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, 2021

OR

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

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

 

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

(832) 519-2200

(Registrant’s telephone number, including area code)

___________________________________________

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

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

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

Crestwood Equity Partners LP	None
Crestwood Midstream Partners LP	None

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

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

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

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

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

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

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

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

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

Crestwood Equity Partners LP	☐
Crestwood Midstream Partners LP	☐

Indicate by check mark whether the registrant 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 LP	Yes	☐	No	☒
Crestwood Midstream Partners LP	Yes	☐	No	☒

State the aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter (June 30, 2021).

Crestwood Equity Partners LP	$1.7 billion
Crestwood Midstream Partners LP	None

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date (February 18, 2022).

Crestwood Equity Partners LP	97,978,074
Crestwood Midstream Partners LP	None

DOCUMENTS INCORPORATED BY REFERENCE

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

Crestwood Equity Partners LP	Portions of Crestwood Equity Partners LP’s Proxy Statement for the 2022 Annual Meeting of Stockholders are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K
Crestwood Midstream Partners LP	None

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

FILING FORMAT

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

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

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CRESTWOOD EQUITY PARTNERS LP

CRESTWOOD MIDSTREAM PARTNERS LP

INDEX TO ANNUAL REPORT ON FORM 10-K

		Page
	PART I
Item 1.	Business	9
Item 1A.	Risk Factors	25
Item 1B.	Unresolved Staff Comments	45
Item 2.	Properties	45
Item 3.	Legal Proceedings	45
Item 4.	Mine Safety Disclosures	45
	PART II
Item 5.	Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities	46
Item 6.	Selected Financial Data	47
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	47
Item 7A.	Quantitative and Qualitative Disclosures about Market Risk	63
Item 8.	Financial Statements and Supplementary Data	64
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	64
Item 9A.	Controls and Procedures	64
Item 9B.	Other Information	65
	PART III
Item 10.	Directors, Executive Officers and Corporate Governance	66
Item 11.	Executive Compensation	66
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters	66
Item 13.	Certain Relationships and Related Transactions, and Director Independence	66
Item 14.	Principal Accountant Fees and Services	66
	PART IV
Item 15.	Exhibits, Financial Statement Schedules	67

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GLOSSARY

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

/d	per day
AOD	Area of dedication, which means the acreage dedicated to a company by an oil and/or natural gas producer under one or more contracts.
ASU	Accounting Standards Update
Barrels (Bbls)	One barrel of petroleum products equal to 42 U.S. gallons.
Bcf	One billion cubic feet of natural gas. A standard volume measure of natural gas products.
Cycle	A complete withdrawal and injection of working gas. Cycling refers to the process of completing one cycle.
EPA	Environmental Protection Agency
FERC	Federal Energy Regulatory Commission
GAAP	Generally Accepted Accounting Principles
HP	Horsepower
Hub	Geographic location of a storage facility and multiple pipeline interconnections
Hub services	With respect to our natural gas storage and transportation operations, the following services: (i) interruptible storage services, (ii) firm and interruptible park and loan services, (iii) interruptible wheeling services, and (iv) balancing services.
Injection rate	The rate at which a customer is permitted to inject natural gas into a natural gas storage facility.
MBbls	One thousand barrels
MMBbls	One million barrels
MMcf	One million cubic feet of natural gas
Natural gas	A gaseous mixture of hydrocarbon compounds, primarily methane together with varying quantities of ethane, propane, butane and other gases.
Natural Gas Act	Federal law enacted in 1938 that established the FERC’s authority to regulate interstate pipelines.
Natural gas liquids (NGLs)	Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. NGLs include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).
NYSE	New York Stock Exchange
SEC	Securities and Exchange Commission
Withdrawal rate	The rate at which a customer is permitted to withdraw gas from a natural gas storage facility.

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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.

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 decrease, resulting in a prolonged period of reduced midstream infrastructure development and service requirements to customers.

•The failure to successfully combine the businesses of Crestwood and Oasis Midstream may adversely affect Crestwood’s future results.

•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 Williston Basin, and due to such geographic concentration, adverse developments in the Williston Basin 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 storage 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 storage 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 storage and logistics operations and certain of our gathering and processing 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.

•A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.

•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.

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Risks Related to Regulatory Matters

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

•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.

•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 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 unitholder ownership interests.

•The market value of Crestwood common units could decline if large amounts of such units are sold following the merger with Oasis Midstream.

•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.

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

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

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.

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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, 2021.

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.

Recent Developments

Oasis Midstream Merger

On October 25, 2021, we entered into a merger agreement to acquire Oasis Midstream Partners LP (Oasis Midstream) in an equity and cash transaction (the Merger). On February 1, 2022, we completed the Merger with Oasis Midstream, under which Oasis Petroleum Inc. (Oasis Petroleum) received $150 million in cash plus approximately 21.0 million newly issued CEQP common units in exchange for its 33.8 million common units held in Oasis Midstream. In addition, Oasis Midstream’s public unitholders received approximately 12.9 million newly issued CEQP common units in exchange for the approximately 14.8 million Oasis Midstream common units held by them. Additionally, under the merger agreement Oasis Petroleum received a $10 million cash payment for its ownership of the general partner of Oasis Midstream. The Merger will result in us having exposure to approximately 1,200 drilling locations and 535,000 dedicated acres in the Williston Basin, expanding our operational footprint beyond the Fort Berthold Indian Reservation. Additionally, Oasis Midstream’s Wild Basin gathering and processing assets are complementary with our Arrow gathering system and Bear Den processing facility. For a further discussion of the Merger, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 20.

Stagecoach Gas Divestiture

In July 2021, Stagecoach Gas Services LLC (Stagecoach Gas) sold certain of its wholly-owned subsidiaries to a subsidiary of Kinder Morgan, Inc. (Kinder Morgan) for approximately $1.195 billion plus certain purchase price adjustments (Initial Closing) pursuant to a purchase and sale agreement dated as of May 31, 2021 between our wholly-owned subsidiary, Crestwood Pipeline and Storage Northeast LLC (Crestwood Northeast), Con Edison Gas Pipeline and Storage Northeast, LLC (CEGP), a wholly-owned subsidiary of Consolidated Edison, Inc., Stagecoach Gas and Kinder Morgan. Following the Initial Closing, in November 2021 Crestwood Northeast and CEGP sold each of their equity interests in Stagecoach Gas and its wholly-owned subsidiary, Twin Tier Pipeline LLC, (Second Closing) to Kinder Morgan. Crestwood Northeast and CEGP each received cash proceeds of approximately $15 million related to the Second Closing. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6.

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Ownership Structure

The diagram below reflects a simplified version of our ownership structure as of December 31, 2021:

In March 2021, Crestwood Equity entered into a purchase agreement with Crestwood Holdings LLC (Crestwood Holdings) pursuant to which it (i) acquired approximately 11.5 million CEQP common units, 0.4 million subordinated units of CEQP and 100% of the equity interests of Crestwood Marcellus Holdings LLC and Crestwood Gas Services Holdings LLC (whose assets consisted solely of CEQP common and subordinated units and 1% of the limited partner interests in Crestwood Holdings LP) in March 2021; and (ii) acquired the general partner and the remaining 99% limited partner interests of Crestwood Holdings LP (whose assets consist solely of its ownership interest in Crestwood Equity GP LLC, which owns CEQP’s non-economic general partner interest) in August 2021 (collectively, the Crestwood Holdings Transactions). Prior to the Crestwood Holdings Transactions, Crestwood Equity was indirectly owned by Crestwood Holdings, which was substantially owned and controlled by First Reserve Management, L.P. (First Reserve). See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 1 for a further discussion of the Crestwood Holdings Transactions.

Description of Our Assets

We conduct our operations and own our operating assets through Crestwood Midstream and its subsidiaries and our joint ventures. Our financial statements reflect three operating and reporting segments as of December 31, 2021: (i) gathering and processing north (includes our Williston and Powder River Basin operations); (ii) gathering and processing south (includes our Marcellus and Barnett operations as well as our Crestwood Permian Basin Holdings LLC equity method investment in the Delaware Basin); and (iii) storage and logistics (includes our crude oil, NGL and natural gas storage and logistics operations, and our Tres Palacios Holdings LLC and Powder River Basin Industrial Complex, LLC equity method investments). Our gathering and processing north and gathering and processing south segments were historically combined into one segment, and

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our storage and logistics segment was historically separated into a storage and transportation segment and a marketing, supply and logistics segment.

Gathering and Processing North Segment

Our gathering and processing north operations provide natural gas, crude oil and produced water gathering, compression, treating, processing and disposal services to producers in the Williston Basin and Powder River Basin. Our gathering and processing north segment’s operating assets consist of: (i) natural gas facilities with approximately 0.4 Bcf/d of gathering capacity and approximately 0.5 Bcf/d of processing capacity; (ii) crude oil facilities with approximately 150,000 Bbls/d of gathering capacity and 266,000 Bbls of storage capacity; and (iii) produced water facilities with approximately 130,000 Bbls/d of gathering and disposal capacity.

Williston Basin

We own and operate an integrated crude oil, rich natural gas and produced water gathering system, with a gas processing facility (Bear Den) and produced water disposal facilities, collectively the Arrow system, in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota, primarily located on the Fort Berthold Indian Reservation. The COLT Hub, a crude-by-rail facility located approximately 60 miles northwest of the Arrow system, connects to the Arrow system through the Tesoro High Plains Pipeline Company LLC’s, a subsidiary of Marathon Petroleum Corporation (Marathon), crude oil pipeline system allowing access to the Pacific Northwest markets. Crude oil gathered on the Arrow system can service Midwest refineries from Patoka, Illinois and the Gulf Coast via the Dakota Access Pipeline (DAPL) or the Guernsey, Wyoming markets through the Kinder Morgan Inc. (Kinder Morgan) Double H Pipeline and the True Pipeline system. In addition to the multiple pipeline take-away outlets, the Arrow system has 266,000 Bbls of crude oil working storage capacity. The Bear Den facility and associated pipelines at the Arrow system fulfill nearly all of the processing requirements for producers on the Arrow system. Our operations are anchored by long-term gathering contracts that 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 rich natural gas gathering system and Bucking Horse gas processing facility in Converse County, Wyoming, which connects to 157 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 15 years and provides minimum revenue guarantees for three years.

The table below details certain information about our gathering and processing north segment as of December 31, 2021:

Basin (State)	Counties	Pipeline (Miles)	Gathering Capacity	2021 Average Gathering Volumes	Compression (HP)	Number of In-Service Processing Plants	Processing Capacity (MMcf/d)	Gross Acreage Dedication
Williston Basin North Dakota	McKenzie and Dunn	709(1)	150 MMcf/d - natural gas 150 MBbls/d - crude oil 130 MBbls/d - produced water	139 MMcf/d - natural gas  88 MBbls/d - crude oil  86 MBbls/d - produced water	86,450	1	140	150,000
Powder River Basin Wyoming	Converse	360	241 MMcf/d	101 MMcf/d	90,235	2	345	399,000

(1)Consists of 267 miles of natural gas gathering pipeline, 223 miles of crude oil gathering pipeline, and 219 miles of produced water gathering pipeline.

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The table below summarizes certain contract information of our gathering and processing north segment as of December 31, 2021:

Basin	Type of Contracts(1)	Weighted Average Remaining Contract Terms (in years)	Major Customers
Williston Basin	Mixed	8	Devon Energy Corporation, Rimrock Oil & Gas, LP, Enerplus Resources (USA) Corporation
Powder River Basin	Fixed-fee	15	Chesapeake

(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 percentage-of-proceeds and fixed-fee arrangements.

Our gathering and processing north segment provides gathering, processing, compression, storage and transportation services under a variety of contracts. Although the cash flows from these operations are predominantly fee-based under contracts with remaining terms ranging from 3-15 years, the results of our operations are significantly influenced by the volumes gathered and processed through our systems. The cash flows from these 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 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.

Gathering and Processing South Segment

Our gathering and processing south operations provide natural gas gathering, compression, treating and processing and produced water gathering and disposal services to producers in the Marcellus, Barnett and Delaware basins. Our gathering and processing south segment’s operating assets consist of: (i) natural gas facilities with 2.5 Bcf/d of gathering capacity and 0.7 Bcf/d of processing capacity; and (iii) produced water facilities with approximately 75,000 Bbls/d of gathering and disposal capacity.

Marcellus

We own and operate rich 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 eight compression and dehydration stations with 113,000 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 customer’s 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 Victoria compressor station, which has a maximum capacity of 120 MMcf/d.

Barnett

We own and operate three systems in the Barnett Shale, including the Cowtown, Lake Arlington and Alliance systems. Our Cowtown system, which is located in Hood, Somervell and Johnson Counties, Texas, consists of pipelines that gather and deliver rich gas produced by customers 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

We own a 50% equity interest in Crestwood Permian Basin Holdings LLC (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) the Willow Lake system, which includes low-pressure dry gas and rich natural gas gathering systems 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 Willow Lake

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system with the Orla plant; and (iv) a produced water gathering and disposal system capable of handling 75,000 Bbls/d of produced water in Culberson and Reeves Counties, Texas.

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, and includes an interconnection with Chevron Phillips Chemical Company, LP’s (Chevron Phillips) pipeline, and other delivery points near Benedum. This capacity is supported, in part, 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 also owns a 50% equity interest in Crestwood Permian Basin LLC (Crestwood Permian Basin) and Shell Midstream Partners L.P. (Shell Midstream), a subsidiary of Royal Dutch Shell plc, owns the remaining 50% equity interest. Crestwood Permian Basin owns the Nautilus natural gas gathering system which includes 166 miles of gathering pipelines, a 43-mile high pressure header system, 45,000 horsepower of compression, 109 receipt meters 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 fixed fee gathering agreement with Permian Delaware Enterprise Holdings LLC (Permian Delaware Enterprise), a subsidiary of ConocoPhillips Company (ConocoPhillips), under which Permian Delaware Enterprise has dedicated the gathering rights for its gas production across a large acreage position in Loving, Reeves and Ward Counties, Texas to Crestwood Permian Basin, and under which Crestwood Permian Basin provides gathering and dehydration services to them.

The table below details certain information about our gathering and processing south segment (including our equity investment and its operations) as of December 31, 2021:

Basin (State)	Counties	Pipeline (Miles)	Gathering Capacity	2021 Average Gathering Volumes	Compression (HP)	Number of In-Service Processing Plants	Processing Capacity(4) (MMcf/d)	Gross Acreage Dedication
Marcellus West Virginia	Harrison and Doddridge	72	875 MMcf/d	227 MMcf/d	113,000	—	—	140,000
Barnett Texas	Hood, Somervell, Tarrant, Johnson and Denton	388	925 MMcf/d	218 MMcf/d	153,465	1	425	140,000
Delaware Basin(1) New Mexico/Texas	Eddy (New Mexico) Loving, Reeves, Ward and Culberson (Texas)	322(2)	650 MMcf/d - natural gas 75 MBbls/d - produced water	229 MMcf/d - natural gas 40 MBbls/d - produced water	85,455(3)	1	255	359,000

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

(2)Consists of 308 miles of natural gas gathering pipeline and 14 miles of produced water gathering pipeline.

(3)Includes 45,000 HP that is owned and operated by a third party under a compression services agreement.

(4)Includes capacity of processing plants that are in service and not in service.

The table below summarizes certain contract information of our gathering and processing south segment (including our equity investment and its operations) as of December 31, 2021:

Basin	Type of Contracts(1)	Weighted Average Remaining Contract Terms (in years)	Major Customers
Marcellus	Fixed-fee	10	Antero Resources Corporation
Barnett	Mixed	5	Diversified Energy Company plc, FDL Operating LLC
Delaware	Fixed-fee	13	Permian Delaware Enterprise, Mewbourne Oil Company (Mewbourne)
	Percentage-of-proceeds	6	Mewbourne, ConocoPhillips

(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 percentage-of-proceeds and fixed-fee arrangements.

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Our gathering and processing south segment provides gathering, processing, compression, disposal and transportation services under a variety of contracts. Although the cash flows from these operations are predominantly fee-based under contracts with remaining terms ranging from 1-16 years, the results of our operations are significantly influenced by the volumes gathered and processed through our systems. The cash flows from these 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 dedications helps minimize our long-term exposure to commodity prices and provides us more stable operating performance and cash flows.

Storage and Logistics Segment

Our storage and logistics operations provide NGL, crude oil and natural gas storage, terminal, marketing and transportation (including rail, truck and pipeline) services to producers, refiners, marketers, utilities and other customers.

Below is a description of our storage and logistics operating assets, including those of our equity method investments.

•NGL Storage Facilities. Consists of approximately 10 MMBbls of NGL storage capacity 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.

•NGL Terminals and Transportation. Includes 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.

•COLT Hub. The COLT Hub consists of our integrated crude oil loading, storage and pipeline terminal located in the heart of the Williston Basin 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 Kinder Morgan 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 and truck unloading racks connected to the COLT Hub can deliver up to approximately 290,000 Bbls/d of crude oil to our terminal.

•Powder River Basin Crude Oil Facilities. We own a 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 through an eight-bay truck unloading rack. 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.

•Natural Gas Storage Facility. We own a 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, with a FERC-certificated maximum injection rate of 1,000 MMcf/d and a maximum withdrawal rate of 2,500 MMcf/d. 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 summarizes certain contract information about our COLT Hub operations and our Tres Holdings equity investment as of December 31, 2021:

Facility	Type of Contracts(1)	Weighted Average Remaining Contract Terms	Major Customers
COLT	Fixed-Fee, Firm	Less than 1 year	BP Products North America, Inc. (BP), Flint Hills Resources
Tres Palacios	Firm(2)	2 years	Trafigura Trading LLC, Hartree Partners LP, BP

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

(2)Tres Palacios has approximately 28.8 Bcf of firm storage contracts at December 31, 2021.

The cash flows from our COLT Hub operations are predominantly fee-based under contracts with terms ranging from six months to 1 year. Our current cash flows from crude-by-rail facilities are supported by 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. The cash flows from our Tres Palacios joint venture are predominantly fee-based under contracts with remaining terms ranging from 1 to 6 years. Cash flows from interruptible and other hub services provided by our Tres Palacios joint venture tend to increase during the peak winter season. The cash flows from our other storage and logistics operations 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.

Major Customers

For the years ended December 31, 2021 and 2020, no customer accounted for more than 10% of our total consolidated revenues. For the year ended December 31, 2019, BP and its affiliates accounted for approximately 10% of our total consolidated revenues.

Competition

Our gathering and processing 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 gathering and processing 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.

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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) and moderate consequence areas (MCAs) along pipelines and take additional safety measures to protect people and property in these areas. The HCAs for natural gas pipelines are predicated on high-population areas (which, for natural gas transmission lines, include Class 3 and 4 areas and, depending on the potential impacts of a risk event, may include Class 1 and 2 areas) whereas HCAs along crude oil and NGL pipelines are based on high-population density areas, in addition to certain drinking water sources and unusually sensitive ecological areas. A MCA is attributable to natural gas pipelines and is based on high-population areas as well as certain principal, high-capacity roadways, though it does not meet the definition of a natural gas pipeline HCA. 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), the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (2016 Pipeline Safety Act) and, most recently, the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (2020 Pipeline Safety Act). Each of these laws imposed increased pipeline safety obligations on pipeline operators. 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, 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. The 2020 Pipeline Safety Act reauthorized PHMSA through fiscal year 2023 and directed the agency to move forward with several regulatory initiatives, including obligating 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.

With the adoption of the 2011 Pipeline Safety Act, the 2016 Pipeline Safety Act and the 2020 Pipeline Safety Act, there exist mandates for PHMSA to make pipeline safety requirements more stringent, 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 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.

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•Natural Gas Rulemaking. In October 2019, PHMSA published a final rule for certain natural gas pipelines that imposes numerous requirements, including maximum allowable operating pressure (MAOP) reconfirmation and exceedance reporting, the integrity assessment of additional pipeline mileage found in MCAs and Class 3 and Class 4 non-HCAs by 2039 unless the pipeline cannot be modified to permit such accommodation, and the consideration of seismicity as a risk factor in integrity management.

•Hazardous Liquids Rulemaking. In October 2019, PHMSA published a final rule that significantly extends and expands the reach of certain PHMSA integrity management requirements for hazardous liquid pipelines, including, for example, performance of periodic assessments and expanded use of leak detection systems, regardless of the pipeline’s proximity to 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 by 2039 unless the pipeline cannot be modified to permit such accommodation. 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.

•Natural Gas Gathering Lines Rulemaking. In November 2021, PHMSA issued a final rule that will impose safety regulations on approximately 400,000 miles of previously unregulated onshore gas gathering lines that, among other things, will impose criteria for inspection and repair of fugitive emissions, extend reporting requirements to all gas gathering operators and apply a set of minimum safety requirements to certain gas gathering pipelines with large diameters and high operating pressures.

Separately, in June 2021, PHMSA issued an Advisory Bulletin advising pipeline and pipeline facility operators of applicable requirements to update their inspection and maintenance plans for the elimination of hazardous leaks and minimization of natural gas released from pipeline facilities. PHMSA, together with state regulators, is expected to commence inspection of these plans in 2022. 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 2020 Pipeline Safety Act, as well as any implementation of PHMSA regulations thereunder, or any issuance or reinterpretation of guidance by PHMSA or any state agencies with respect thereto, could require us to install new or modified safety controls, pursue additional capital projects or conduct maintenance programs on an accelerated basis, any or all of which tasks could result in our incurring increased operating costs that could have a material adverse effect on our results of operations or financial position.

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 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

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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 to federal, 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 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.

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

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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 (the 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 the BLM. However, Native American tribes possess certain inherent authorities to enact and enforce their own internal laws and regulations as long as such laws and regulations do not supersede or conflict with such federal statutes. These tribal laws and regulations may include various fees, taxes and requirements to extend preference in employment to tribal members or Indian owned businesses. Further, lessees and operators within a Native American reservation may be subject to the pertinent Native American judiciary system, or barred from litigating matters adverse to the pertinent tribe unless there is a specific waiver of the tribe’s sovereign immunity. Therefore, we may be subject to various applicable laws and regulations pertaining to Native American oil and gas leases, fees, taxes and other burdens, obligations and issues unique to oil and gas operations within Native American reservations. One or more of these applicable regulatory requirements, or delays in obtaining necessary approvals or permits necessary to operate on tribal lands, may increase our costs of doing business on Native American tribal lands and have an impact on the economic viability of any well or project within 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’s 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

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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 natural gas storage operations of our Tres Holdings equity investment is subject to regulation by the FERC under the Natural Gas Act. 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 equity investment are found in the FERC-approved tariff of Tres Palacios, a wholly-owned subsidiary of Tres Holdings that owns the Tres Palacios natural gas storage facility. Tres Palacios is authorized to charge and collect market-based rates for storage services. Market-based authority allows our equity investment to negotiate rates with individual customers based on market demand. A loss of market-based authority or any successful complaint or protest against the rates charged or provided by our equity investment 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.

NGLs Transportation

The transportation of 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 restrictions, delays or cancellations in permitting or the development of projects; and (iv) issuance of injunctions restricting or prohibiting some or all of the activities in a particular area.

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

•The Comprehensive Environmental Response, Compensation and Liability Act, a remedial statute that imposes strict liability on generators, transporters, 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 generation, 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;

•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 to 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 these water spills.

It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us as well as the industry in general or otherwise adversely affect demand for our services. For example, in 2015, the EPA issued a final rule under the 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, in December 2020, published notice of a final action to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups have filed

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litigation over this December 2020 decision and the Biden Administration has announced plans to reconsider the December 2020 final action in favor of a more stringent ground-level ozone NAAQS. 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. In another example, there continues to be uncertainty on the federal government’s applicable jurisdictional reach under the Clean Water Act over waters of the United States, including wetlands and the EPA and the U.S. Army Corps of Engineers (Corps) under the Obama, Trump and Biden Administrations have pursued multiple rulemakings since 2015 in an attempt to determine the scope of such reach. While the EPA and Corps under the Trump Administration issued a final rule in April 2020 narrowing federal jurisdictional reach over waters of the United States, President Biden issued an executive order in January 2021 to further review and assess these regulations consistent with the new administration’s policy objectives, following which the EPA and Corps announced plans in June 2021 to initiate a new rulemaking process that would repeal the 2020 rule and restore protections that were in place prior to 2015. Although the EPA and Corps did not seek to vacate the 2020 rule on an interim basis, two federal district courts in Arizona and New Mexico have vacated the 2020 rule in decisions announced during the third quarter of 2021. While these district court decisions may be appealed, it is clear that the EPA and Corps intend to adopt a more expansive definition for waters of the United States. As an initial step, the agencies published on December 7, 2021 a proposed rulemaking that would put back into place the pre-2015 definition of “waters of the United States” in effect prior to the 2015 rule issued under the Obama Administration and update it to reflect consideration of Supreme Court decisions. The proposed rule, if adopted would serve as an interim approach to “waters of the United States” and provide the agency with time to develop a subsequent rule that builds upon the currently proposed rule based, in part, on additional stakeholder involvement. To the extent that the EPA and the Corps under the Biden Administration issues a final rule that 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.

In addition to the laws and regulations described above, the potential impact of climate change continues to attract considerable attention in the United States and in other countries and, 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. However, the EPA has determined that GHG emissions present a danger to public health and the environment and has adopted regulations to restrict emissions of GHGs under existing provisions of the Clean Air Act that, among other things, establish 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. Compliance with these rules or other initiatives could result in increased compliance costs on our operations. In November 2021, the EPA issued a proposed rule that would make methane emissions from the crude oil and natural gas sources category more stringent, by establishing Quad Ob new source and Quad Oc first-time existing source standards of performance for methane and volatile organic compound (VOC) emissions. The EPA plans to issue a supplemental proposal enhancing this proposed rulemaking in 2022 that will contain additional requirements not included in the November 2021 proposed rule and the agency anticipates issuing a final rule by the end of 2022.

Additionally, various states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, the United Nations has sponsored the Paris Agreement, which is a non-binding agreement for nations to limit their GHG emissions through individually-determined reduction goals every five years after 2020. President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50-52% from 2005 levels in economy-wide net GHG emissions by 2030. Moreover, the international community gathered in Glasgow in November 2021 at the 26th Conference of the Parties (COP26), during which multiple announcements (not having the effect of law) were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced at COP26 the launch of a Global Methane Pledge, an initiative which over 100 countries joined, committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.

Additionally, our access to capital may be impacted by climate change policies. Shareholders and bondholders currently invested in fossil fuel energy companies such as ours but concerned about the potential effects of climate change may elect in

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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 that favor “clean” power sources, such as wind and solar, making those sources more attractive, and some of them may elect not to provide funding for fossil fuel energy companies. Many banks have made “net zero” carbon emission commitments and have announced that they will be assessing financed emissions across their portfolios and taking steps to quantify and reduce those emissions. These and other developments in the financial sector could lead to some lenders restricting access to capital for or divesting from certain industries or companies, including the oil and natural gas sector, or requiring that borrowers take additional steps to reduce their GHG emissions. Additionally, there is the possibility that financial institutions may be pressured or required to adopt policies that limit funding for fossil fuel energy companies. While we cannot predict what policies may result from these announcements, a material reduction in the capital available to the fossil fuel industry could make it more difficult to secure funding for exploration, development, production, transportation, and processing activities, which could impact our business and operations. Furthermore, the SEC has announced that it will propose rules that, amongst other matters, will establish a framework for the reporting of climate risks. However, no such rules have been proposed to date and we cannot predict what any such rules may require. To the extent the rules impose additional reporting obligations, we could face increased costs. Separately, the SEC has also announced that it is scrutinizing existing climate-change related disclosures in public filings, increasing the potential for enforcement if the SEC were to allege an issuer’s existing climate disclosures are misleading or deficient.

Finally, increasing concentrations of greenhouse gas in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events, as well as chronic shifts in temperature and precipitation patterns. These climatic developments have the potential to cause physical damage to our assets and thus could have an adverse effect on our operations. Additionally, changing meteorological conditions may result in changes to the amount, timing, or location of demand for energy, thus potentially impacting the demand for our services. While our consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.

Increasing attention to climate change, societal expectations for companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and customer demand for alternative forms of energy may result in increased costs, reduced demand for our services, reduced profits, increased risks of governmental investigations and private party litigation, and negative impacts on our stock price and access to capital markets. Increasing attention to climate change and environmental conservation, for example, may result in demand shifts from oil and natural gas products and bias against companies operating in the sector. To the extent that societal pressures or political or other factors are involved, it is possible that such liability could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.

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 ratings and recent activism directed at shifting funding away from companies with fossil fuel energy-related assets could 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.

Human Capital

As of December 31, 2021, we had 645 full-time employees, 254 of which were general and administrative employees and 391 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. Our commitment to Diversity and Inclusion (D&I) is advanced by our Chief Diversity Officer and our internal D&I committee pursuant to 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. During 2021, we demonstrated our commitment to D&I by conducting our first ever trainings on unconscious bias in the workplace and indigenous cultural awareness, hosting an

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internship program where over half of the participants came from diverse backgrounds, and focusing our community involvement and giving on D&I, such that over 40% of our volunteer hours and donations involved D&I organizations in the areas in which we work. Each of these D&I accomplishments were factored into our employees’ short-term incentive compensation for 2021, and we were able to exceed the targeted goals for each of those areas during 2021.

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. 99.9% of our employees completed their assigned training in these areas during the year ended December 31, 2021.

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 11% during the year ended December 31, 2021 compared to 8% during the year ended December 31, 2020 and was impacted by the COVID-19 pandemic and its impact on the labor markets.

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) and lagging indicators (i.e., incident and injury rates), certain of which are factored into our employees’ short-term incentive compensation each year. During 2021, we exceeded all of our core safety goals and targets, and achieved a total recordable incident rate of 1.10, a days away restricted transferred rate of 0.66 and a preventable vehicular incident rate of 0.66 for the year ended December 31, 2021.

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;

•disruptions of financial and credit markets, including inflation, which affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements;

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

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

•competition from imported supplies and alternate fuels;

•commodity price changes that could negatively impact the supply of, or the demand for these products;

•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 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 north and south segments’ results. With West Texas Intermediate crude oil prices ranging from $47.47 to $84.64 per barrel in 2021, the sustainability of recent prices improvements and longer-term oil prices cannot be predicted. These commodity price impacts could have a negative impact on our business, financial condition and results of operations.

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 2021 and 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

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and commodity markets. The effects of the COVID-19 pandemic 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 during 2020. As a result, many producers, including some of our customers, curtailed some of their short-term drilling and production activity and reduced or slowed down their plans for future drilling and production activity. This decrease in activity 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 reducing 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 decrease, 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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The failure to successfully combine the businesses of Crestwood and Oasis Midstream may adversely affect Crestwood’s future results.

The success of the Merger will depend, in part, on the ability of Crestwood to realize the anticipated benefits from successfully combining the businesses of Crestwood and Oasis Midstream. If the combined entity is not able to achieve these objectives, the anticipated benefits of the Merger may not be realized fully or at all or may take longer to realize than expected. In addition, the actual integration may result in additional and unforeseen costs, which could reduce the anticipated benefits of the Merger.

Crestwood and Oasis Midstream, including their respective subsidiaries, have operated independently until the completion of the Merger. It is possible that the integration process could result in material challenges, including the diversion of management’s attention from ongoing business concerns, the loss of key employees, the possibility of faulty assumptions underlying expectations regarding the integration process and associated costs, consolidating corporate and administrative infrastructure and eliminating duplicative operations, as well as the disruption of each company’s ongoing businesses or inconsistencies in their standards, controls, procedures and policies.

Any or all of those occurrences could adversely affect the combined company’s ability to maintain relationships with customers and employees after the Merger or to achieve the anticipated benefits of the Merger. Integration efforts between the two companies will also divert management attention and resources. These integration matters could have an adverse effect on the combined entity.

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.

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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.

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 Williston Basin, 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 Williston Basin. These operations accounted for approximately 55% of our total revenues, less of costs of product/services sold, for the year ended December 31, 2021. 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

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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 was 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 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 storage 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 storage 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 storage 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 storage 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.

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Our storage and logistics operations and certain of our gathering and processing 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 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.

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

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

We compete with other energy midstream enterprises, some of which are much larger and have significantly greater financial resources or operating experience, in our areas of operation. 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 $2.1 billion of long-term debt outstanding as of December 31, 2021. 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

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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;

•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.

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 3.50 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 a change of control of Crestwood Equity’s general partner. If these provisions are triggered, our outstanding indebtedness may become due. 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 to enter into a transaction which

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would trigger the change of control provision. In certain circumstances, the control of our general partner may be transferred to a third party without unitholder consent, and this may be considered a change in control under our revolving credit facility and senior notes. Please read “The control of our general partner may be transferred to a third party without unitholder consent.”

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

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

A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.

A downgrade of our credit ratings may increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:

•economic downturns;

•deteriorating capital market conditions;

•declining market prices for crude oil, natural gas, NGLs and other commodities;

•terrorist attacks or threatened attacks on our facilities or those of other energy companies; and

•the overall health of the energy industry, including the bankruptcy or insolvency of other companies.

Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.

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.

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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, Tres Holdings 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 contrary to our policies or objectives, and disputes between us and our joint venture partners may result in delays, litigation or operational impasses. The risks described above or the failure to continue our joint ventures or to resolve disagreements with our joint venture partners could adversely affect our ability to conduct business that is the subject of a joint venture, which could in turn negatively affect our financial condition and results of operations.

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

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

Our primary exposure to market risk occurs at the time contracts expire and are subject to renegotiation and renewal. As of December 31, 2021, the weighted average remaining term of our consolidated portfolio of natural gas gathering contracts is approximately nine years, and our consolidated portfolio of crude oil gathering contracts is approximately eight 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.

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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 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. We are also not insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could result in a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

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

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

We do not own all of the land on which our pipelines and facilities (particularly our gathering and processing 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. Easements and rights-of-way exists for varying periods of time. 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 2017 court decision issued 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. 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’

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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 ransomware demands, 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 updating our systems with recent patches and updates from our software providers and 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 such a breach has not already occurred and we are unaware of it, and that we will not suffer such a loss in the future.

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

Several jurisdictions in which we operate throughout the United States may have laws governing how we must respond to a cyber incident that results in the unauthorized access, disclosure or loss of personal data. Additionally, new laws and regulations governing cybersecurity, data privacy and unauthorized disclosure of confidential information, including international comprehensive data privacy regulations and recent U.S. state legislation in California, Virginia and Colorado (some of 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 and report any cyber incidents to the applicable regulatory authorities. In particular, in response to recent ransomware attacks, the Department of Homeland Security has issued a security directive to certain pipeline companies requiring the companies to appoint personnel, perform cybersecurity assessments, and report incidents and other information. Any failure by us, or a company we acquire, to comply with such laws and regulations could result in reputational harm, loss of goodwill, penalties, liabilities, and/or mandated changes in our business practices.

Risks Related to Regulatory Matters

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

Increasing attention to climate change, societal expectations for companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and customer demand for alternative forms of energy may result in increased costs, reduced demand for our services, reduced profits, increased risks of governmental investigations and private party litigation, and negative impacts on our common unit price and access to capital markets. Additionally, there are 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. Unfavorable ESG ratings could 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 capital and costs of capital. See Item 1. Business,“Regulation - Environmental and Occupational Safety and Health Matters” for a further discussion of these matters.

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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. 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.

The FERC issued a Notice of Inquiry (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.

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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.

Our and our customers’ operations are subject to various risks arising out of the threat of climate change, energy conservation measures, or initiatives that stimulate demand for alternative forms of energy that could result in increased costs, limit the areas in which oil and natural gas production may occur and reduced demand for our services.

Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change, energy conservation measures, or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce the demand for the crude oil and natural gas. Risks arising out of the threat of climate change, fuel conservation measures, governmental requirements for renewable energy resources, increasing customer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices may create new competitive conditions that result in reduced demand for the crude oil and natural gas our customers produce and our services. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. See Part I, Item 1. Business, “Regulation - Environmental and Occupational Safety and Health Matters” for further discussion relating to risks arising out of the threat of climate change and emission of GHGs, climate change activism, energy conservation measures or initiatives that stimulate demand for alternative forms of energy, and physical effects of climate change. 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

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

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

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

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

•prevailing economic and market conditions;

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

•changes in tax laws;

•the level of competition from other midstream companies;

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

•the level of capital expenditures we make;

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

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

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

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

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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 unitholder 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.

The market value of Crestwood’s common units could decline if large amounts of such units are sold following the merger with Oasis Midstream.

As of February 1, 2022, Oasis Petroleum owned approximately 21.6% of our common units. We cannot predict the effect that issuances and sales of our common units after the merger, including issuances and sales in connection with capital markets transactions, acquisition transactions or other transactions, may have on the market value of our common units. The issuance and sale of substantial amounts of our common units, including those owned by Oasis Petroleum and its affiliates, could adversely affect the market value of such units.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units and has other governance differences from typical corporations.

Unitholders’ voting rights are restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence our management. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership due to the absence of a takeover premium in the trading price or other governance differences.

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

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

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

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

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

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

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

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. The new owner of our general partner would then be in a position, subject to obtaining any approvals or consents required under the applicable governing documents, 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.”

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

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

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

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

•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

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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.

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 and therefore would have eliminated 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 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 their investment in our units.

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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 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.

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

In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, under the Tax Cuts and Jobs Act, for taxable years beginning after December 31, 2017, our deduction for business interest is limited to the sum of our business interest income and 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, the 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 and other guidance from the IRS 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, 2023. Thereafter, the obligation to withhold on a transfer of interests in a publicly traded partnership that is effected through a broker is imposed on the transferor’s broker. Current and prospective non-U.S. unitholders should consult their tax advisors regarding the impact of these rules on an investment in 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.

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.

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

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

At the close of business on February 18, 2022, Crestwood Equity had 97,978,074 common units issued and outstanding, which were held by 230 unitholders of record.

Issuer Purchases of Equity Securities

On March 30, 2021, Crestwood Gas Services Holdings LLC, a company controlled by an investment fund sponsored by First Reserve, closed on a private placement of six million common units representing limited partner interests of CEQP for gross proceeds of $132 million. CEQP did not sell any common units and did not receive any proceeds from the private placement. The securities offered in the private placement were not registered under the Securities Act of 1933, as amended or any state securities laws, and were sold in reliance upon the exemption provided in Section 4(a)(7) of the Securities Act of 1933.

The table below presents the CEQP’s common unit repurchase activity for the year ended December 31, 2021:

	Total Number of Units Repurchased(1)	Weighted-Average Price Paid Per Unit		Units Purchased as Part of Publicly Announced Programs	Maximum Dollar Value That May Yet Be Repurchased Under the Program(2)
January 1, 2021 - January 31, 2021	—	$	—	—	$	—
February 1, 2021 - February 28, 2021	—	$	—	—	$	—
March 1, 2021 - March 31, 2021	11,469,911	$	22.49	—	$	175,000,000
First Quarter 2021	11,469,911	$	22.49	—
April 1, 2021 - April 30, 2021	—	$	—	—	$	—
May 1, 2021 - May 31, 2021	—	$	—	—	$	—
June 1, 2021 - June 30, 2021	—	$	—	—	$	—
Second Quarter 2021	—	$	—	—
July 1, 2021 - July 31, 2021	—	$	—	—	$	—
August 1, 2021 - August 31, 2021	—	$	—	—	$	—
September 1, 2021 - September 31, 2021	—	$	—	—	$	—
Third Quarter 2021	—	$	—	—
October 1, 2021 - October 31, 2021	—	$	—	—	$	—
November 1, 2021 - November 30, 2021	—	$	—	—	$	—
December 1, 2021 to December 31, 2021	—	$	—	—	$	—
Fourth Quarter 2021	—	$	—	—
Year Ended 2021	11,469,911	$	22.49	—

(1)All units repurchased during the year ended December 31, 2021 were purchased pursuant to the Crestwood Holdings Transactions described in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 1.

(2)On March 25, 2021, CEQP’s board of directors approved a plan to repurchase common and preferred units in one or more open-market transactions or in privately negotiated transactions, with an aggregate purchase price not to exceed $175 million exclusive of any fees, commissions or other expenses. The repurchase program expires December 31, 2022. No units were purchased under the program during the year ended December 31, 2021.

Equity Compensation Plan Information

For information on our equity compensation plans, see Part III, Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13.

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Item 6. Selected Financial Data

This information has been omitted from this report pursuant to the final SEC rules in Release No. 34-90459 which permits the elimination of Item 301 of Regulation S-K.

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

Our Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our consolidated financial statements and the accompanying footnotes, and Part I, Item 1. Business - Assets.

A comparative discussion of our 2020 operating results to our 2019 operating results can be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K for the year ended December 31, 2020 filed with the SEC on February 26, 2021.

Overview

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

Our Company

We provide broad-ranging services to customers across the crude oil, natural gas and NGL sectors of the energy value chain. Our midstream infrastructure is geographically located in or near significant supply basins, especially developed and emerging liquids-rich and crude oil shale plays, across the United States. We believe that our strategy of focusing on prolific, low-cost shale plays positions us well to generate greater returns in varying commodity price environments and capture greater upside economics when development activity occurs.

In conjunction with the divestiture of our Stagecoach Gas equity method investment described in Outlook and Trends below, and the definitive merger agreement we entered into with Oasis Midstream, also described in Outlook and Trends below, we modified our segments as of December 31, 2021 and, as a result, our financial statements reflect three operating and reporting segments: (i) gathering and processing north (includes our Williston Basin and Powder River Basin operations); (ii) gathering and processing south (includes our operations in the Marcellus and Barnett shales as well as our Crestwood Permian Basin Holdings LLC equity method investment in the Delaware Basin); and (iii) storage and logistics (includes our crude oil, NGL and natural gas storage and logistics operations, the COLT Hub, and our Tres Holdings and PRBIC equity method investments). Our gathering and processing north and gathering and processing south segments were historically combined into one segment, and our storage and logistics segment was historically separated into a storage and transportation segment and a marketing, supply and logistics segment.

Below is a summary of our operating and reporting segments. For a detailed description of the assets included in our operating and reporting segments, see Part I, Item 1. Business.

•Gathering and Processing North. Our gathering and processing north operations provide natural gas, crude oil and produced water gathering, compression, treating, processing and disposal services to producers in the Williston Basin and Powder River Basin.

•Gathering and Processing South. Our gathering and processing south operations provide natural gas gathering, compression, treating and processing and produced water gathering and disposal services to producers in the Marcellus, Barnett and Delaware basins.

•Storage and Logistics. Our storage and logistics operations provide NGL, crude oil and natural gas storage, terminal, marketing and transportation (including rail, truck and pipeline) services to producers, refiners, marketers, utilities and other customers.

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Outlook and Trends

Our business objective is to create long-term value for our unitholders. We expect to create value for our investors by generating stable operating margins and improving cash flows from our diversified midstream operations by prudently financing investments in our assets and expansions of our portfolio, maximizing throughput and optimizing services on our assets, and effectively controlling our capital expenditures, operating and administrative costs.

We have taken a number of strategic steps to better position the Company as a stronger, better capitalized company that can accretively grow cash f