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
Table of Contents
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 Street Suite 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 LP
Yes
No
Crestwood Midstream Partners LP
Yes
No
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.     
Crestwood Equity Partners LP
Yes
No
Crestwood Midstream Partners LP
Yes
No
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Crestwood Equity Partners LP
Yes
No
Crestwood Midstream Partners LP
Yes
No


Table of Contents
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).
Crestwood Equity Partners LP
Yes
No
Crestwood Midstream Partners LP
Yes
No 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer”, “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act.
Crestwood Equity Partners LPLarge accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company
Emerging growth company
Crestwood Midstream Partners LPLarge accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange act.
Crestwood Equity Partners LP
Crestwood Midstream Partners LP
Indicate by check mark whether the registrant 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 LPYes
No
Crestwood Midstream Partners LPYes
No
State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (June 30, 2020).
Crestwood Equity Partners LP$0.7 billion
Crestwood Midstream Partners LPNone
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 LPNoneNone

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.



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FILING FORMAT

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

Item 15 of Part IV of this Annual Report includes separate financial statements (i.e., balance sheets, statements of operations, statements of comprehensive income, statements of partners’ capital and statements of cash flows, as applicable) for Crestwood Equity Partners LP and Crestwood Midstream Partners LP. The notes accompanying the financial statements are presented on a combined basis for each registrant. Management’s Discussion and Analysis of Financial Condition and Results of Operations included under Item 7 of Part II is presented for each registrant.
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CRESTWOOD EQUITY PARTNERS LP
CRESTWOOD MIDSTREAM PARTNERS LP
INDEX TO ANNUAL REPORT ON FORM 10-K

  Page

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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 Volumes Compression (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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Table of Contents
 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