amendments to this October 2019 final rule relating to recordkeeping for gas transmission lines were published by PHMSA in July 2020. The remaining rulemakings comprising the former Gas Mega Rule proposal have not yet been published, and we cannot predict when they will be finalized; however, they are expected to include revised pipeline repair criteria as well as more stringent corrosion control requirements.
Hazardous Liquids Rulemaking. In October 2019, PHMSA published a final rule, made effective in July 2020, 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 an HCA. Additionally, this final rule requires all hazardous liquid pipelines in or affecting an HCA to be capable of accommodating in line inspection tools within a 20-year period. Moreover, this final rule extends annual, accident, and safety-related conditional reporting requirements to hazardous liquid gravity lines and certain gathering lines and 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 the operational and financial impact related to one or more of these laws and PHMSA rules. The safety enhancement requirements and other provisions of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act, and the PIPES Act of 2020, as well as any implementation of PHMSA regulations thereunder, or any issuance or reinterpretation of guidance
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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.

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.

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), the New York State Department of Environmental Conservation (NYSDEC), Michigan Department of Environment, Great Lakes and Energy (EGLE) and the EPA have jurisdiction over the underground storage of NGLs and NGL related well drilling, well conversions and well plugging in Indiana, New York and Michigan, respectively. The INDNR regulates aspects of our Seymour facility, the NYSDEC and EPA regulate aspects of the Bath facility and the EGLE and EPA regulate aspects of our Alto facility. Additionally, NGL terminals have the potential to be subject to state and federal air compliance regulations. For example, the Pennsylvania Department of Environmental Protection (PADEP) and the EPA have
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jurisdiction over facilities with the potential to emit regulated air pollutants in Pennsylvania. The PADEP regulates those aspects of the Schaefferstown 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 our 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.

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
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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, 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 Recommended 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 represents 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.

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
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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 the 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, tribal, regional, state and local laws and regulations governing the discharge and emission of pollutants into the environment, environmental protection or occupational health and safety. These laws and regulations may impose significant obligations on our operations, including (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. 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 restrictions, delays or cancellations in permitting, development or expansion of projects and the issuance of injunctions restricting or prohibiting some or all of our activities.

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, disposers 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 that 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 and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;
The Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of substances into below-ground formations that may adversely affect drinking water sources;
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The National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments 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. States also adopt and implement their own environmental laws and regulations, which may be more stringent than federal requirements. 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, and during September 2019, we experienced two produced water releases totaling approximately 5,000 barrels. We are substantially complete with all remediation efforts related to these spills, have settled and paid all potential fines and penalties related to the 2015 water spills and we believe our remediation efforts are insurable events under our insurance policies.

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 under the Obama Administration issued a final rule under the Clean Air Act, making the National Ambient Air Quality Standard (NAAQS) for ground-level ozone more stringent. Since that time, the EPA has issued area designations with respect to ground-level ozone and final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone and, more recently, in August 2020, the EPA under the Trump Administration published notice of a proposed action that, upon conducting a periodic review of the ozone standards in accordance with Clean Air Act requirements, elected to retain the 2015 ozone NAAQS without revision on a going-forward basis. State implementation of the revised NAAQS could, among other things, require installation of new emission controls on some of our or our customers' equipment, resulting in longer permitting timelines, and could significantly increase our or our customers' capital expenditures and operating costs. Also, in 2015, the EPA and U.S. Army Corps of Engineers (Corps) under the Obama Administration released a final rule outlining federal jurisdictional reach under the Clean Water Act over waters of the United States, including wetlands; however, the 2015 rule was repealed by the EPA and the Corps under the Trump Administration in a final rule that became effective in December 2019 and they also published a final rule in April 2020 re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to federal regulation. The April 2020 final rule is subject to various pending legal challenges and it is expected that the Biden Administration may reconsider this final rule. To the extent that the EPA and the Corps under the Biden Administration revises the June 2020 final rule in a manner similar to or more stringent than the original 2015 final rule, or if any challenge to the June 2020 final rule is successful and the 2015 final rule or a revised rule again expands the scope of the Clean Water Act’s jurisdiction in areas where we or our customers conduct operations, such developments could delay, restrict or halt permitting or development of projects, result in longer permitting timelines, or increased compliance expenditures or mitigation costs for our and our customers’ operations, which may reduce the rate of production from operators.

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Human Capital

As of December 31, 2020, we had 731 full-time employees, 269 of which were general and administrative employees and 462 of which were operational employees. Our ability to attract, develop, retain and keep our employees safe is critical to the operational performance and future sustainability of our company.

We believe our ability to attract employees is significantly influenced by our efforts to create a culture founded on respect and collaboration, and our ability to value the diverse backgrounds, skills and contributions that our employees offer. In 2020, we continued to take steps to advance our commitment to Diversity and Inclusion (D&I) by developing a long-term D&I five-point plan with the key pillars of attracting talent for a diverse workforce, creating an inclusive and engaged workforce, focusing on sustainability and accountability, creating meaningful D&I-related partnerships, and building the future pipeline of employees with D&I in mind. In addition, we further advanced our D&I efforts by appointing a Chief Diversity Officer and participating in the CEO Action Pledge for Diversity and Inclusion during 2020.

We develop our employees through a comprehensive performance management program and through continuous training, especially as it relates to safety, operations, technology, human resources and ethics. 99.96% of our employees completed their assigned training in these areas during the year ended December 31, 2020.

We monitor our ability to retain our employees through our voluntary turnover rate (the percentage of employees who voluntarily leave our organization compared to our total employee population), which was 8% during the year ended December 31, 2020 compared to 11% during the year ended December 31, 2019.

We monitor our ability to keep our employees safe by setting company-wide goals each year as it relates to leading indicators (i.e., near miss reporting, timely completion of compliance tasks, setting individual safety goals) and lagging indicators (i.e., incident and injury rates). These safety metrics are included in the annual compensation of our executives and employees, which are described in more detail in Part III, Item 11. Executive Compensation under Annual Incentive Compensation.

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 impact natural gas demand domestically include the effects of the COVID-19 pandemic, the realization of potential liquefied natural gas exports and demand growth within the power generation market. Factors that impact crude oil demand include production cuts and freezes implemented by OPEC members and other large oil producers such as Russia. For example, during the first half of 2020, the combined effect of OPEC and Russia’s failure to agree on a plan to cut production of oil and related commodities, the outbreak of the COVID-19 pandemic and the shortage in available storage for hydrocarbons in the United States contributed to a sharp drop in prices for crude oil. While prices for oil have subsequently experienced more stability since then, we cannot predict what actions OPEC and other oil-producing countries will take in the future. 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, including the recent civil unrest within the United States related to the 2020 presidential election;
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;
outbreak of illness, pandemic or any other public health crisis, including the COVID-19 pandemic;
the availability of hydrocarbon storage;
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, reduced demand for energy, or otherwise, the demand for our services and the fees 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. For example, in response to low commodity prices experienced during early 2020, some of our customers reduced capital expenditures and curtailed production, which adversely affected our gathering and processing segment results. With West Texas Intermediate crude oil prices ranging from $46.31 to $66.24 per barrel in 2019 and from $63.27 to negative $36.98 per barrel in 2020, the sustainability of recent 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.

The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.

During 2020, the global and U.S. economy was negatively impacted by the COVID-19 pandemic, which disrupted global supply chains, reduced consumer activity, disrupted travel and created significant volatility and disruption of financial and
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commodity markets. The effects of the COVID-19 pandemic have resulted in a significant reduction in global demand for natural gas, NGLs and crude oil and a significant and persistent reduction in the market price of crude oil. As a result, many producers, including some of our customers, curtailed some of their short-term drilling and production activity during 2020, and reduced or slowed down their plans for future drilling and production activity. This decrease in activity has decreased the demand that certain of these customers had for our services in 2020, and may continue to impact demand for our services in the future if our customers continue to or further curtail drilling and production activity in the future.

The COVID-19 pandemic has also caused federal and local governments to implement measures to quarantine individuals and limit gatherings, which has impacted our workforce and the way we have traditionally conducted our business. In response, we have implemented preventative measures to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations. We have continued to follow modified business practices (including discontinuing non-essential business travel, implementing staggered work-from-home policies for employees who can execute their work remotely in order to reduce office density, and encouraging employees to adhere to local and regional social distancing recommendations) to support efforts to reduce the spread of COVID-19 and to conform to government restrictions and best practices encouraged by governmental and regulatory authorities. We also have promoted heightened awareness and vigilance, hygiene and more stringent cleaning protocols across our facilities and operations. We continue to evaluate and adjust these preventative measures, response plans and business practices with the evolving impacts of COVID-19. However, if COVID-19 were to impact a location where we have a high concentration of business and resources, our local workforce could be affected by such an occurrence or outbreak which could also significantly disrupt our operations and decrease our ability to provide gathering, processing, storage and transportation services to our customers.

The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations. There is uncertainty around the extent and duration of the disruption. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Additionally, the actions taken to contain the COVID-19 pandemic include actions implemented by governmental authorities, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns, all of which affect the demand for oil, natural gas and NGLs. Due to these factors, we expect to see continued volatility in commodity prices for the foreseeable future. These potential impacts, while uncertain, could adversely affect our operating results.

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

Our business strategy depends on our ability to provide increased services to our customers and develop growth projects that can be financed appropriately. We may be unable to complete successful, accretive growth projects for any of the following reasons, among others:
 
we fail to identify (or we are outbid for) attractive expansion or development projects or acquisition candidates that satisfy our economic and other criteria;
we fail to secure adequate customer commitments to use the facilities to be developed, expanded or acquired; or
we cannot obtain governmental approvals or other rights, licenses or consents needed to complete such projects or acquisitions on time or on budget, if at all.

The development and construction of gathering, processing, storage and transportation facilities involves numerous regulatory, environmental, safety, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. When we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular growth project. For instance, if we build a new gathering system, 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.

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

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 in the equity and debt securities of energy companies, as well as a negative impact on the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all. 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. Furthermore, these factors may be exacerbated by the impact of the COVID-19 pandemic and any responses to the pandemic by governmental authorities, the effects of which may be difficult to predict.

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

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

A substantial portion of our revenue is derived from our operations in the Bakken shale, and due to such geographic concentration, adverse developments in the Bakken could impact our financial condition and results of operations.

A significant portion of our revenue is derived from our operations in the Bakken shale. These operations accounted for approximately 51% of our total revenues, less of costs of product/services sold, for the year ended December 31, 2020. Due to this geographic concentration of our operations, adverse developments that affect customers, suppliers or operations in the Bakken, such as catastrophic events or weather, health pandemics and changes in supply or demand of crude oil, natural gas and related commodities that impact regional commodity prices and availability of infrastructure, could have a significantly greater impact on our financial condition and results of operations than if we maintained operations in more diverse locations.

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 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 and fluctuations thereof; (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; (vi) the availability of drilling rigs and other development services; (vii) the availability of storage of crude oil and other commodities; and (viii) the impact of illness, pandemics or any other public health crisis, including the COVID-19 pandemic. As it relates to certain drilling methods, including hydraulic fracturing, the EPA has completed a study of potential adverse impacts that those drilling methods and fracturing activities 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. Moreover, the Biden Administration may seek to pursue legislation, executive actions or regulatory initiatives that restrict hydraulic fracturing activities on federal lands. Drilling and production activity generally decreases as commodity prices decrease (such as what could be experienced with the decline in commodity prices during 2020, as further described in “Our business depends on hydrocarbon supply and demand fundamentals, which can be adversely affected by numerous factors outside of our control”) 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. For example, due to the sharp decreases in commodity prices experienced in 2020, many of our customers announced reductions in their estimated capital expenditures for 2021 and beyond. 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
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systems is less than anticipated and we are unable to secure additional sources of natural gas or crude oil, it could have a material adverse effect on our business, results of operations and financial condition.

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

Many of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flows from operations, the incurrence of debt or the issuance of equity. The combination of the reduction of cash flows resulting from declines in commodity prices (such as experienced during 2020), 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 or crude oil 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 our long-lived assets and goodwill to become impaired, and our financial condition and results of operations could suffer if we record future impairments 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
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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.

During the year ended December 31, 2020, we determined that the goodwill associated with our Powder River Basin reporting unit should be fully impaired, and accordingly recorded an $80.3 million impairment of its goodwill.

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 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. Furthermore, the recent depressed commodity prices environment may cause consolidation within the energy industry, leading to combined companies with greater resources. Our competitors may expand or construct infrastructure that creates additional competition for the services we provide to customers. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions.

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

We had approximately $2.5 billion of long-term debt outstanding as of December 31, 2020. 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. For example, a change of control of Crestwood Equity’s general partner may occur if our parent, Crestwood Holdings, became unable to service its debt and an event of default occurred under the documents governing its debt. If our Board of Directors reduces the level of distributions to our common unitholders in future quarters as a consequence of the recent significant decline in commodity prices or for other reasons, the ability of our parent to service its debt may be adversely affected. In the event our outstanding indebtedness became due, 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
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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 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
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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, 2020, the weighted average remaining term of our consolidated portfolio of natural gas gathering contracts is approximately 10 years, and our consolidated portfolio of crude oil gathering contracts is approximately nine 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 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
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 potential future water spills could subject 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.
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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 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.

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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.

Increasing attention to environmental, social and governance (ESG) matters may impact our business.

Organizations that provide information to investors on corporate governance, climate change, health and safety and other ESG related factors have developed ratings processes for evaluating companies on their approach to ESG matters. Such ratings are used by some investors to inform their investment decisions. Unfavorable ESG reviews of our company or industry by third parties may lead to increased negative investor sentiment toward us or our customers and to the diversion of investment to other industries which could have a negative impact on our unit price and/or our access to and costs of capital.

Risks Related to Regulatory Matters

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’s 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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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. The FERC has not taken further action since the Certificate Policy Statement NOI was issued. 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.

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. These requirements may take the form of laws, regulations, executive actions and various other legal initiatives. See Item 1. Business, “Regulation -Environmental and Occupational Safety and Health Matters” for a further discussion on these matters. Compliance with these regulations and other regulatory initiatives or any other new environmental laws and regulations could, among other things, require us or our customers to install new or modified emission controls on equipment or processes and incur significantly increased capital or operating expenditures and operating delays, restrictions or cancellations with respect to our operations, which costs may be significant. Additionally, one or more of these developments that impact our customers involved in oil and natural gas exploration and production could reduce demand for our services. These developments could have a material adverse effect on our business, results of operations and financial condition.
 
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Our and our customers’ operations are subject to various risks arising out of the threat of climate change that could result in increased costs, limit the areas in which oil and natural gas production may occur 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 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 but with President Biden taking office in January 2021, he may pursue new climate change legislation, executive actions or other regulatory initiatives to limit GHG emissions. Moreover, 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 construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources, including certain oil and natural gas production, processing, transmission, storage and distribution facilities, and impose new standards reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. In recent years, there has been considerable uncertainty surrounding regulation of methane emissions, as the EPA under the Obama Administration published final regulations under the Clean Air Act establishing new performance standards for methane in 2016, but since that time the EPA has undertaken several measures, including issuing rules in 2020, to delay implementation of the methane standards. Various states and industry and environmental groups are separately challenging both the original 2016 standards and the EPA’s September 2020 final rule. Notwithstanding the current court challenges, the EPA under the Biden Administration may reconsider the September 2020 final rule, which could result in more stringent methane emission rulemaking. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored Paris Agreement, which is a non-binding agreement for nations to limit their greenhouse gas emissions through individually-determined reduction goals every five years after 2020. While the United States withdrew from the Paris Agreement effective November 4, 2020, President Biden recommitted the United States to the Paris Agreement on January 20, 2021.
 
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 addition to recommitting to the Paris Agreement, the Biden Administration indicated that they intend to undertake other actions that could adversely affect the oil and gas industry include limiting hydraulic fracturing by banning new oil and gas permitting on federal lands and waters, limiting new leasing of federal lands or offshore waters for oil and gas exploration and production activities, potentially eliminating certain tax rules (referred to as subsidies) that benefit the oil and gas industry, and imposing restrictions on pipeline infrastructure. Litigation risks are also increasing as a number of cities, local governments and other plaintiffs have sought to bring lawsuits 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 Paris Agreement, and foreign citizenry concerned about climate change not to provide funding for fossil fuel producers.
 
The adoption and implementation of new or more stringent international, federal or state executive actions, legislation, regulations or regulatory initiatives that impose more stringent standards for GHG emissions from the oil and natural gas sector or otherwise restrict the areas in which this sector may produce oil and natural gas or generate GHG emissions 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
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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 HCAs, MCAs, Class 3 and 4 areas, as well as areas unusually sensitive to environmental damage and commercially navigable waterways. 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 HCA, MCA or Class 3 and 4 area;
maintain processes for data collection, integration and analysis;
repair and remediate pipelines as necessary; and
implement preventive and mitigating actions.

Additionally, certain states where we conduct operations, including New Mexico, North Dakota, West Virginia and Wyoming, 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. See Item 1. Business, “Regulation -Environmental and Occupational Safety and Health Matters” for a further discussion on pipeline safety matters.

Risks Inherent in an Investment in Our Equity

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;
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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.

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.
 
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.
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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.

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.

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, 2020, 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 Crestwood 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
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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 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, Crestwood Holdings LP, from transferring its ownership interest in our general partner to a third party. Additionally, Crestwood 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
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partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units. As of December 31, 2020, Crestwood Holdings and its affiliates owned approximately 24% of our common units.

Risks Related to our Tax Matters

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. Members of Congress have frequently 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, including proposals that would eliminate our ability to qualify for partnership tax treatment.
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 or
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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. Unitholders are urged to consult with their own tax advisors 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 our unitholders 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 our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those units. Because distributions in excess of our unitholders allocable share of our total net taxable income result in a reduction in their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. In addition, because the amount realized includes a unitholder’s
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share of our nonrecourse liabilities, if they sell their units they may incur a tax liability in excess of the amount of cash received 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, our unitholders may recognize both ordinary income and capital loss from the sale of their units if the amount realized on a sale of their units is less than their 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 our unitholders sell their units, they may recognize ordinary income from our allocations of income and gain to them 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 (as modified by the Coronovirus Aid, Relief and Economic Security 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 a certain percentage 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. 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. 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 non-U.S. person. While the determination of a partner’s amount realized generally includes any decrease of a partner’s share of the partnership’s liabilities, recently issued Treasury regulations provide that the amount realized on a transfer of an interest in a publicly traded partnership, such as our units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2022. For a transfer of interests in a publicly traded partnership that is effected through a broker on or after January 1, 2022, the obligation to withhold is imposed on the transferor’s broker.
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 our unitholders. 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 our unitholders’ tax returns.
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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, they 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 non-U.S. 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 non-U.S. 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 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.


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Item 1B. Unresolved Staff Comments

None.


Item 2. Properties

A description of our properties is included in Item 1. Business, and is incorporated herein by reference. We also lease office space for our corporate offices in Houston, Texas and 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 10, 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 12, 2021, was $22.31. As of that date, Crestwood Equity had 74,306,787 common units issued and outstanding, which were held by 219 unitholders of record.

Issuer Purchases of Equity Securities

For the year ended December 31, 2020, we relinquished 581,608 common units to cover payroll taxes upon the vesting of restricted and performance 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, 2020: 
Plan categoryNumber 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— $— 2,193,965 
Total— $— 2,193,965 


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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, 2020 and balance sheet data as of December 31, 2020 and 2019 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, 2017 and the balance sheet data as of December 31, 2018, 2017 and 2016 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, 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 realignment and restructuring of our operations, 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,
 20202019201820172016
(in millions, except per unit data)
Statement of Income Data:
Revenues$2,254.3 $3,181.9 $3,654.1 $3,880.9 $2,520.5 
Operating income (loss)$86.8 $402.2 $113.5 $(79.4)$(108.7)
Income (loss) before income taxes$(14.9)$320.2 $67.1 $(167.4)$(191.8)
Net income (loss)$(15.3)$319.9 $67.0 $(166.6)$(192.1)
Net income (loss) attributable to Crestwood Equity Partners LP$(56.1)$285.1 $50.8 $(191.9)$(216.3)
Performance Measures:
Diluted net income (loss) per limited partner unit:$(1.59)$2.93 $(0.13)$(3.64)$(3.55)
Distributions declared per limited partner unit(1)
$2.50 $2.425 $2.40 $2.40 $3.175 
Other Financial Data:
EBITDA (unaudited)
$356.0 $631.4 $335.9 $161.4 $152.9 
Adjusted EBITDA (unaudited)
$580.3 $526.5 $420.1 $395.4 $455.6 
Net cash provided by operating activities$408.1 $420.4 $253.6 $255.9 $346.1 
Net cash provided by (used in) investing activities$(273.3)$(943.7)$(241.2)$38.7 $867.2 
Net cash provided by (used in) financing activities$(146.5)$531.8 $3.5 $(294.9)$(1,212.2)
Balance Sheet Data:
Property, plant and equipment, net$2,917.1 $2,909.1 $2,029.7 $1,820.8 $2,097.6 
Total assets$5,243.7 $5,349.3 $4,294.5 $4,284.9 $4,448.9 
Total debt, including current portion$2,484.0 $2,328.5 $1,753.3 $1,492.2 $1,523.7 
Long-term liabilities(2)
$294.0 $304.2 $176.2 $108.0 $49.9 
Interest of non-controlling partner in subsidiary(3)
$432.7 $426.2 $— $— $— 
Partners’ capital$1,655.4 $1,932.8 $2,033.8 $2,180.5 $2,539.0 

(1)Reported amounts include the fourth quarter distributions, which are paid in the first quarter of the subsequent year.
(2)Includes all long-term liabilities, other than debt which is presented separately in the table.
(3)Reflected in partners’ capital at December 31, 2018, 2017 and 2016. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 12 for a further discussion of our interest of non-controlling partner in subsidiary.



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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, and Part I, Item 1. Business - Assets.

A comparative discussion of our 2019 operating results to our 2018 operating results can be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K for the year ended December 31, 2019 filed with the SEC on February 21, 2020.

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, disposal and transportation assets in the most prolific shale plays across the United States.

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. 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.
Our financial statements reflect three operating and reporting segments: (i) gathering and processing; (ii) storage and transportation; and (iii) marketing, supply and logistics. 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 provide natural gas, crude oil and produced water gathering, compression, treating, processing and disposal services to producers in multiple unconventional resource plays in some of the largest shale plays in the United States in which we have established footprints in the “core of the core” areas (Bakken, Powder River Basin, Marcellus, Barnett and Delaware Permian).

Storage and Transportation. Our S&T operations provide crude oil and natural gas storage and transportation services to producers, utilities and other customers and consists 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 NGL, crude oil and natural gas marketing and logistics operations, and NGL storage, terminal and transportation (including rail, truck and pipeline) assets which provide integrated supply and logistics solutions to producers, refiners and other customers.

Outlook and Trends

Our business objective is to create long-term value for our unitholders. We expect to create value for our investors by generating stable operating margins and improving cash flows from our diversified midstream operations by prudently financing investments in our assets and expansions of our portfolio, maximizing throughput and optimizing services on our assets, and effectively controlling our capital expenditures, operating and administrative costs.
During 2020, crude oil and other commodity prices decreased significantly due primarily to decreases in energy demand as a result of the COVID-19 pandemic and actions taken by OPEC, Russia and the United States and other oil-producing countries related to the over-supply of oil. The resulting low commodity price environment adversely impacted U.S. producers and other companies in the energy industry. Despite the recent decline in commodity prices and resulting market conditions, our long-term business strategy has not changed. We have, however, implemented a number of adjustments to our operations and financial strategies in response to these market conditions, including (i) substantially reducing capital expenditures in response to lower development activity by our gathering and processing customers; (ii) realigning our organization to reduce operating and administrative expenses; (iii) engaging with our customers to maintain volumes across our asset portfolio; (iv) optimizing our storage, transportation and marketing assets to take advantage of regional commodity price volatility; (v) acquiring
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businesses that synergize with our existing operations and disposing of other non-core businesses; and (vi) evaluating our debt and equity structure to preserve liquidity and ensure balance sheet strength during this period of uncertainty in the energy and financial markets. Given our efforts over the past few years to improve the partnership’s competitive position in the businesses we operate, manage costs and improve margins, create a stronger balance sheet and implement new operating standards consistent with our Environmental, Social and Governance program, we believe the Company is well positioned to execute its business plan and weather current market conditions.
Business Highlights

Below is a discussion of events that highlight our core business activities during the year ended December 31, 2020. 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 completed several capital projects that expanded capacity on our natural gas gathering system, and also expanded capacity on our produced water gathering system while replacing several miles of water gathering pipeline with pipe that is composed of higher capacity material that is more suitable for the environment and climate conditions in the Bakken. We believe that the expansion of our Arrow facilities, including the placing in service of the Bear Den II processing plant in late 2019, will allow us to provide greater flow assurance to our producer customers, reduce the flaring of natural gas experienced by producers, and further our commitment to sustainability and environmental stewardship on the Fort Berthold Indian Reservation.

In July 2020, a U.S. District Court (District Court) ordered the Dakota Access Pipeline (DAPL) to cease operation based on an alleged procedural permitting failure. On August 5, 2020, the U.S. Court of Appeals for the District of Columbia Circuit (D.C. Circuit) stayed the DAPL shutdown, and set an expedited briefing schedule to determine the merits of the District Court’s decision. The D.C. Circuit issued an opinion on January 26, 2021 which upheld the District Court’s decision on the merits, but did not rule on whether DAPL should be prohibited from continued operation. The plaintiffs have sought another injunction against DAPL’s continued operation, which has been fully briefed before the District Court. After the D.C. Circuit’s January 26, 2021 decision, the District Court scheduled a status conference to be held on April 9, 2021 to determine whether the Army Corps will allow DAPL to continue to operate without a valid easement, and while the Army Corps prepare an Environmental Impact Statement. We continue to monitor these legal proceedings, as well as the Army Corps renewed permitting efforts. We are actively engaged with our producer customers on the Arrow system to ensure downstream market access for their crude oil volumes. The Arrow gathering system currently connects to the DAPL, Hiland and Tesoro pipelines, providing significant downstream delivery capacity for our Arrow customers. Additionally, we can transport Arrow crude volumes to our COLT Hub facility by pipeline or truck, which mitigates the impact to our producers with the ability to access multiple markets out of the basin.

Powder River Basin. In the Powder River Basin, we completed the 200 MMcf/d expansion of our processing capacity at our Bucking Horse facility, which increased our processing capacity to 345 MMcf/d. In addition, we placed in-service two compressor stations with 18,750 horsepower and significantly expanded the gas gathering system to connect numerous wells that had been drilled and completed by our producer customers.

In June 2020, Chesapeake, our customer in the Powder River Basin and northeast Marcellus, filed for protection under Chapter 11 of the U.S. Bankruptcy Code. In December 2020, Chesapeake filed a motion in the United States Bankruptcy Court for the Southern District of Texas for authorization to enter into, assume and make all payments under an amended and restated gas gathering and processing contract with us, and Chesapeake emerged from bankruptcy in February 2021. Chesapeake is current on all amounts due to us.

Delaware Permian. In the Delaware Permian, through our Crestwood Permian joint venture, we are expanding our gas gathering systems and continue to optimize processing volumes at our Orla processing plant. Additionally, during 2020, we completed construction and commenced operations of a produced water gathering and salt water disposal system pursuant to an agreement with a large integrated producer in Culberson and Reeves Counties, Texas. The system capacity is 60 MBbls/d as of December 31, 2020 with plans to expand up to 120 MBbls/d based on producer activity.

Fayetteville Shale. On October 1, 2020, we sold our gathering systems in the Fayetteville Shale to a third party for approximately $23 million.

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Marketing, Supply and Logistics. In April 2020, we acquired several NGL storage and rail-to-truck terminals from Plains for approximately $162 million. These assets are complementary to our existing NGL assets, are located in high demand markets across the central and eastern United States and include 7 MMBbls of NGL storage and seven terminals.

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. 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.

During 2020, current and forward commodity prices significantly declined from their levels at December 31, 2019 due primarily to the decreases in energy demand as a result of the outbreak of the COVID-19 pandemic and actions taken by the OPEC, Russia, the United States and other oil-producing countries relating to the oversupply of oil. We believe that the decrease in commodity prices has had and will continue to have a negative impact on certain of our customers in our gathering and processing segment, which could adversely impact the financial performance of certain of the reporting units within those operations.

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.

We acquired our Powder River Basin reporting unit in April 2019, and during the year ended December 31, 2020, we fully impaired the goodwill associated with this reporting unit based on the impact that the decline in commodity prices has had on our producer customers in the Powder River Basin described above. At December 31, 2020, our goodwill consisted of approximately $45.9 million associated with our G&P Arrow reporting unit and $92.7 million associated with our MS&L NGL Marketing and Logistics reporting unit. 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
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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.

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 2020 and 2019, we recorded $3.1 million and $4.3 million of impairments of our property, plant and equipment primarily related to certain of our water gathering facilities in our Arrow operations, which is further discussed in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2. During 2018, we did not record any material impairments of our intangible assets and property, plant and equipment. During 2020, we sold our Fayetteville assets and recorded a loss on long-lived assets of approximately $19.9 million and during 2018, we sold our MS&L West Coast operations and recorded a loss on long-lived assets of approximately $26.9 million. For a further discussion of these assets sales, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.

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.

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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.

During 2020, current and forward commodity prices significantly declined from their levels at December 31, 2019 due primarily to the decreases in energy demand as a result of the outbreak of the COVID-19 pandemic and actions taken by the OPEC, Russia, the United States and other oil-producing countries related to the oversupply of oil. We currently anticipate that the decrease in commodity prices could have a negative impact on certain of our equity method investments’ customers, which could adversely impact the financial performance of certain of those investments. Although we currently anticipate that the decline in commodity prices has not decreased the fair value of our equity investments below their carrying value and any such decline would not be considered other than temporary, we continue to monitor our equity method investments (especially those with gathering and processing operations such as our Crestwood Permian equity method investment). If we receive additional negative information about market conditions or the intent of our equity method investments’ customers to curtail production in the future that negatively impacts the forecasted cash flows or discount rates utilized to determine the fair value of those investments, we could experience impairments to the carrying value of these 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. During 2020, we recorded a $4.5 million reduction to the equity earnings from our PRBIC equity method investment as a result of us recording our proportionate share of a long-lived asset impairment recorded by the equity method investee. The carrying value of our PRBIC equity method investment was $3.6 million at December 31, 2020. 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). Stagecoach Gas concluded that its goodwill was not impaired because the fair value of its reporting unit approximated its book value at December 31, 2020, and accordingly 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. We believe that the fair value of our equity investment in Stagecoach Gas exceeded its $792.5 million carrying value at December 31, 2020, and accordingly did not have any triggers to assess our investment for impairment during 2020.

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
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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. 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 was 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, 2020 and 2019, we had deferred revenues of approximately $182.5 million and $153.5 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 of our contracts 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.

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.

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EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company’s operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. 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 realignment and restructuring of our operations, 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 EquityCrestwood Midstream
Year Ended December 31,Year Ended December 31,
20202019201820202019
Revenues$2,254.3 $3,181.9 $3,654.1 $2,254.3 $3,181.9 
Costs of product/services sold1,600.5 2,544.9 3,129.4 1,600.5 2,544.9 
Operations and maintenance expense131.8 138.8 125.8 131.8 138.8 
General and administrative expense91.5 103.4 88.1 86.7 98.2 
Depreciation, amortization and accretion237.4 195.8 168.7 251.5 209.9 
Loss on long-lived assets, net26.0 6.2 28.6 26.0 6.2 
Goodwill impairment80.3 — — 80.3 — 
Gain on acquisition— (209.4)— — (209.4)
Operating income86.8 402.2 113.5 77.5 393.3 
Earnings from unconsolidated affiliates, net32.5 32.8 53.3 32.5 32.8 
Interest and debt expense, net(133.6)(115.4)(99.2)(133.6)(115.4)
Gain (loss) on modification/extinguishment of debt0.1 — (0.9)0.1 — 
Other income (expense), net(0.7)0.6 0.4 — 0.2 
(Provision) benefit for income taxes(0.4)(0.3)(0.1)0.1 (0.3)
Net income (loss)(15.3)319.9 67.0 (23.4)310.6 
Add:
Interest and debt expense, net133.6 115.4 99.2 133.6 115.4 
(Gain) loss on modification/extinguishment of debt(0.1)— 0.9 (0.1)— 
Provision (benefit) for income taxes0.4 0.3 0.1 (0.1)0.3 
Depreciation, amortization and accretion237.4 195.8 168.7 251.5 209.9 
EBITDA356.0 631.4 335.9 361.5 636.2 
Unit-based compensation charges30.7 47.0 28.5 30.7 47.0 
Loss on long-lived assets, net26.0 6.2 28.6 26.0 6.2 
Goodwill impairment80.3 — — 80.3 — 
Gain on acquisition— (209.4)— — (209.4)
Earnings from unconsolidated affiliates, net(32.5)(32.8)(53.3)(32.5)(32.8)
Adjusted EBITDA from unconsolidated affiliates, net75.4 74.9 95.6 75.4 74.9 
Change in fair value of commodity inventory-related derivative contracts33.6 2.7 (18.3)33.6 2.7 
Significant transaction and environmental related costs and other items10.8 6.5 3.1 10.8 6.5 
Adjusted EBITDA$580.3 $526.5 $420.1 $585.8 $531.3 

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Crestwood EquityCrestwood Midstream
Year Ended December 31,Year Ended December 31,
20202019201820202019
Net cash provided by operating activities$408.1 $420.4 $253.6 $407.9 $424.1 
Net changes in operating assets and liabilities(36.1)(47.8)46.9 (30.0)(46.5)
Amortization of debt-related deferred costs(6.5)(6.2)(6.8)(6.5)(6.2)
Interest and debt expense, net133.6 115.4 99.2 133.6 115.4 
Unit-based compensation charges(30.7)(47.0)(28.5)(30.7)(47.0)
Loss on long-lived assets, net(26.0)(6.2)(28.6)(26.0)(6.2)
Goodwill impairment(80.3)— — (80.3)— 
Gain on acquisition— 209.4 — — 209.4 
Earnings from unconsolidated affiliates, net, adjusted for cash distributions received(6.5)(6.9)(0.5)(6.5)(6.9)
Deferred income taxes(0.1)— 0.7 — (0.2)
Provision (benefit) for income taxes0.4 0.3 0.1 (0.1)0.3 
Other non-cash income0.1 — (0.2)0.1 — 
EBITDA356.0 631.4 335.9 361.5 636.2 
Unit-based compensation charges30.7 47.0 28.5 30.7 47.0 
Loss on long-lived assets, net26.0 6.2 28.6 26.0 6.2 
Goodwill impairment80.3 — — 80.3 — 
Gain on acquisition— (209.4)— — (209.4)
Earnings from unconsolidated affiliates, net(32.5)(32.8)(53.3)(32.5)(32.8)
Adjusted EBITDA from unconsolidated affiliates, net75.4 74.9 95.6 75.4 74.9 
Change in fair value of commodity inventory-related derivative contracts33.6 2.7 (18.3)33.6 2.7 
Significant transaction and environmental related costs and other items10.8 6.5 3.1 10.8 6.5 
Adjusted EBITDA$580.3 $526.5 $420.1 $585.8 $531.3 

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

Gathering and ProcessingStorage and TransportationMarketing, Supply and Logistics
Revenues$631.4 $13.8 $1,609.1 
Intersegment revenues159.8 9.2 (169.0)
Costs of product/services sold261.5 0.2 1,338.8 
Operations and maintenance expense84.9 3.6 43.3 
Loss on long-lived assets, net(23.8)— (2.4)
Goodwill impairment(80.3)— — 
Earnings (loss) from unconsolidated affiliates, net(1.0)33.5 — 
EBITDA for the year ended December 31, 2020$339.7 $52.7 $55.6 
Revenues$835.8 $20.4 $2,325.7 
Intersegment revenues175.0 14.2 (189.2)
Costs of product/services sold526.1 0.2 2,018.6 
Operations and maintenance expense98.7 4.0 36.1 
Loss on long-lived assets, net(6.2)— (0.2)
Gain on acquisition209.4 — — 
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 revenues192.4 10.5 (202.9)
Costs of product/services sold767.0 0.2 2,362.2 
Operations and maintenance expense71.7 3.3 50.8 
Loss on long-lived assets, net(3.0)— (27.3)
Earnings from unconsolidated affiliates, net22.5 30.8 — 
EBITDA for the year ended December 31, 2018$319.9 $54.9 $47.1 

Segment Results

Below is a discussion of the factors that impacted EBITDA by segment for the year ended December 31, 2020 compared to the year ended December 31, 2019.

Gathering and Processing

EBITDA for our gathering and processing segment decreased by approximately $247.4 million during the year ended December 31, 2020 compared to 2019. Our gathering and processing segment’s EBITDA for the year ended December 31, 2020 was impacted by a $19.9 million loss on long-lived assets related to the sale of our Fayetteville gathering systems and an $80.3 million goodwill impairment related to our Jackalope operations. For the year ended December 31, 2019, our gathering and processing segment’s EBITDA was impacted by a $209.4 million gain related to the acquisition of the remaining 50% equity interest in Jackalope. For a further discussion of these matters, see “Critical Accounting Estimates” above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 2 and 3.

Our gathering and processing segment’s revenues decreased by approximately $219.6 million during the year ended December 31, 2020 compared to 2019, while our costs of product/services sold decreased by approximately $264.6 million. These decreases were primarily due to declines in commodity prices experienced during 2020 compared to 2019, which impacted the average prices that our gathering and processing segment realized on its agreements under which it purchases and sells crude oil and natural gas during the year ended December 31, 2020 compared to 2019.

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During the year ended December 31, 2020, our costs of product/services sold decreased faster than our revenues primarily as a result of Arrow placing in service a 120 MMcf/d cryogenic plant in August 2019, which resulted in a 108%, 34%, 9% and 30% increase in Arrow’s natural gas processing volumes and natural gas, crude oil and water gathering volumes, respectively, during the year ended December 31, 2020 compared to 2019. Partially offsetting the increase in Arrow’s volumes was a decrease in volumes during the second and third quarters of 2020 that resulted from certain of our gathering and processing customers shutting in volumes in response to the decrease in commodity prices experienced during the second quarter of 2020. Commodity prices began to improve late in the second quarter of 2020 and, as a result, certain of our gathering and processing customers began to bring some of the shut-in production back online during the third and fourth quarters of 2020. In addition, in April 2019, Crestwood Niobrara acquired the remaining 50% equity interest in Jackalope from Williams Partners LP and we began consolidating Jackalope’s results, which partially offset the decrease in revenues experienced related to the decline in commodity prices and producer shut-ins described above.

Our gathering and processing segment’s operations and maintenance expenses decreased by approximately $13.8 million during the year ended December 31, 2020 compared to 2019, primarily due to our cost cutting efforts which began in early second quarter of 2020 as a result of the low commodity price environment discussed above. In addition, our gathering and processing segment’s operations and maintenance expenses also decreased due to the sale of our Fayetteville assets described below.

Our gathering and processing segment’s EBITDA was impacted by a loss on long-lived assets of approximately $19.9 million during the year ended December 31, 2020 related to the sale of our Fayetteville assets which were sold on October 1, 2020. For a further discussion on the sale of our Fayetteville gathering assets, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3. In addition, during the years ended December 31, 2020 and 2019, we recorded a loss on long-lived assets of approximately $3.1 million and $4.3 million primarily related to the removal and retirement of certain water gathering lines on our Arrow system. For a further discussion on the retirement of our Arrow system water gathering lines, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

Our gathering and processing segment’s EBITDA was impacted by equity losses from our Crestwood Permian equity investment of approximately $1.0 million and $5.8 million during the years ended December 31, 2020 and 2019. Equity earnings from our Crestwood Permian equity investment were impacted by our proportionate share of write-offs at the equity investment related to certain of their growth projects and the retirement of certain of their gathering and processing assets during 2020 and 2019. Aside from these write-offs, Crestwood Permian’s results were relatively consistent year-over-year with decreases in gathering volumes (as a result of the decrease in commodity prices described above) being largely offset by the operating results generated by placing in service a produced water gathering and disposal system in late 2020. Our gathering and processing segment’s EBITDA was also impacted by a decrease in equity earnings from our Jackalope equity investment of $3.7 million during the year ended December 31, 2020 compared to 2019 due to the acquisition of the remaining 50% equity interest in Jackalope in April 2019.

Storage and Transportation

EBITDA for our storage and transportation segment decreased by approximately $12.6 million during the year ended December 31, 2020 compared to 2019. Revenues from our COLT Hub operations decreased by $11.6 million during the year ended December 31, 2020 compared to 2019, primarily due to a decline in demand for rail loading services as a result of the decline in commodity prices, which resulted in a decrease of 23% in rail loading volumes during 2020 compared to 2019. In addition, in late 2019 and early 2020, we renewed several rail loading and storage contracts at lower rates resulting in lower revenues during the year ended December 31, 2020 compared to 2019.

Our storage and transportation segment’s costs of product/services sold and operations and maintenance expenses were relatively flat during the year ended December 31, 2020 compared to 2019.

Our storage and transportation segment’s EBITDA was also impacted by a net decrease in earnings from unconsolidated affiliates during the year ended December 31, 2020 compared to 2019. Earnings from our PRBIC equity investment decreased by approximately $4.1 million during the year ended December 31, 2020 compared to 2019. During 2020, we recorded a $4.5 million reduction in equity earnings from PRBIC to reflect our proportionate share of a long-lived asset impairment recorded by our PRBIC equity investment. Earnings from our Stagecoach Gas equity investment increased by approximately $3.6 million during the year ended December 31, 2020 compared to 2019, primarily due to the increase in our proportionate share of Stagecoach Gas’s equity earnings from 40% to 50% effective July 1, 2019. Aside from the change in earnings percentage, our earnings from our Stagecoach Gas equity investment were relatively flat. During 2020, the demand for natural gas storage and transportation services provided by Stagecoach Gas was relatively flat due to decreases in natural gas prices and tight basis
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differentials across its assets, 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.

Marketing, Supply and Logistics

EBITDA for our marketing, supply and logistics segment decreased by approximately $26 million during the year ended December 31, 2020 compared to 2019. Our marketing, supply and logistics segment’s revenues decreased by approximately $696.4 million during the year ended December 31, 2020 compared to 2019, while our costs of product/services sold decreased by approximately $679.8 million during the year ended December 31, 2020 compared to 2019.

Our crude oil and natural gas marketing operations experienced a decrease in its revenues of approximately $632.8 million during the year ended December 31, 2020 compared to 2019, and a decrease in its product costs of approximately $631.1 million year over year. These decreases were driven by lower average sales prices to our customers and lower volumes due to the decline in commodity prices experienced during 2020.

Our NGL marketing and logistics operations were impacted by the significant decline in commodity prices described above and their impact on the NGL markets during 2020. During the year ended December 31, 2020, our NGL marketing and logistics operations experienced a decrease in revenues and costs of product/services sold of approximately $63.6 million and $48.7 million, respectively, compared to 2019, primarily driven by lower NGL prices during 2020. During the year ended December 31, 2020 compared to 2019, revenues decreased more than costs of product/services sold as a result of the decline in NGL prices, which was due to a combination of decreases in overall commodity prices, high NGL production and constrained NGL infrastructure. Although we were able to take advantage of market disruptions and low NGL prices during 2020 (which created strong margin for delivery into forward markets, and the constrained NGL infrastructure increased demand for our storage, terminalling and transportation assets), there was less volatility in NGL market conditions in 2020 than there was during 2019, where a combination of record high NGL production and constrained NGL infrastructure allowed our NGL marketing and logistics operations to capitalize on the significant market disruptions to utilize our trucking, rail and storage assets to source seasonal inventory for delivery into forward markets allowing us to generate higher margins in 2019 compared to 2020. Partially offsetting the decrease in revenues and costs of product/services sold was the operating results of the NGL assets that we acquired from Plains in April 2020. Included in our costs of product/services sold was a loss of $20.7 million during the year ended December 31, 2020 and a gain of $19.5 million during the year ended December 31, 2019 related to our price risk management activities.

Our marketing, supply and logistics operations and maintenance expenses increased by approximately $7.2 million during the year ended December 31, 2020 compared to 2019, primarily due to the acquisition of several NGL storage and rail-to-truck terminals from Plains in April 2020.

Our marketing, supply and logistics segment’s EBITDA includes a loss on long-lived assets of approximately $2.4 million during the year ended December 31, 2020, primarily related to the impairment and loss on the sale of our Bakken transportation assets.

Other EBITDA Results

General and Administrative Expenses. During the year ended December 31, 2020, general and administrative expenses decreased by approximately $12 million compared to 2019, primarily due to lower unit-based compensation charges as a result of the decrease in the market price for Crestwood Equity’s common units during 2020 compared to 2019.

Items not affecting EBITDA include the following:

Depreciation, Amortization and Accretion Expense. During the year ended December 31, 2020, depreciation, amortization and accretion expense increased by approximately $41.6 million compared to 2019, primarily due to the acquisition of NGL assets from Plains in April 2020 and the acquisition of the remaining 50% equity interest in Jackalope in April 2019. In addition, we placed in-service the expansion of our processing capacity at our Bucking Horse processing facility on our Powder River Basin system in early 2020 and placed into service the Bear Den II processing plant on our Arrow system in late 2019.

Interest and Debt Expense, Net. Interest and debt expense, net increased by approximately $18.2 million during the year ended December 31, 2020 compared to 2019, primarily due to the issuance of $600 million unsecured senior notes in April 2019. In addition, our capitalized interest was lower during the year ended December 31, 2020 compared to 2019 due to the timing of growth capital projects primarily in the Bakken and Powder River Basin.
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The following table provides a summary of our interest and debt expense, net (in millions):
Year Ended December 31,
202020192018
Credit facilities$23.3 $26.4 $24.6 
Senior notes106.1 96.6 72.5 
Other debt-related costs6.9 6.8 7.1 
Gross interest and debt expense136.3 129.8 104.2 
Less: capitalized interest2.7 14.4 5.0 
Interest and debt expense, net$133.6 $115.4 $99.2 


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 and contributions from us to fund their operating activities, maintenance and growth capital expenditures, and service their outstanding indebtedness.

The COVID-19 pandemic’s impact on global crude oil demand and corresponding supply and demand imbalances have created significant near-term challenges for the energy industry including record low commodity prices, production declines and temporary shut-ins for producers in every major basin across North America. We are aggressively responding to these extraordinary market events by canceling or delaying capital projects, substantially reducing operating and administrative costs, optimizing our storage assets and working closely with our customers to maintain volumes across our diversified asset portfolio. Through these steps, combined with the steps we have taken over the past few years, we believe our liquidity sources and operating cash flows are sufficient to address our future operating, debt service and capital requirements.

We make quarterly cash 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. We also pay quarterly cash 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 exceed cash distributions to our partners, preferred unitholders and non-controlling partner, and as a result, we will have adequate operating cash flows as a source of liquidity for our growth capital expenditures.

On January 21, 2021, we declared a quarterly cash distribution of $0.625 per unit to our common unitholders, which was paid on February 12, 2021 and was consistent with the distribution paid in November 2020. Based on our financial performance in 2020 and our estimates of our financial performance for future quarters, we believe the current level of distributions is appropriate. Our Board of Directors evaluates the level of distributions to our common and preferred unitholders every quarter and considers a wide range of strategic, commercial, operational and financial factors, including current and projected operating cash flows and liquidity needs and the potential adverse impact of future distribution reductions on our common unitholders, including our general partner. The evaluation also includes a review of the potential for an event of default of the debt of Crestwood Holdings, which could result in a change in control at Crestwood Holdings and, accordingly, in us, which is further described in Part I, Item 1A. Risk Factors.

As of December 31, 2020, we had $507.1 million of available capacity under the Crestwood Midstream credit facility considering the most restrictive debt covenants in the credit agreement. As of December 31, 2020, we were in compliance with all of our debt covenants applicable to the credit facility and our senior notes. We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, tender offers or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. In January 2021, Crestwood Midstream issued $700 million of 6.00% unsecured senior notes due 2029 (the 2029 Senior Notes). We utilized the proceeds from the issuance of the 2029 Senior Notes to repurchase and cancel $399.2 million outstanding on our senior notes due 2023 (2023 Senior Notes) and to reduce borrowings on our credit facility. We intend to redeem and cancel the remaining 2023 Senior Notes after they become callable at par in April 2021. See Part IV, Item 15.
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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,
202020192018
Net cash provided by operating activities$408.1 $420.4 $253.6 
Net cash used in investing activities(273.3)(943.7)(241.2)
Net cash provided by (used in) financing activities(146.5)531.8 3.5 

Operating Activities

Our operating cash flows decreased by approximately $12.3 million during the year ended December 31, 2020 compared to 2019. The decrease was driven by lower revenues of approximately $927.6 million primarily from our marketing, supply and logistics segment’s and our gathering and processing segment’s operations, offset by lower costs of product/services sold of approximately $944.4 million primarily from these segments as discussed above in Results of Operations.

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
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 2021, we anticipate growth capital expenditures of approximately $35 million to $45 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 $5 million to $15 million on capital expenditures that are directly reimbursable by our customers. We anticipate that our growth and reimbursable capital expenditures in 2021 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. Additional commitments or expenditures will be made at our discretion, and any discontinuation of the construction of these projects could result in less future operating cash flows and earnings.

The following table summarizes our capital expenditures for the year ended December 31, 2020 (in millions):

Growth capital$140.4 
Maintenance capital10.7 
Other(1)
17.2 
Purchases of property, plant and equipment$168.3 

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

Acquisitions and Divestitures. Below is a summary of the acquisitions and divestitures which impacted our investing activities during the years ended December 31, 2020 and 2019.

In April 2020, we acquired NGL assets from Plains for approximately $162 million;
In April 2019, Crestwood Niobrara acquired Williams’s 50% equity interest in Jackalope for approximately $462.1 million, net of cash acquired of approximately $22.5 million; and
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In October 2020, we sold our Fayetteville gathering assets for approximately $23 million.

Investments in Unconsolidated Affiliates. Pursuant to our joint venture agreements with our respective equity investments, we periodically make contributions to our equity investments to fund their expansion projects and for other operating purposes. During the years ended December 31, 2020 and 2019, we contributed approximately $3.4 million and $28.3 million to our Crestwood Permian equity investment primarily to fund its expansion projects and we contributed $6.0 million and $8.6 million during 2020 and 2019 to our other equity investments for other operating purposes. We also contributed $24.4 million to our Jackalope equity investment during 2019 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. For further details regarding these contributions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6.

Financing Activities

The following equity and debt transactions which impacted our financing activities during the years ended December 31, 2020 and 2019 included the following:

Equity and Debt Transactions

During the year ended December 31, 2020, distributions to our partners increased by $10.3 million compared to 2019, primarily due to the increase in our quarterly distribution from $0.60 per limited partner unit to $0.625 per limited partner unit;
During the year ended December 31, 2019, Crestwood Niobrara issued $235 million in new Series A-3 Preferred Units to CN Jackalope Holdings LLC 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;
During the years ended December 31, 2020 and 2019, Crestwood Niobrara paid cash distributions of $37.1 million and $25.0 million to its non-controlling partner. In addition, during the year ended December 31, 2020, Crestwood Niobrara received contributions of $2.8 million from its non-controlling partner;
During the year ended December 31, 2020, our taxes paid for unit-based compensation vesting increased by approximately $4.6 million compared to 2019, primarily due to higher vesting of unit-based compensation awards;
During the year ended December 31, 2020, we paid approximately $12.6 million to repurchase and cancel approximately $12.8 million of our senior notes due 2023;
During the year ended December 31, 2019, we received net proceeds of approximately $591.1 million from the issuance of our senior notes due 2027; and
During the year ended December 31, 2020, our debt-related transactions resulted in net proceeds of approximately $161.9 million compared to net borrowings of approximately $22.3 million during the year ended December 31, 2019.

Guarantor Summarized Financial Information

Crestwood Midstream and Crestwood Midstream Finance Corp. are issuers of our debt securities (the Issuers). Crestwood Midstream is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Crestwood Midstream Finance Corp. is Crestwood Midstream’s 100% owned subsidiary and has no material assets or operations other than those related to its service as co-issuer of our senior notes. Obligations under Crestwood Midstream’s senior notes and its credit facility are jointly and severally guaranteed by substantially all of its subsidiaries (collectively, the Guarantor Subsidiaries), except for Crestwood Infrastructure Holdings LLC, Crestwood Niobrara LLC, Crestwood Pipeline and Storage Northeast LLC, Powder River Basin Industrial Complex LLC, and Tres Palacios Holdings LLC and their respective subsidiaries (collectively, Non-Guarantor Subsidiaries). The assets and credit of our Non-Guarantor Subsidiaries are not available to satisfy the debts of the Issuers or Guarantor Subsidiaries, and the liabilities of our Non-Guarantor Subsidiaries do not constitute obligations of the Issuers or Guarantor Subsidiaries. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 9 for additional information regarding our credit facility and senior notes and related guarantees.

The following tables provide summarized financial information for the Issuers and Guarantor Subsidiaries (collectively, the Obligor Group) on a combined basis after elimination of significant intercompany balances and transactions between entities in the Obligor Group. The investment balances in the Non-Guarantor Subsidiaries have been excluded from the supplemental
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summarized combined financial information. Transactions with other related parties, including the Non-Guarantor Subsidiaries, represent affiliate transactions and are presented separately in the summarized combined financial information below.

Summarized Combined Balance Sheet Information (in millions)

December 31, 2020
Current assets$371.3 
Current assets - affiliates$1.1 
Property, plant and equipment, net$2,295.2 
Non-current assets$696.2 
Current liabilities$345.4 
Current liabilities - affiliates$5.0 
Long-term debt, less current portion$2,483.8 
Non-current liabilities$157.4 

Summarized Combined Income Statement Information (in millions)

Year Ended December 31, 2020
Revenues$2,150.5 
Revenues - affiliates$29.1 
Cost of products/services sold$1,579.5 
Cost of products/services sold - affiliates$21.1 
Operations and maintenance expenses(1)
$111.8 
General and administrative expenses(2)
$86.7 
Operating income$158.4 
Net income$25.0 

(1)    We have operating agreements with certain of our 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, 2020, we charged $28.5 million to our affiliates under these agreements.
(2)    Includes $26.7 million of net general and administrative expenses that were charged by our affiliates to us.

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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 asset retirement obligations, while other obligations, such as capital and other commitments and contractual interest amounts are not reflected on our consolidated balance sheets. The following table summarizes our contractual cash obligations as of December 31, 2020 (in millions):

Less than 1 Year1-3 Years3-5 YearsThereafterTotal
Long-term debt:
Principal(1)
$0.2 $1,406.4 $500.0 $600.0 $2,506.6 
Interest(2)
123.1 209.0 103.4 45.1 480.6 
Standby letters of credit23.9 — — — 23.9 
Future minimum payments under leases(3)
19.8 20.2 9.5 5.0 54.5 
Asset retirement obligations1.0 — — 34.1 35.1 
Fixed price commodity purchase commitments(4)
1,398.2 200.6 — — 1,598.8 
Purchase commitments and other contractual obligations(5)
25.7 — — — 25.7 
Total contractual obligations$1,591.9 $1,836.2 $612.9 $684.2 $4,725.2 
    
(1)    In January 2021, Crestwood Midstream issued $700 million of 6.00% unsecured senior notes due 2029. We utilized the proceeds from the issuance of the 2029 Senior Notes to repurchase and cancel $399.2 million outstanding on our 2023 Senior Notes. We intend to redeem and cancel the remaining 2023 Senior Notes after they become callable at par in April 2021.
(2)    $719.0 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 2.40% and 4.50% at December 31, 2020. These rates have been applied for each period presented in the table.
(3)    Includes our operating and finance leases. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 11 for a further discussion of these obligations.
(4)     Fixed price purchase commitments are volumetrically offset by third party fixed price sale contracts.
(5)     Primarily related to growth and maintenance contractual purchase obligations in our gathering and processing segment and environmental obligations included in accrued expenses and other liabilities on our consolidated balance sheets. 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.

Off-Balance Sheet Arrangements

As of December 31, 2020, 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.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Interest Rate Risk

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

For fixed rate debt, changes in the interest rates generally affect the fair value of the debt instrument, but not our earnings or cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt instrument, but may affect our future earnings and cash flows.
As of December 31, 2020 and 2019, both the carrying value and fair value of our fixed rate debt instruments was approximately $1.8 billion in each period. For a further discussion of our fixed rate debt, see Part IV, Item 15. Exhibits, 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, 2020, we had obligations totaling $719.0 million outstanding under the credit facility. These floating rate obligations expose us to the risk of increased interest payments 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, 2020, our annual interest expense would have changed by approximately $7.2 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 minimum 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 our price risk management activities are energy marketers, propane retailers, resellers, and dealers.

We engage in hedging and risk management transactions, including various types of forward contracts, options, swaps and futures contracts, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions and to help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by purchasing volumes only when we have a matching purchase commitment from our marketing customers. However, we may experience net unbalanced positions from time to time, which we believe to be immaterial in amount. In addition to our ongoing policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the market value of our derivative portfolio. These derivatives are not designated as hedges for accounting purposes.

The fair value of the derivatives contracts related to price risk management activities as of December 31, 2020 were assets of $27.2 million and liabilities of $76.3 million. We use observable market values for determining the fair value of these derivative contracts. In cases where actively quoted prices are not available, other external sources are used that incorporate
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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 impact that a 10% change in market prices would have on the underlying fair value of our commodity-based derivative instruments, along with the net unbalanced position of those commodity-based derivatives at December 31, 2020 and the inventory position that would substantially offset that theoretical change at December 31, 2020:

December 31, 2020
Change in Fair Value of Commodity-Based Derivatives
(in millions)
Net Unbalanced Derivative PositionInventory Position
Natural gas$0.7 2.6 Bcf0.5 Bcf
NGLs$8.7 2.8 MMBbls2.6 MMBbls
Crude oil$4.2 0.9 MMBbls0.8 MMBbls

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.

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.


Item 9A. Controls and Procedures

Disclosure Controls and Procedures

As of December 31, 2020, 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,
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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, 2020.

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 2020 that have materially affected, or are reasonably likely to materially affect Crestwood Equity’s and Crestwood Midstream’s internal control over financial reporting.

Management’s Report on Internal Control Over Financial Reporting

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

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

Under the supervision and with the participation of Crestwood Equity’s and Crestwood Midstream’s management, including the Chief Executive Officers and Chief Financial Officers of their General Partners, Crestwood Equity and Crestwood Midstream assessed the effectiveness of their respective internal control over financial reporting as of December 31, 2020. 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, 2020, their respective internal control over financial reporting is effective, based upon those criteria.

Crestwood Equity’s independent registered public accounting firm, Ernst & Young LLP, issued an attestation report dated February 26, 2021, on the effectiveness of our internal control over financial reporting, which is included herein.


Item 9B. Other Information

None.

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PART III

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

Item 10. Directors, Executive Officers and Corporate Governance

Our General Partner Manages Crestwood Equity Partners LP

Crestwood Equity GP LLC, our general partner, manages our operations and activities. Our general partner is not elected by our unitholders and will not be subject to re-election on a regular basis in the future. Our general partner may not be removed unless that removal is approved by the vote of the holders of not less than 66 2/3% of the outstanding units, including units held by the general partner and their affiliates, and we receive an opinion of counsel regarding limited liability and tax matters. Any removal of the general partner is also subject to the approval of a successor general partner by the vote of the holders of a majority of the outstanding common units. Unitholders do not directly or indirectly participate in our management or 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 nine directors.
     
Directors and Executive Officers
 
The following table sets forth certain information with respect to the executive officers and members of the board of directors of our general partner. Executive officers and directors will serve until their successors are duly appointed or elected.

Executive Officers and DirectorsAgePosition with our General Partner
Robert G. Phillips66President, Chief Executive Officer and Director
Robert T. Halpin37Executive Vice President, Chief Financial Officer
Steven M. Dougherty48Executive Vice President, Chief Accounting Officer
Joel C. Lambert52Executive Vice President, Chief Legal, Compliance and Safety Officer
William H. Moore41Executive Vice President, Corporate Strategy
Alvin Bledsoe72Director
William Brown39Director
Warren H. Gfeller68Director
Janeen S. Judah61Director
David Lumpkins66Director
Gary D. Reaves41Director
John J. Sherman65Director
Frances M. Vallejo55Director
 
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
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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 served as a Director of Bonavista Energy Corporation, a Canadian independent oil and gas producer, from May 2015 to March 2020. Mr. Phillips holds a B.B.A. from The University of Texas at Austin and a Juris Doctorate from South Texas College of Law. Mr. Phillips was selected to serve as the Chairman of the Board of our general partner because of his deep experience in the midstream business, expansive knowledge of the oil and gas industry, as well as his experience in executive leadership roles for public companies in the energy industry and operational and financial expertise in the oil and gas business generally.

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 Chairman of the Board 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
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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. 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 non-executive Chairman of the Board since April 2020. He 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 Aethon Energy. Additionally, Ms. Judah serves on the University Lands Advisory Board. She previously served as a director at 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 served as a director of Westlake Chemical Partners LP from January 2015 until November 2019. 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 appointed 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. Mr. Sherman is the former Chief Executive Officer and President of Inergy, L.P. and Inergy Midstream, L.P., and served in those positions until 2013. Additionally, he served as President, Chief Executive Officer and director of Inergy Holdings GP, LLC. Currently, he is the Chairman and CEO of the Kansas City Royals Club. Prior to joining our predecessor, he was a vice president with Dynegy Inc. from 1996 through 1997. 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. Mr. Sherman previously served as a director on the boards of Evergy and Tech Accel LLC. We believe the breadth of Mr. Sherman’s experience in the energy industry has given him valuable knowledge about our business and our industry that makes him an asset to our board of directors.

Frances M. Vallejo was appointed to the board of our general partner on February 1, 2021. She is a former executive officer of ConocoPhillips where she began her career in 1987. She served as Vice President Corporate Planning and Development from April 2015 until December 2016 and as Vice President and Treasurer from October 2008 until March 2015. Prior to October 2008, she served as General Manager Corporate Planning and Budgets, Vice President Upstream Planning and Portfolio
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Management, Assistant Treasurer, Manager Strategic Transactions, and in other geophysical, commercial, and finance roles. Ms. Vallejo has served as a member of the board of Cimarex Energy since May 2017, a member of the Board of Trustees of Colorado School of Mines from 2010 until 2016 and is a member of the Colorado School of Mines Foundation Board of Governors. Ms. Vallejo was appointed to serve as a director of our general partner due to her significant financial and corporate planning and development experience.

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, David Lumpkins, John Sherman and Frances Vallejo qualify as independent pursuant to independence standards established by the NYSE as set forth in Section 303A.02 of the manual. To be considered an independent director under the NYSE listing standards, the board of directors must affirmatively determine that a director has no material relationship with us other than as a director. In making this determination, the board of directors adheres to all of the specific tests for independence included in the NYSE listing standards and considers all other facts and circumstances it deems necessary or advisable.

Board Committees

Audit Committee

The members of the audit committee are Alvin Bledsoe (Chairman), Janeen Judah, David Lumpkins and Frances Vallejo. 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), Warren Gfeller and Frances Vallejo. 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.

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Sustainability Committee

The members of the sustainability committee are Janeen Judah (Chairman), William Brown and Frances Vallejo. 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.

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. The sustainability committee assists the board on matters relating to sustainability, which include environmental risks and opportunities, social responsibility and impacts, employee, contractor and community health and safety, and activities related to stakeholder engagement and community investment.

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. In February 2021, our board of directors approved certain amendments to the corporate governance guidelines to add the following items:

Duties of the Lead Director;
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Attendance Policy (directors expected to attend at least 75% of board and committee meetings);
Director Stock Ownership Guidelines (maintain equity at least five times the annual cash retainer);
Statement on Board Diversity and Inclusion; and
Limitation on Service on other Boards (CEO should not serve on more than two other boards of a public company and other directors should not serve on more than four other boards of public companies).

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, 2020, all section 16(a) filing requirements applicable to our directors, executive officers and greater than 10% unitholders, were met.


Item 11. Executive Compensation

Compensation Discussion and Analysis
 
Introduction

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

All of our executive officers also serve in the same capacities as executive officers of 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 2020 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; and
Joel C. Lambert, our Executive Vice President, Chief Legal, Compliance and Safety 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-term 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.

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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.

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 2020 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 2020, 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
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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 2020 executive compensation analyses.

CompanyTicker Symbol
Revenue (LTM) (1)
Market Cap (1)
Targa Resources Corp.TRGP$9,879 $9,232 
DCP Midstream, LPDCP$9,294 $3,746 
EnLink Midstream, LLCENLC$7,633 $3,927 
MPLX LPMPLX$6,430 $30,252 
Buckeye Partners, L.P.BPL$3,805 $6,329 
Sprague Resources LPSRLP$3,619 $395 
Enable Midstream Partners, LPENBL$3,408 $5,130 
Magellan Midstream Partners, L.P.MMP$3,834 $15,018 
Genesis Energy LPGEL$2,689 $2,651 
SemGroup CorporationSEMG$2,488 $1,295 
Western Midstream Partners, LPWES$2,828 $11,194 
NuStar Energy L.P.NS$1,916 $3,029 
EQM Midstream Partners, LPEQM$1,545 $6,471 
Tallgrass Energy Partners, LPTGE$829 $— 
Summit Midstream Partners, LPSMLP$492 $399 
75th Percentile$5,118 $7,851 
Median$2,834 $3,927 
25th Percentile$2,122 $1,973 
Crestwood Equity Partners LPCEQP$3,217 $2,609 
Percent Rank55 %28 %
(1)    Information is as of October 1, 2019

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
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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 50th percentile of the market data, the compensation committee approved increases for our NEOs effective January 1, 2020. Accordingly, the annual base salaries were increased as follows: Mr. Phillips ($800,000), Mr. Halpin ($500,000), Mr. Dougherty ($435,000), Mr. Lambert ($470,000) and Mr. Moore ($395,000).

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.

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 Table - 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 2020 were determined based on our achievement of compensation committee approved key performance indicators (KPIs) and a board discretionary component. The KPIs for fiscal 2020 were Distributable Cash Flow Per Common Unit, Adjusted EBITDA, Total Shareholder Return Relative to Peers, Safety, and Optimization and Sustainability Achievements. 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.

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20202020%Weighting
2020 Annual Incentive Awards KPIsActualsTargetAchievedWeightingAchieved
Consolidated Distributable Cash Flow Per Common Unit$4.91$5.0797 %30 %29 %
Consolidated Adjusted EBITDA$580$60872 %30 %22 %
Total Shareholder Return Relative to Peers101 %100 %101 %10 %10 %
Safety
Total Recordable Incident Rate0.96 1.3 126 %%%
Lost Time Injury Rate0.48 0.7 131 %%%
Preventable Vehicle Incident Rate1.19 1.4 115 %%%
Contractor TRIR on Growth/Maintenance Capital1.81 1.3 61 %%%
Safety and Compliance Leading Indicators(1)
%%
Optimization and Sustainability Achievements(2)
10 %13 %
Total Achievement96 %

(1)    Safety and Compliance Leading Indicators consisted of employee safety goals and near miss reports and completion of compliance tasks and training.
(2)    Optimization and Sustainability Achievements consisted of operations and maintenance and general and administrative costs, growth capital expenditures, ratings by ESG agencies and cybersecurity training and penetration testing.

Based on the company’s KPI achievement, the annual incentive bonus pool for fiscal 2020 was calculated at 96% of target. The board then utilized its discretionary authority to increase the recommended bonus pool by 5.5%. The board cited management’s COVID-19 response and execution, ESG leadership, and the completion of several strategic transactions as the rationale for increasing the bonus pool.

The actual bonus amount paid to the individual NEO is then further adjusted based on the individual performance review for such NEO. All of our NEOs received the highest performance rating of “1” which increased the actual percentage for such individuals to 120% of target, which is equivalent to the company-wide target payout for “1” performance ratings.

The 2020 bonus payouts were as follows:

Name2020 Base Salary ($)Target Bonus ($)Percentage of Target BonusTotal ($)
Robert G. Phillips800,0001,000,000120%1,200,000
Robert T. Halpin500,000500,000120%600,000
William H. Moore395,000395,000120%474,000
Steven M. Dougherty435,000391,500120%469,800
Joel C. Lambert470,000423,000120%507,600

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 project, the strategic importance of the project to the company and the respective individual’s efforts in sourcing and completing the project.

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On January 2, 2020, the compensation committee made one-time project completion restricted unit awards to each of Mr. Halpin, Mr. Moore and Mr. Dougherty for their efforts in sourcing, financing and closing the company’s acquisition of the 50% interest in Jackalope Gas Gathering Services, L.L.C. from The Williams Companies in April 2019, which was an important strategic transaction in our efforts to expand our operational footprint in our core growth basins. The restricted units awarded were as follows:

Name
Units Awarded(1)
Value at Grant Date ($)
Robert T. Halpin16,223506,482
William H. Moore16,223506,482
Steven M. Dougherty8,112253,257
(1)    The units vest in full three years from the grant date.

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 2020, 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 Table - 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. The following annual restricted unit awards were made to our NEOs in 2020:

NameTarget Equity Percentage
2020 Restricted Units Awarded(1)
Value at Grant Date ($)
Robert G. Phillips400%103,8293,264,384
Robert T. Halpin275%44,6141,402,664
William H. Moore225%28,837906,635
Steven M. Dougherty225%31,757998,440
Joel C. Lambert250%38,1251,198,650
(1)    The annual restricted unit grants pay cash distributions in the same amount that would be payable to the holder of common units.

The annual restricted unit grants pay partnership distributions in cash in the same amount that would be payable to 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 2020, 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 Adjusted EBITDA, distributable cash flow per unit, 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:

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Performance Unit MetricWeighting
Adjusted EBITDA30%
Distributable Cash Flow per Unit30%
Return on Capital Invested20%
Total Unitholder Return20%

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 to or greater than the threshold is determined on a linear scale between performance levels.

In making the 2020 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 December 16, 2019:

Performance Units
NameMinimum (#)Target (#)Maximum (#)Value at Grant Date ($)
Robert G. Phillips25,89851,796103,5921,416,414
Robert T. Halpin6,90713,81327,626377,733
William H. Moore5,18010,36020,720283,305
Steven M. Dougherty5,18010,36020,720283,305
Joel C. Lambert6,47512,94925,898354,105

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. For performance units granted in 2020, the value of the distributions is converted into units each quarter based on the closing price of CEQP units on the payment date.

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-term 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 2020.”
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Other Compensation Related Matters

Retirement and Health Benefits

We offer a variety of health and welfare and retirement programs to all eligible employees. The NEOs are eligible for 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.

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, 2020.

Members of the Compensation Committee

Warren Gfeller
Alvin Bledsoe


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Summary Compensation Table for Fiscal 2020

The following table sets forth the cash and non-cash compensation earned by our NEOs for the fiscal years ended December 31, 2020, 2019 and 2018.
Name and Principal PositionFiscal
Year
Salary
($)
Bonus
($)
Unit
Awards
($)(1)
Non-Equity Incentive Plan Compensation ($)
All Other Compensation ($)(2)


Total
($)
Robert G. Phillips
President, Chief Executive Officer and Director
2020829,8074,783,0701,200,000153,4096,966,286
2019774,0387,154,1211,085,00052,1389,065,297
2018747,1024,120,1091,125,00017,3886,009,599
Robert T. Halpin
Executive Vice President, Chief Financial Officer
2020517,8842,314,193600,00021,4023,453,479
2019464,4232,414,740651,00021,7053,551,868
2018448,5383,123,311675,00016,3444,263,193
William H. Moore
Executive Vice President, Corporate Strategy
2020409,8071,716,894474,00020,2662,620,967
2019385,0001,706,964539,00020,3792,651,343
2018384,0582,319,731577,50016,2543,297,543
Steven M. Dougherty
Executive Vice President, Chief Accounting Officer
2020451,2301,555,474469,80024,2222,500,726
2019421,5381,800,332472,64021,6542,716,164
2018409,0872,178,202492,00016,4703,095,759
Joel C. Lambert
Executive Vice President,
Chief Legal, Compliance and Safety
Officer
2020486,7301,578,347507,60022,9022,595,579
2019434,0382,138,998435,00022,8393,030,875
2018409,0872,178,202492,00016,6143,095,903
(1)    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. For performance units granted in 2020, the value of the distributions is converted into units each quarter based on the closing price of CEQP units on the payment date and this value is included in the total unit awards amounts. 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.
(2) All Other Compensation for Fiscal Year 2020 consisted of the following:

Name401(k) Matching Contributions ($)Group Term Life Insurance ($)Other ($)Total ($)
Robert G. Phillips17,1008,239
128,070 (1)
153,409
Robert T. Halpin17,1004,30221,402
William H. Moore17,1003,16620,266
Steven M. Dougherty17,1004,722
2,400 (2)
24,222
Joel C. Lambert17,1005,80222,902
    
(1)    Represents the incremental cost to the Company of the personal use of the Company aircraft.
(2)    Represents the transfer of certain personal seat licenses.

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Grants of Plan-Based Awards Table for Fiscal 2020

The following table provides information concerning each grant of an award made to our NEOs during fiscal 2020.

Estimated Future Payouts Under Non-Equity Incentive Plan Awards(1)
Estimated Future Payout Under Equity Incentive Plan Awards(2)
NameGrant DateThreshold ($)Target ($)


Maximum ($)
Threshold
(#)
Target
(#)
Maximum
(#)
All Other Unit Awards
(#)(3)
Grant Date Fair Value of Unit and Option Awards ($)(4)
Robert G. Phillips01/03/20103,8293,264,384
02/10/2025,89851,796103,5921,416,414
400,0001,000,0001,400,000
Robert T. Halpin01/02/2016,223506,482
01/03/2044,6141,402,664
02/10/206,90713,81327,626377,733
200,000500,000700,000
William H. Moore01/02/2016,233506,482
01/03/2028,837906,635
2/10/205,18010,36020,720283,305
158,000395,000553,000
Steven M. Dougherty01/02/208,112253,257
01/03/2031,757998,440
2/10/205,18010,36020,720283,305
156,600391,500548,100
Joel C.
Lambert
01/03/2038,1251,198,650
2/10/206,47512,94925,898354,105
169,200423,000592,200

(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 EBITDA, distributable cash flow per unit, return on capital invested 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.
(4)    Unit award amounts reflect the aggregate grant date fair value of unit awards granted during 2020 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.

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

Employment Agreements

We have entered into employment agreements (the Executive Employment Agreements) with each of our named executive officers. 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
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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 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 2020 Fiscal Year-End

The following table summarizes the outstanding equity awards as of the end of Fiscal 2020 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. Phillips448,9458,520,976
Robert T. Halpin226,9044,306,639
William H. Moore162,9293,092,392
Steven M. Dougherty157,8692,996,354
Joel C. Lambert167,7713,184,294

(1)     Mr. Phillips' restricted units vest as follows: 34,609 units vest on January 3, 2021, 104,070 units vest on January 8, 2021, 37,024 units vest on January 10, 2021, 34,610 units vest on January 3, 2022, 37,024 units vest on January 10, 2022 and 34,610 units vest on January 3, 2023. Mr. Phillips' phantom performance units vests as follows: 107,488 units vest on February 12, 2022 and 59,510 units vest on February 10, 2023. Mr. Halpin's restricted units vest as follows: 14,871 units vest on January 3, 2021, 90,989 units vest on January 8, 2021, 15,272 units vest on January 10, 2021, 14,871 units vest on January 3, 2022, 15,273 units vest on January 10, 2022, 16,223 units vest on January 2, 2023 and 14,872 units vest on January 3, 2023. Mr. Halpin's phantom performance units vests as follows: 28,663 units vest on February 12, 2022 and 15,870 units vest on February 10, 2023. Mr. Moore's restricted units vest as follows: 9,612 units vest on January 3, 2021, 63,776 units vest on January 8, 2021, 10,346 units vest on January 10, 2021, 9,612 units vest on January 3, 2022, 10,346 units vest on January 10, 2022, 16,223 units vest on January 2, 2023 and 9,613 units vest on January 3, 2023. Mr. Moore's phantom performance units vests as follows: 21,497 units vest on February 12, 2022 and 11,904 units vest on February 10, 2023. Mr. Dougherty's restricted units vest as follows: 10,585 units vest on January 3, 2021, 61,919 units vest on January 8, 2021, 11,340 units vest on January 10, 2021, 10,586 units vest on January 3, 2022, 11,340 units vest on January 10, 2022, 8,112 units vest on January 2, 2023 and 10,586 units vest on January 3, 2023. Mr. Dougherty's phantom units vests as follows: 21,497 units vest on February 12, 2022 and 11,904 units vest on February 10, 2023. Mr. Lambert's restricted units vest as follows: 12,708 units vest on January 3, 2021, 61,919 units vest on January 8, 2021, 12,988 units vest on January 10, 2021, 12,708 units vest on January 3, 2022, 12,989 units vest on January 10, 2022 and 12,709 units vest on January 3, 2023. Mr. Lambert's phantom performance units vests as follows: 26,872 units vest on February 12, 2022 and 14,878 units vest on February 10, 2023. The above vesting schedule does not include the unitized accrued distributions on the performance phantom unit granted in 2019.
(2)    Does not includes unitization of the accrued distributions on the performance phantom units granted in 2019 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 $18.98 on December 31, 2020.
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Units Vested During Fiscal 2020

The following table provides information regarding restricted and performance units vesting during Fiscal 2020 for each of the NEOs. For the restricted units, the 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. For the performance units, the value realized on vesting was calculated by using the NYSE closing price of Crestwood Equity Partners LP on the day the award vested.

UNIT AWARDS
NameNumber of Units Acquired On VestingValue Realized on Vesting ($)
Robert G. Phillips316,2069,283,531
Robert T. Halpin116,5053,465,266
William H. Moore85,7082,547,172
Steven M. Dougherty85,1892,530,033
Joel C. Lambert86,8372,582,209

Vesting of 2017 Performance Grants
MetricHighest Performance LevelPerformance Achieved
Adjusted EBITDA$480$523
Distributable Cash Flow Per Unit$3.50$4.17
Return on Capital Invested17.5%17.0%
Total Unitholder Return>75th Percentile>75th Percentile

The final performance achievement resulted in a weighted average of 196% multiplier which resulted in the issuance of 448,950 common units (net of 268,964 common units withheld to satisfy tax withholding obligations) being issued to the NEOs related to the 2017 performance unit grants.

Pension Benefits during Fiscal 2020

We do not offer any pension benefits.

Non-qualified Deferred Compensation during Fiscal 2020

Our compensation committee adopted the Crestwood Nonqualified Deferred Compensation Plan (the “NQDC”) 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 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.

Potential Payments upon a Change in Control or Termination during Fiscal 2020

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
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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 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, 2020.

Name
Cash Severance ($)(1)
Accelerated Vesting of Restricted Units ($)(2)
Benefit Continuation ($)(3)
Total ($)
Robert G. Phillips5,715,0008,520,97624,19814,260,174
Robert T. Halpin2,326,0004,306,63928,0036,660,642
William H. Moore1,906,5003,092,39228,0095,026,901
Steven M. Dougherty1,834,6402,996,35428,0094,859,003
Joel C. Lambert1,867,0003,184,29428,3955,079,689

(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 $18.98 for CEQP units on December 31, 2020. 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 2020

The following table sets forth the cash and non-cash compensation for Fiscal 2020 by each person who served as a non-employee director of our general partner during such time.

NameFees Earned or Paid in Cash ($)
Unit Awards ($)(1)
Non-Qualified Deferred Comp Earnings ($)Total ($)
Alvin Bledsoe120,000111,4243,848235,272
William Brown111,424111,424
Warren Gfeller140,000111,424251,424
Janeen Judah120,000111,424231,424
David Lumpkins120,000111,424231,424
Gary Reaves111,424111,424
John Sherman100,000111,424211,424

(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, 2020, our non-employee directors held the following restricted unit awards: Mr. Brown, Mr. Gfeller, Ms. Judah, Mr. Lumpkins, Mr. Reaves and Mr. Sherman each held 3,569 restricted units. Mr. Bledsoe deferred his unit awards pursuant to the Non-Qualified Deferred Compensation Plan.
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Compensation of Directors during Fiscal 2020

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, finance committee chairperson and sustainability committee chairperson each receive additional cash compensation of $20,000 per year and the compensation committee chairperson receives additional cash compensation of $20,000 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 $110,000 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.

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 2020 total taxable cash and equity compensation (again, to the extent taxed to the employee in 2020), 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, 2020. We included all salaried and hourly employees, whether employed on a full-time, part-time, temporary or seasonal basis. As of December 31, 2020, we employed 699 such persons.  We annualized the compensation for any employees that were not employed for all of 2020 (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 2020 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 2020 compensation was as follows:

NameYearSalaryBonusStock AwardsNon-Equity Incentive Plan CompensationAll Other CompensationTotal
Median Employee2020$89,385$11,411$—$—$94$100,890

With respect to the annual total compensation of our CEO, we used the amount reported in the “Total” column of our 2020 Summary Compensation Table included in this Annual Report, which was $6,966,286. Our 2020 ratio of Chief Executive Officer total compensation to our median employee’s total compensation is reasonably estimated to be 69:1.


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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 18, 2021, 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 OwnedPercentage of Common Units Owned
Crestwood Gas Services Holdings LLC9,985,462 (2)(3)(4)13.4%
Crestwood Holdings LLC7,484,449 (2)(3)10.1%
ALPS Advisors, Inc.(5)
6,419,825 8.6%
Alvin Bledsoe26,611 (6)*
William Brown12,050 *
Steven M. Dougherty284,399 *
Warren H. Gfeller57,778 *
Robert T. Halpin400,509 *
Janeen S. Judah13,693 *
Joel C. Lambert232,156 *
David Lumpkins47,385 *
William H. Moore246,806 *
Robert G. Phillips779,466 1%
Gary D. Reaves9,377 *
John J. Sherman3,237,277 4.4%
Frances M. Vallejo5,795 
Directors and executive officers as a group (13 persons)5,353,302 (7)7.2%
* 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 9, 2021. The address of ALPS Advisors, Inc. is 1290 Broadway, Suite 1000, Denver, CO 80203.
(6) Excludes 19,952 restricted units held in the Crestwood Nonqualified Deferred Compensation Plan.
(7)    Excludes 373,277 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.
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
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.
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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.


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 year ending December 31, 2020. The following table summarizes the fees for professional services rendered by Ernst & Young LLP for the years ended December 31, 2020 and 2019 (in millions).
20202019
Audit-related fees(1)
$1.6 $1.9 
All other fees(2)
— 0.1 
Total$1.6 $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 2020. 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
2.2
2.3
3.1  
3.2  
3.3  
3.4   
3.5
3.6
3.7  
3.8  
92

Exhibit
Number
  Description
3.9  
3.10  
3.11
3.12
3.13
3.14
3.15
3.16
3.17
3.18
3.19
3.20
3.21
3.22
3.23
4.1  
4.2  
93

Exhibit
Number
  Description
4.3  
4.4  
4.5  
4.6
4.7
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
**4.17
94

Exhibit
Number
  Description
*10.1
*10.2
*10.3
*10.4
*10.5
*10.6
*10.7  
*10.8  
*10.9
*10.10  
*10.11
10.12
10.13
10.14
10.15
10.16
10.17
*10.19
95

Exhibit
Number
  Description
*10.20
*10.21
*10.22
*10.23  
*10.24
10.25
10.26
*10.27
16.1  
**21.1  
**22.1
**23.1  
**23.2
**31.1  
**31.2  
**31.3
**31.4
**32.1  
**32.2  
**32.3
**32.4
**99.1
**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
96

Exhibit
Number
  Description
**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
104Cover 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, 2020 and 2019 and for the years ended December 31, 2020, 2019 and 2018 (audited) pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09) and is filed herein as Exhibit 99.1.


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Crestwood Equity Partners LP
Crestwood Midstream Partners LP

Index to Financial Statements
 
Crestwood Equity Partners LP
Report of Independent Registered Public Accounting Firm
Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial Reporting
Audited Consolidated Financial Statements:
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Statements of Partners’ Capital
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Crestwood Midstream Partners LP
Report of Independent Registered Public Accounting Firm
Audited Consolidated Financial Statements:
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Partners’ Capital
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements

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Report of Independent Registered Public Accounting Firm

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

Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Crestwood Equity Partners LP (the Partnership) as of December 31, 2020 and 2019, 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, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, 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, 2020, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated February 26, 2021 expressed an unqualified opinion thereon.

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 Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Revenue recognition – Measuring variable consideration
Description of the MatterAs 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.
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How We Addressed the Matter in Our AuditWe obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership’s process to calculate the variable consideration, including the underlying assumptions about estimates of expected volumes.

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 forecasted volumes through comparison to analyst forecasted commodity prices and historical production 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 forecasted volumes.

/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2013.
Houston, Texas
February 26, 2021



100

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, 2020, 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, 2020, 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, 2020 and 2019 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, 2020, and the related notes and financial statement schedules listed in the Index at Item 15(a) of the Partnership and our report dated February 26, 2021 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.

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 26, 2021
101

CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(in millions, except unit information)
December 31,
20202019
Assets
Current assets:
Cash$14.0 $25.7 
Accounts receivable, less allowance for doubtful accounts of $0.9 million and $0.3 million at December 31, 2020 and 2019262.2 242.2 
Inventory89.1 53.7 
Assets from price risk management activities27.2 43.2 
Prepaid expenses and other current assets13.4 11.6 
Total current assets405.9 376.4 
Property, plant and equipment3,759.6 3,612.5 
Less: accumulated depreciation842.5 703.4 
Property, plant and equipment, net2,917.1 2,909.1 
Intangible assets1,126.1 1,076.3 
Less: accumulated amortization331.8 271.1 
Intangible assets, net794.3 805.2 
Goodwill138.6 218.9 
Operating lease right-of-use assets, net36.8 53.8 
Investments in unconsolidated affiliates943.7 980.4 
Other non-current assets7.3 5.5 
Total assets$5,243.7 $5,349.3 
Liabilities and capital
Current liabilities:
Accounts payable$160.3 $189.2 
Accrued expenses and other liabilities122.0 161.7 
Liabilities from price risk management activities76.3 6.7 
Contingent consideration - current19.0 
Current portion of long-term debt0.2 0.2 
Total current liabilities377.8 357.8 
Long-term debt, less current portion2,483.8 2,328.3 
Contingent consideration38.0 57.0 
Other long-term liabilities253.3 244.6 
Deferred income taxes2.7 2.6 
Total liabilities3,155.6 2,990.3 
Commitments and contingencies (Note 10)
00
Interest of non-controlling partner in subsidiary (Note 12)
432.7 426.2 
Crestwood Equity Partners LP partners' capital (73,970,208 and 72,282,942 common and subordinated units issued and outstanding at December 31, 2020 and 2019)1,043.4 1,320.8 
Preferred units (71,257,445 units issued and outstanding at December 31, 2020 and 2019)612.0 612.0 
Total partners’ capital1,655.4 1,932.8 
Total liabilities and capital$5,243.7 $5,349.3 
See accompanying notes.
102


CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per unit data)
Year Ended December 31,
 202020192018
Revenues:
Product revenues:
     Gathering and processing$240.2 $455.8 $670.5 
Marketing, supply and logistics1,552.8 2,296.6 2,639.2 
Related party (Note 19)
27.3 2.9 
1,820.3 2,755.3 3,309.7 
Service revenues:
     Gathering and processing391.2 380.0 276.1 
Storage and transportation13.8 20.4 17.1 
Marketing, supply and logistics28.5 26.2 50.2 
Related party (Note 19)
0.5 1.0 
434.0 426.6 344.4 
Total revenues2,254.3 3,181.9 3,654.1 
Costs of product/services sold (exclusive of items shown separately below):
Product costs1,558.8 2,469.7 2,950.5 
Product costs - related party (Note 19)
21.0 45.4 134.7 
Service costs20.7 29.8 44.2 
Total costs of products/services sold1,600.5 2,544.9 3,129.4 
Operating expenses and other:
Operations and maintenance131.8 138.8 125.8 
General and administrative91.5 103.4 88.1 
Depreciation, amortization and accretion237.4 195.8 168.7 
Loss on long-lived assets, net26.0 6.2 28.6 
Goodwill impairment80.3 
Gain on acquisition(209.4)
567.0 234.8 411.2 
103

CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per unit data)
Year Ended December 31,
 202020192018
Operating income86.8 402.2 113.5 
Earnings from unconsolidated affiliates, net32.5 32.8 53.3 
Interest and debt expense, net(133.6)(115.4)(99.2)
Gain (loss) on modification/extinguishment of debt0.1 (0.9)
Other income (expense), net(0.7)0.6 0.4 
Income (loss) before income taxes(14.9)320.2 67.1 
Provision for income taxes(0.4)(0.3)(0.1)
Net income (loss)(15.3)319.9 67.0 
Net income attributable to non-controlling partner40.8 34.8 16.2 
Net income (loss) attributable to Crestwood Equity Partners LP(56.1)285.1 50.8 
Net income attributable to preferred units60.1 60.1 60.1 
Net income (loss) attributable to partners$(116.2)$225.0 $(9.3)
Net income (loss) per limited partner unit: (Note 14)
Basic$(1.59)$3.11 $(0.13)
Diluted$(1.59)$2.93 $(0.13)
Weighted-average limited partners’ units outstanding:
Basic73.2 71.8 71.2 
Dilutive5.1 
Diluted73.2 76.9 71.2 

See accompanying notes.
104


CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)
 Year Ended December 31,
202020192018
Net income (loss)$(15.3)$319.9 $67.0 
Change in fair value of Suburban Propane Partners, L.P. units0.3 (0.7)
Comprehensive income (loss)(15.3)320.2 66.3 
Comprehensive income attributable to non-controlling partner40.8 34.8 16.2 
Comprehensive income (loss) attributable to Crestwood Equity Partners LP$(56.1)$285.4 $50.1 

See accompanying notes.

105

CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in millions)
PreferredPartners
UnitsCapitalCommon UnitsSubordinated UnitsCapitalNon-Controlling
Partner
Total Partners’ Capital
Balance at December 31, 201771.3 $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, 201871.3 612.0 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, 201971.3 612.0 71.9 0.4 1,320.8 1,932.8 
Distributions to partners— (60.1)— — (182.7)— (242.8)
Unit-based compensation charges— — 2.1 — 34.0 — 34.0 
Taxes paid for unit-based compensation vesting— — (0.6)— (15.6)— (15.6)
Other— — 0.2 — 3.1 — 3.1 
Net income (loss)— 60.1 — — (116.2)— (56.1)
Balance at December 31, 202071.3 $612.0 73.6 0.4 $1,043.4 $— $1,655.4 

See accompanying notes.
106


     
CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Year Ended December 31,
 202020192018
Operating activities
Net income (loss)$(15.3)$319.9 $67.0 
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion237.4 195.8 168.7 
Amortization of debt-related deferred costs6.5 6.2 6.8 
Unit-based compensation charges30.7 47.0 28.5 
Loss on long-lived assets, net26.0 6.2 28.6 
Goodwill impairment80.3 
Gain on acquisition(209.4)
(Gain) loss on modification/extinguishment of debt(0.1)0.9 
Earnings from unconsolidated affiliates, net, adjusted for cash distributions received6.5 6.9 0.5 
Deferred income taxes0.1 (0.7)
Other(0.1)0.2 
Changes in operating assets and liabilities:
Accounts receivable(27.5)42.9 167.8 
Inventory(33.7)10.9 (24.1)
Prepaid expenses and other current assets(3.7)0.1 (3.1)
Accounts payable, accrued expenses and other liabilities(1.2)(23.3)(138.6)
Reimbursements of property, plant and equipment15.7 24.8 21.7 
Change in price risk management activities, net86.5 (7.6)(70.6)
Net cash provided by operating activities408.1 420.4 253.6 
Investing activities
Acquisitions, net of cash acquired (Note 3)
(162.3)(462.1)
Purchases of property, plant and equipment(168.3)(455.5)(305.5)
Investments in unconsolidated affiliates(9.4)(61.3)(64.4)
Capital distributions from unconsolidated affiliates39.4 35.5 49.2 
Net proceeds from sale of assets27.3 0.8 79.5 
Other(1.1)
Net cash used in investing activities(273.3)(943.7)(241.2)
107

     
CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Year Ended December 31,
 202020192018
Financing activities
Proceeds from the issuance of long-term debt1,125.1 2,307.3 2,274.8 
Payments on long-term debt(975.8)(1,729.5)(2,015.7)
Payments on finance/capital leases(3.1)(3.5)(1.6)
Payments for deferred financing costs(9.0)(5.7)
Net proceeds from issuance of non-controlling interest2.8 235.0 
Distributions to partners(182.7)(172.4)(170.8)
Distributions to non-controlling partner(37.1)(25.0)(9.9)
Distributions to preferred unitholders(60.1)(60.1)(60.1)
Taxes paid for unit-based compensation vesting(15.6)(11.0)(7.4)
Other(0.1)
Net cash provided by (used in) financing activities(146.5)531.8 3.5 
Net change in cash and restricted cash(11.7)8.5 15.9 
Cash and restricted cash at beginning of period25.7 17.2 1.3 
Cash and restricted cash at end of period$14.0 $25.7 $17.2 
Supplemental disclosure of cash flow information
Cash paid for interest$129.8 $123.7 $97.4 
Cash paid for income taxes$0.6 $0.6 $3.1 
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued expenses$40.0 $(27.7)$0.3 

See accompanying notes.
108


Report of Independent Registered Public Accounting Firm

The Board of Directors of Crestwood Equity GP LLC

Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Crestwood Midstream Partners (the Partnership) as of December 31, 2020 and 2019, and the related consolidated statements of operations, partners’ capital and cash flows for each of the three years in the period ended December 31, 2020, 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, 2020 and 2019, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2020, in conformity with U.S. generally accepted accounting principles.

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.

Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of the critical audit matter 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 matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Revenue recognition – Measuring variable consideration
Description of the MatterAs 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
109

How We Addressed the Matter in Our AuditWe obtained an understanding, evaluated the design and tested the operating effectiveness of controls over the Partnership’s process to calculate the variable consideration, including the underlying assumptions about estimates of expected volumes.

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 forecasted volumes through comparison to analyst forecasted commodity prices and historical production 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 forecasted volumes.
/s/ Ernst & Young LLP

We have served as the Partnership’s auditor since 2013
Houston, Texas
February 26, 2021

110


CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(in millions)
December 31,
20202019
Assets
Current assets:
Cash$13.7 $25.4 
Accounts receivable, less allowance for doubtful accounts of $0.9 million and $0.3 million at December 31, 2020 and 2019262.2 241.9 
Inventory89.1 53.7 
Assets from price risk management activities27.2 43.2 
Prepaid expenses and other current assets13.4 11.6 
Total current assets405.6 375.8 
Property, plant and equipment4,089.6 3,942.6 
Less: accumulated depreciation1,028.3 875.1 
Property, plant and equipment, net3,061.3 3,067.5 
Intangible assets1,126.1 1,076.3 
Less: accumulated amortization331.8 271.1 
Intangible assets, net794.3 805.2 
Goodwill138.6 218.9 
Operating lease right-of-use assets, net36.8 53.8 
Investments in unconsolidated affiliates943.7 980.4 
Other non-current assets5.2 2.4 
Total assets$5,385.5 $5,504.0 
Liabilities and partners’ capital
Current liabilities:
Accounts payable$157.8 $186.6 
Accrued expenses and other liabilities120.1 160.4 
Liabilities from price risk management activities76.3 6.7 
Contingent consideration, current portion19.0 
Current portion of long-term debt0.2 0.2 
Total current liabilities373.4 353.9 
Long-term debt, less current portion2,483.8 2,328.3 
Contingent consideration38.0 57.0 
Other long-term liabilities251.8 238.6 
Deferred income taxes0.7 0.7 
Total liabilities3,147.7 2,978.5 
Commitments and contingencies (Note 10)
Interest of non-controlling partner in subsidiary (Note 12)
432.7 426.2 
Partners’ capital1,805.1 2,099.3 
Total liabilities and capital$5,385.5 $5,504.0 

See accompanying notes.

111


CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
 Year Ended December 31,
 202020192018
Revenues:
Product revenues:
Gathering and processing$240.2 $455.8 $670.5 
Marketing, supply and logistics1,552.8 2,296.6 2,639.2 
Related party (Note 19)
27.3 2.9 
1,820.3 2,755.3 3,309.7 
Service revenues:
Gathering and processing391.2 380.0 276.1 
Storage and transportation13.8 20.4 17.1 
Marketing, supply and logistics28.5 26.2 50.2 
Related party (Note 19)
0.5 1.0 
434.0 426.6 344.4 
Total revenues2,254.3 3,181.9 3,654.1 
Costs of product/services sold (exclusive of items shown separately below):
Product costs1,558.8 2,469.7 2,950.5 
Product costs - related party (Note 19)
21.0 45.4 134.7 
Service costs20.7 29.8 44.2 
Total costs of products/services sold1,600.5 2,544.9 3,129.4 
Operating expenses and other:
Operations and maintenance131.8 138.8 125.8 
General and administrative86.7 98.2 83.5 
Depreciation, amortization and accretion251.5 209.9 181.4 
Loss on long-lived assets, net26.0 6.2 28.6 
Goodwill impairment80.3 
Gain on acquisition(209.4)
576.3 243.7 419.3 
Operating income77.5 393.3 105.4 
Earnings from unconsolidated affiliates, net32.5 32.8 53.3 
Interest and debt expense, net(133.6)(115.4)(99.2)
Gain (loss) on modification/extinguishment of debt0.1 (0.9)
Other income, net0.2 
Income (loss) before income taxes(23.5)310.9 58.6 
(Provision) benefit for income taxes0.1