Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
☒
☐
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES
EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 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
Crestwood Equity Partners LP
Crestwood Midstream Partners LP
001-34664
001-35377
Delaware
Delaware
(I.R.S. Employer
Identification No.)
43-1918951
20-1647837
811 Main Street
(Address of principal executive offices)
Suite 3400
Houston
Texas
77002
(Zip code)
(832) 519-2200
(Registrant’s telephone number, including area code)
___________________________________________
Securities registered pursuant to Section 12(b) of the Act:
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
Title of each class
Trading Symbol Name of each exchange on which registered
Securities registered pursuant to Section 12(g) of the Act:
Crestwood Equity Partners LP
Crestwood Midstream Partners LP
None
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
Crestwood Midstream Partners LP
Yes ☒ No ☐
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
Crestwood Midstream Partners LP
Yes ☐ No ☒
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
Crestwood Midstream Partners LP
Yes ☒ No ☐
Yes ☒ No ☐
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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
Crestwood Midstream Partners LP
Yes ☒ No ☐
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
Crestwood Midstream Partners LP Large
accelerated filer
☐ Accelerated filer ☐ Non-accelerated filer ☒ Smaller reporting
company
☐ Emerging growth
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
Crestwood Midstream Partners LP
Yes ☐ No ☒
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
Crestwood Midstream Partners LP
$1.7 billion
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
Crestwood Midstream Partners LP
97,978,074
None
Portions of the following documents are incorporated by reference into the indicated parts of this report:
DOCUMENTS INCORPORATED BY REFERENCE
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.
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FILING FORMAT
This Annual Report on Form 10-K is a combined report being filed by two separate registrants: Crestwood Equity Partners LP
and Crestwood Midstream Partners LP. Crestwood Midstream Partners LP is a wholly-owned subsidiary of Crestwood Equity
Partners LP. Information contained herein related to any individual registrant is filed by such registrant solely on its own
behalf. Each registrant makes no representation as to information relating exclusively to the other registrant.
Item 15 of Part IV of this Annual Report includes separate financial statements (i.e., balance sheets, statements of operations,
statements of comprehensive income, statements of partners’ capital and statements of cash flows, as applicable) for Crestwood
Equity Partners LP and Crestwood Midstream Partners LP. The notes accompanying the financial statements are presented on a
combined basis for each registrant. Management’s Discussion and Analysis of Financial Condition and Results of Operations
included under Item 7 of Part II is presented for each registrant.
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CRESTWOOD EQUITY PARTNERS LP
CRESTWOOD MIDSTREAM PARTNERS LP
INDEX TO ANNUAL REPORT ON FORM 10-K
Item 1.
Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2.
Properties
Item 3.
Legal Proceedings
Item 4. Mine Safety Disclosures
PART I
PART II
Item 5. Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity
Securities
Item 6.
Selected Financial Data
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures about Market Risk
Item 8.
Financial Statements and Supplementary Data
Item 9.
Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Controls and Procedures
Item 9B. Other Information
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive Compensation
PART III
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accountant Fees and Services
Item 15. Exhibits, Financial Statement Schedules
PART IV
Page
9
25
45
45
45
45
46
47
47
63
64
64
64
65
66
66
66
66
66
67
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GLOSSARY
The terms below are common to our industry and used throughout this report.
/d
AOD
ASU
per day
Area of dedication, which means the acreage dedicated to a company by an oil and/or natural
gas producer under one or more contracts.
Accounting Standards Update
Barrels (Bbls)
One barrel of petroleum products equal to 42 U.S. gallons.
Bcf
Cycle
EPA
FERC
GAAP
HP
Hub
Hub services
Injection rate
MBbls
MMBbls
MMcf
Natural gas
Natural Gas Act
Natural gas liquids (NGLs)
NYSE
SEC
Withdrawal rate
One billion cubic feet of natural gas. A standard volume measure of natural gas products.
A complete withdrawal and injection of working gas. Cycling refers to the process of
completing one cycle.
Environmental Protection Agency
Federal Energy Regulatory Commission
Generally Accepted Accounting Principles
Horsepower
Geographic location of a storage facility and multiple pipeline interconnections
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.
The rate at which a customer is permitted to inject natural gas into a natural gas storage
facility.
One thousand barrels
One million barrels
One million cubic feet of natural gas
A gaseous mixture of hydrocarbon compounds, primarily methane together with varying
quantities of ethane, propane, butane and other gases.
Federal law enacted in 1938 that established the FERC’s authority to regulate interstate
pipelines.
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).
New York Stock Exchange
Securities and Exchange Commission
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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Item 1. Business
PART I
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
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
Converse
360
241 MMcf/d
101 MMcf/d
90,235
Williston
Basin
North Dakota
Powder River
Basin
Wyoming
1
2
140
150,000
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
Williston Basin
Powder River Basin
Type of Contracts(1)
Weighted Average Remaining
Contract Terms (in years)
Major Customers
Mixed
Fixed-fee
8
15
Devon Energy Corporation, Rimrock Oil & Gas, LP, Enerplus
Resources (USA) Corporation
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
Barnett
Texas
Delaware
Basin(1)
New Mexico/
Texas
Hood,
Somervell,
Tarrant,
Johnson and
Denton
Eddy (New
Mexico)
Loving,
Reeves, Ward
and Culberson
(Texas)
72
875 MMcf/d
227 MMcf/d
113,000
—
—
140,000
388
925 MMcf/d
218 MMcf/d
153,465
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
1
425
140,000
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)
(4)
Includes 45,000 HP that is owned and operated by a third party under a compression services agreement.
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
Marcellus
Barnett
Delaware
Type of Contracts(1)
Weighted Average Remaining
Contract Terms (in years)
Fixed-fee
Mixed
Fixed-fee
Percentage-of-proceeds
10
5
13
6
Major Customers
Antero Resources Corporation
Diversified Energy Company plc, FDL Operating LLC
Permian Delaware Enterprise, Mewbourne Oil Company
(Mewbourne)
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
COLT
Tres Palacios
Type of Contracts(1)
Weighted Average
Remaining Contract Terms
Major Customers
Fixed-Fee, Firm
Less than 1 year
BP Products North America, Inc. (BP), Flint Hills Resources
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:
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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:
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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:
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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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•
•
•
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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:
•
•
•
•
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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:
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•
•
•
•
•
•
•
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:
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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;
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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:
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the rates charged for services and the amount of services customers purchase, which will be affected by, among other
things, the overall balance between the supply of and demand for commodities, governmental regulation of our rates
and services and our ability to obtain permits for growth projects;
force majeure events that damage our or third-party pipelines, facilities, related equipment and surrounding properties;
prevailing economic and market conditions;
governmental regulation, including changes in governmental regulation in our industry;
changes in tax laws;
the level of competition from other midstream companies;
the level of our 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:
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our existing common unitholders’ proportionate ownership interest in us will decrease;
the amount of cash available for distribution on each common unit may decrease;
the ratio of taxable income to distributions may increase;
the relative voting strength of each previously outstanding common unit may be diminished; and
the market price of the common units may decline.
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:
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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
First Quarter 2021
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 $
11,469,911 $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
— $
—
—
22.49
22.49
—
—
—
—
—
—
—
—
—
—
—
—
11,469,911 $
22.49
—
—
175,000,000
—
—
—
—
—
—
—
—
—
— $
— $
— $
—
— $
— $
— $
—
— $
— $
— $
—
— $
— $
— $
—
—
(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 flows and as an industry leader in ESG efforts.
During 2021, CEQP paid Crestwood Holdings approximately $268 million to (i) acquire 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); and (ii) acquire 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) (collectively the Crestwood Holdings Transactions). The purchase
price was funded through borrowings under the Crestwood Midstream credit facility. The Crestwood Holdings Transactions
resulted in CEQP retiring the common and subordinated units acquired from Crestwood Holdings.
The Crestwood Holdings Transactions were a significant step in our strategy to drive peer leading governance and set the stage
for future growth by simplifying our organizational structure, increasing our public float and liquidity and enhancing our
financial flexibility as we strive to generate long-term value for our unitholders. In conjunction with the completion of the
Crestwood Holdings Transactions, CEQP transitioned to a traditional public company governance structure which further
ensures alignment between management and the Board of Directors with common unitholders and is consistent with our long-
term ESG program.
To further enhance our financial flexibility and execute our long-term business strategy, in July 2021 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. Stagecoach Gas distributed to us approximately $614 million as our proportionate share of the gross
proceeds received from the sale. 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. We received cash proceeds of approximately $15 million related to the sale. The Stagecoach Gas divestiture enabled
us to repay borrowings under our credit facility and therefore decrease our net debt to consolidated EBITDA ratio below 3.6x at
December 31, 2021, which should position us to utilize a greater portion of our cash flow going forward to increase returns to
our unitholders through continued distributions, prudent capital investments around our assets, and opportunistic repurchases of
our preferred and common units under our approved $175 million unit repurchase program described below in “Liquidity and
Sources of Capital”.
We continue to drive our long-term growth strategy through disciplined capital investments utilizing our current financial
flexibility, and on February 1, 2022, we completed the Merger with Oasis Midstream Partners LP (Oasis Midstream) through
which we acquired Oasis Midstream in an equity and cash transaction. Pursuant to the merger agreement, Oasis Petroleum Inc.
(Oasis Petroleum) received $150 million in cash plus 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 12.9 million newly
issued CEQP common units in exchange for the 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. This transaction further solidifies Crestwood’s competitive position in the Williston Basin with exposure to
approximately 1,200 drilling locations and 535,000 dedicated acres, expanding the Company’s operational footprint beyond the
Fort Berthold Indian Reservation. Additionally, Oasis Midstream’s Wild Basin gathering and processing assets are highly
complementary with our Arrow gathering system and Bear Den processing facility which provides for opportunities to drive
cost savings, commercial synergies and better utilization of available gas processing capacity.
In addition to the strategic steps discussed above, we have also taken steps to (i) align capital investments with development
activity by our gathering and processing customers; (ii) realign our organizational structure to reduce operating and
administrative expenses; (iii) engage with our customers to maintain volumes across our asset portfolio; (iv) optimize our
storage, transportation and marketing assets to take advantage of regional commodity price volatility; and (v) evaluate our debt
and equity structure to preserve liquidity and ensure balance sheet strength. Given our efforts over the past few years to
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improve the partnership’s competitive position in the businesses in which we operate, manage costs and improve margins and
create a stronger balance sheet, we believe the Company is well positioned to execute its business plan.
Recent Developments
Bakken DAPL Matter. In July 2020, a U.S. District Court (District Court) ordered the Dakota Access Pipeline (DAPL) to cease
operation based on an alleged procedural permitting failure. On August 5, 2020, the U.S. Court of Appeals for the District of
Columbia Circuit (D.C. Circuit) stayed the DAPL shutdown, and subsequently issued an opinion upholding the District Court’s
decision on the merits, but not prohibiting DAPL’s continued operation. The plaintiffs sought another injunction against
DAPL’s operation, which was denied by the District Court in May 2021. As required by the District Court, the U.S. Army
Corps of Engineers is currently conducting an environmental impact statement, which is currently expected to be complete in
September 2022. We expect DAPL will remain in operation while the environmental impact statement is being completed.
The Arrow gathering system currently connects to the DAPL, Kinder Morgan Hiland, Tesoro and True Companies’ Bridger
Four Bears pipelines, providing significant downstream delivery capacity for our Arrow customers. Additionally, we can
transport Arrow crude volumes to our COLT Hub facility by pipeline or truck, which mitigates the impact of any potential
pipeline shut-downs to our producers with the ability to access multiple markets out of the basin.
Carbon Management. One of the core initiatives related to our ESG efforts surrounds our focus on managing the intensity of
our emissions in order to reduce climate-related risk to our business.
In January 2022, we published our first carbon management plan (CMP), which outlines near-term emissions reduction and
management activities that we intend to implement over the next three years. The CMP includes several core objectives,
including (i) reducing emissions intensity of our assets; (ii) evaluating opportunities to reduce Scope 2 greenhouse gas (GHG)
emissions while managing our operations’ energy efficiency; (iii) enhancing our process by which we manage GHG emissions;
(iv) piloting methane emission monitoring devices at certain of our facilities; (v) participating in the development of responsibly
sourced gas standards for the midstream sector; (vi) investing in technology to better inventory and calculate emissions data and
integrating the technology into our operations; and (vii) participating in and providing leadership to trade associations focused
on climate-related risks.
During 2021, we included our first emissions-related metric in our executives’ and employees’ short-term incentive
compensation program, with a methane intensity target of 0.054% (measured as metric tons per Mscf of throughput on our
assets), compared to our actual 2020 methane intensity statistic of 0.051%. We have included a methane intensity target of
0.046% in our executives’ and employees’ short-term incentive compensation program for 2022.
We currently believe that our carbon management efforts will help to mitigate the potential impact that emissions may have on
our capital expenditures or results of operations in the future, although we currently anticipate that these efforts will not have a
material impact on our capital expenditures or results of operations in 2022.
Critical Accounting Estimates and Policies
Our significant accounting policies are described in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.
The preparation of financial statements in conformity with GAAP requires management to select appropriate accounting
estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses
and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require
difficult, complex, or subjective judgment necessary in accounting for inherently uncertain matters and those that could
significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may
result in revised estimates and actual results may differ materially from those estimates. We have discussed the development
and selection of the following critical accounting estimates and related disclosures with the Audit Committee of the board of
directors of our general partner.
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Goodwill
Our goodwill represents the excess of the amount we paid for a business over the fair value of the net identifiable assets
acquired. We evaluate goodwill for impairment annually on December 31, and whenever events indicate that it is more likely
than not that the fair value of a reporting unit could be less than its carrying amount. This evaluation requires us to compare the
fair value of each of our reporting units to its carrying value (including goodwill). If the fair value exceeds the carrying amount,
goodwill of the reporting unit is not considered impaired.
We estimate the fair value of our reporting units based on a number of factors, including discount rates, projected cash flows
and the potential value we would receive if we sold the reporting unit. Estimating projected cash flows requires us to make
certain assumptions as it relates to the future operating performance of each of our reporting units (which includes assumptions,
among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the
cost and timing of facility expansions) and assumptions related to our customers, such as their future capital and operating plans
and their financial condition. When considering operating performance, various factors are considered such as current and
changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these
projections and assumptions, actual results can and often do, differ from our estimates. If the assumptions embodied in the
projections prove inaccurate, we could incur a future impairment charge. In addition, the use of the income approach to
determine the fair value of our reporting units (see further discussion of the use of the income approach below) could result in a
different fair value if we had utilized a market approach, or a combination thereof.
Upon acquisition, we are required to record the assets, liabilities and goodwill of a reporting unit at its fair value on the date of
acquisition. As a result, any level of decrease in the forecasted cash flows of these businesses or increases in the discount rates
utilized to value those businesses from their respective acquisition dates would likely result in the fair value of the reporting
unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s
goodwill is impaired.
During 2020, current and forward commodity prices significantly declined from their levels at December 31, 2019 due
primarily to the decreases in energy demand as a result of the outbreak of the COVID-19 pandemic and actions taken by the
Organization of the Petroleum Exporting Countries, Russia, the United States and other oil-producing countries relating to the
oversupply of oil. We acquired our Powder River Basin reporting unit in April 2019, and during the year ended December 31,
2020, we fully impaired the goodwill associated with this reporting unit based on the impact that the decline in commodity
prices has had on our producer customers in the Powder River Basin described above.
At December 31, 2021, our goodwill consisted of approximately $45.9 million associated with our gathering and processing
north Arrow reporting unit and $92.7 million associated with our storage and logistics NGL Marketing and Logistics reporting
unit. We continue to monitor our remaining goodwill, and we could experience additional impairments of the remaining
goodwill in the future if we experience a significant sustained decrease in the market value of our common or preferred units or
if we receive additional negative information about market conditions or the intent of our customers on our remaining
operations with goodwill, which could negatively impact the forecasted cash flows or discount rates utilized to determine the
fair value of those businesses. A 5% decrease in the forecasted cash flows or a 1% increase in the discount rates utilized to
determine the fair value of our Arrow and NGL Marketing and Logistics reporting units would not have resulted in a goodwill
impairment of either of those reporting units.
Long-Lived Assets
Our long-lived assets consist of property, plant and equipment and intangible assets that have been obtained through multiple
business combinations and property, plant and equipment that has been constructed in recent years. The initial recording of a
majority of these long-lived assets was at fair value, which is estimated by management primarily utilizing market-related
information, asset specific information and other projections on the performance of the assets acquired (including an analysis of
discounted cash flows which can involve assumptions on discount rates and projected cash flows of the assets acquired).
Management reviews this information to determine its reasonableness in comparison to the assumptions utilized in determining
the purchase price of the assets in addition to other market-based information that was received through the purchase process
and other sources. These projections also include projections on potential and contractual obligations assumed in these
acquisitions. Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results
can, and often do, differ from our estimates.
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We utilize assumptions related to the useful lives and related salvage value of our property, plant and equipment in order to
determine depreciation and amortization expense each period. Due to the imprecise nature of the projections and assumptions
utilized in determining useful lives, actual results can, and often do, differ from our estimates.
To estimate the useful life of our finite lived intangible assets we utilize assumptions of the period over which the assets are
expected to contribute directly or indirectly to our future cash flows. Generally this requires us to amortize our intangible assets
based on the expected future cash flows (to the extent they are readily determinable) or on a straight-line basis (if they are not
readily determinable) of the acquired contracts or customer relationships. Due to the imprecise nature of the projections and
assumptions utilized in determining future cash flows, actual results can, and often do, differ from our estimates.
We continually monitor our business, the business environment and the performance of our operations to determine if an event
has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves
judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value of our assets
based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. This differs from our evaluation
of goodwill, for which we perform an assessment of the recoverability of goodwill utilizing fair value estimates that primarily
utilize discounted cash flows in the estimation process (as described above), and accordingly a reporting unit that has
experienced a goodwill impairment may not experience a similar impairment of the underlying long-lived assets included in
that reporting unit.
Projected cash flows of our long-lived assets are generally based on current and anticipated future market conditions, which
require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs,
construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside
of our control. If those cash flow projections indicate that the long-lived asset’s carrying value is not recoverable, we record an
impairment charge for the excess of the carrying value of the asset over its fair value. The estimate of fair value considers a
number of factors, including the potential value we would receive if we sold the asset, discount rates and projected cash flows.
Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.
During 2021, we recorded $40.1 million of impairments of our property, plant and equipment related to our gathering and
processing south segment’s compressor stations in the Marcellus West AOD based on the actual or anticipated dismantlement
and redeployment of those assets to other areas. During 2020 and 2019, we recorded $3.1 million and $4.3 million of
impairments of our property, plant and equipment primarily related to certain of our water gathering facilities in our Arrow
operations. During 2020, we sold our Fayetteville assets and recorded a loss on long-lived assets of approximately
$19.9 million. For a further discussion of these matters, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2
and Note 3.
We continue to monitor our long-lived assets, and we could experience additional impairments of the remaining carrying value
of these long-lived assets in the future if we receive negative information about market conditions or the intent of our long-lived
assets’ customers, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value
of those investments.
Equity Method Investments
We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the
equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the
recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, we adjust the
carrying values of the investment downward, if necessary, to their estimated fair values.
We estimate the fair value of our equity method investments based on a number of factors, including discount rates, projected
cash flows, enterprise value and the potential value we would receive if we sold the equity method investment. Estimating
projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our
equity method investments (which includes assumptions, among others, about estimating future operating margins and related
future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to
our equity method investments’ customers, such as their future capital and operating plans and their financial condition. When
considering operating performance, various factors are considered such as current and changing economic conditions and the
commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results
can and often do, differ from our estimates.
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We continue to monitor our equity method investments, and if we receive negative information about market conditions or the
intent of our equity method investments’ customers to curtail production in the future that negatively impacts the forecasted
cash flows or discount rates utilized to determine the fair value of those investments, we could experience impairments to the
carrying value of these investments.
Our equity method investments have long-lived assets, intangible assets and equity method investments in their underlying
financial statements, and our equity investees apply similar accounting policies and have similar critical accounting estimates in
assessing those assets for impairment as we do. During 2021, we recorded a $158.7 million reduction to the equity earnings
from our Stagecoach Gas equity method investment as a result of the sale (through a series of transactions) of Stagecoach Gas
to a subsidiary of Kinder Morgan. For a further discussion of the Stagecoach Gas divestiture, see Part IV, Item 15. Exhibits,
Financial Statement Schedules, Note 6. During 2020, we recorded a $4.5 million reduction to the equity earnings from our
PRBIC equity method investment as a result of us recording our proportionate share of a long-lived asset impairment recorded
by the equity method investee. The carrying value of our PRBIC equity method investment was $3.5 million at December 31,
2021.
Revenue Recognition
We recognize revenues for services and products under our revenue contracts as our obligations to perform services or deliver/
sell products under the contracts are satisfied. A contract’s transaction price is allocated to each performance obligation in the
contract and recognized as revenue when, or as, the performance obligation is satisfied. Under certain contracts, we may be
entitled to receive payments in advance of satisfying our performance obligations under the contract. We recognize a liability
for these payments in excess of revenue recognized and present it as deferred revenue or contract liabilities on our consolidated
balance sheets. At December 31, 2021 and 2020, we had deferred revenues of approximately $197.8 million and $182.5
million. Our deferred revenues primarily relate to:
•
•
Capital Reimbursements. Certain of our contracts require that our customers reimburse us for capital expenditures
related to the construction of long-lived assets utilized to provide services to them under the revenue contracts.
Because we consider these amounts as consideration from customers associated with ongoing services to be provided
to customers, we defer these upfront payments in deferred revenue and recognize the amounts in revenue over the life
of the associated revenue contract as the performance obligations are satisfied under the contract.
Contracts with Increasing (Decreasing) Rates per Unit. Certain of our contracts have fixed rates per volume that
increase and/or decrease over the life of the contract once certain time periods or thresholds are met. We record
revenues on these contracts ratably per unit over the life of the contract based on the remaining performance
obligations to be performed, which can result in the deferral of revenue for the difference between the consideration
received and the ratable revenue recognized.
The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our
performance obligations requires significant judgments and assumptions, including our evaluation of the timing of when control
of the underlying good or service has transferred to our customers, estimating the revenue to be generated per unit over the life
of the contracts, and determining the relative standalone selling price of goods and services provided to customers under
contracts with multiple performance obligations. Actual results can significantly vary from those judgments and assumptions.
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How We Evaluate Our Operations
We evaluate our overall business performance based primarily on EBITDA and Adjusted EBITDA. We do not utilize
depreciation, amortization and accretion expense in our key measures because we focus our performance management on cash
flow generation and our assets have long useful lives.
EBITDA and Adjusted EBITDA - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a
company’s operational performance and its ability to incur and service debt, fund capital expenditures and make distributions.
We believe that EBITDA and Adjusted EBITDA are useful to our investors because it allows them to use the same performance
measure analyzed internally by our management to evaluate the performance of our businesses and investments without regard
to the manner in which they are financed or our capital structure. EBITDA is defined as income before income taxes, plus debt-
related costs (interest and debt expense, net, and gain (loss) on modification/extinguishment of debt) and depreciation,
amortization and accretion expense. Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates
by adjusting our equity earnings or losses from our unconsolidated affiliates to reflect our proportionate share (based on the
distribution percentage) of their EBITDA, excluding gains and losses on long-lived assets and other impairments. Adjusted
EBITDA also considers the impact of certain significant items, such as unit-based compensation charges, gains or losses and
impairments related to long-lived assets, goodwill and acquisitions, third party costs incurred related to potential and completed
acquisitions, certain environmental remediation costs, the change in fair value of commodity inventory-related derivative
contracts, costs associated with the realignment and restructuring of our operations and corporate structure, and other
transactions identified in a specific reporting period. The change in fair value of commodity inventory-related derivative
contracts is considered in determining Adjusted EBITDA given that the timing of recognizing gains and losses on these
derivative contracts differs from the recognition of revenue for the related underlying sale of inventory to which these
derivatives relate. Changes in the fair value of other derivative contracts is not considered in determining Adjusted EBITDA
given the relatively short-term nature of those derivative contracts. EBITDA and Adjusted EBITDA are not measures calculated
in accordance with GAAP, as they do not include deductions for items such as depreciation, amortization and accretion, interest
and income taxes, which are necessary to maintain our business. EBITDA and Adjusted EBITDA should not be considered as
alternatives to net income, operating cash flow or any other measure of financial performance presented in accordance with
GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to
measures used by other companies. See our reconciliation of net income to EBITDA and Adjusted EBITDA in “Results of
Operations” below.
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Results of Operations
The following table summarizes our results of operations (in millions).
Revenues
Costs of product/services sold
Operations and maintenance expense
General and administrative expense
Depreciation, amortization and accretion
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
Operating income
Earnings (loss) from unconsolidated affiliates, net
Crestwood Equity
Crestwood Midstream
Year Ended December 31,
Year Ended December 31,
2021
2020
2019
2021
2020
$ 4,569.0 $ 2,254.3 $ 3,181.9 $ 4,569.0 $ 2,254.3
3,843.9
1,600.5
2,544.9
3,843.9
1,600.5
121.0
97.6
244.2
39.6
—
—
222.7
(120.4)
131.8
91.5
237.4
26.0
80.3
—
86.8
32.5
138.8
103.4
195.8
6.2
—
(209.4)
402.2
32.8
121.0
90.2
258.4
39.4
—
—
216.1
(120.4)
131.8
86.7
251.5
26.0
80.3
—
77.5
32.5
Interest and debt expense, net
(132.1)
(133.6)
(115.4)
(132.1)
(133.6)
Gain (loss) on modification/extinguishment of debt
Other income (expense), net
(Provision) benefit for income taxes
Net income (loss)
Add:
(7.5)
0.1
(0.2)
0.1
(0.7)
(0.4)
—
0.6
(7.5)
—
(0.3)
(0.1)
0.1
—
0.1
(37.4)
(15.3)
319.9
(44.0)
(23.4)
Interest and debt expense, net
132.1
133.6
115.4
132.1
133.6
(Gain) loss on modification/extinguishment of debt
Provision (benefit) for income taxes
Depreciation, amortization and accretion
EBITDA
Unit-based compensation charges
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
(Earnings) loss from unconsolidated affiliates, net
Adjusted EBITDA from unconsolidated affiliates, net
Change in fair value of commodity inventory-related
derivative contracts
Significant transaction and environmental related costs
and other items
Adjusted EBITDA
7.5
0.2
244.2
346.6
34.9
39.6
—
—
120.4
67.0
(0.1)
0.4
237.4
356.0
30.7
26.0
80.3
—
(32.5)
75.4
—
0.3
195.8
631.4
47.0
6.2
—
(209.4)
(32.8)
74.9
7.5
0.1
258.4
354.1
34.9
39.4
—
—
120.4
67.0
(0.1)
(0.1)
251.5
361.5
30.7
26.0
80.3
—
(32.5)
75.4
(13.5)
33.6
5.1
10.8
2.7
6.5
(13.5)
33.6
2.5
10.8
$
600.1 $
580.3 $
526.5 $
604.8 $
585.8
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Net cash provided by operating activities
$
426.7 $
408.1 $
420.4 $
434.4 $
407.9
Crestwood Equity
Crestwood Midstream
Year Ended December 31,
Year Ended December 31,
2021
2020
2019
2021
2020
Net changes in operating assets and liabilities
6.7
(36.1)
(47.8)
6.8
Amortization of debt-related deferred costs
(6.7)
(6.5)
(6.2)
(6.7)
Interest and debt expense, net
Unit-based compensation charges
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
Earnings (loss) from unconsolidated affiliates, net,
adjusted for cash distributions received
Deferred income taxes
Provision (benefit) for income taxes
Other non-cash income
EBITDA
Unit-based compensation charges
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
(Earnings) loss from unconsolidated affiliates, net
Adjusted EBITDA from unconsolidated affiliates, net
Change in fair value of commodity inventory-related
derivative contracts
Significant transaction and environmental related costs
and other items
Adjusted EBITDA
132.1
133.6
115.4
132.1
(34.9)
(39.6)
—
—
(138.0)
0.4
0.2
(0.3)
346.6
34.9
39.6
—
—
120.4
67.0
(30.7)
(26.0)
(80.3)
—
(6.5)
(0.1)
0.4
0.1
356.0
30.7
26.0
80.3
—
(47.0)
(6.2)
—
209.4
(34.9)
(39.4)
—
—
(6.9)
(138.0)
—
0.3
—
631.4
47.0
6.2
—
(209.4)
—
0.1
(0.3)
354.1
34.9
39.4
—
—
120.4
67.0
(32.5)
(32.8)
75.4
74.9
(30.0)
(6.5)
133.6
(30.7)
(26.0)
(80.3)
—
(6.5)
—
(0.1)
0.1
361.5
30.7
26.0
80.3
—
(32.5)
75.4
(13.5)
33.6
5.1
10.8
2.7
6.5
(13.5)
33.6
2.5
10.8
$
600.1 $
580.3 $
526.5 $
604.8 $
585.8
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Segment Results
The following tables summarize the EBITDA of our segments (in millions):
Gathering and
Processing North
Gathering and
Processing South
Storage and
Logistics
$
574.7
$
105.9
$
Revenues
Intersegment revenues
Costs of product/services sold
Operations and maintenance expense
Gain (loss) on long-lived assets, net
Earnings (loss) from unconsolidated affiliates, net
EBITDA for the year ended December 31, 2021
Revenues
Intersegment revenues
Costs of product/services sold
Operations and maintenance expense
Loss on long-lived assets, net
Goodwill impairments
Earnings (loss) from unconsolidated affiliates, net
EBITDA for the year ended December 31, 2020
Revenues
Intersegment revenues
Costs of product/services sold
Operations and maintenance expense
Loss on long-lived assets, net
Gain on acquisition
Earnings (loss) from unconsolidated affiliates, net
$
$
$
$
459.3
553.2
51.1
0.4
—
—
0.9
22.9
(40.6)
9.6
430.1
$
51.1
$
510.4
$
121.0
$
160.5
261.0
55.7
(3.8)
(80.3)
—
(0.7)
0.5
29.2
(20.0)
—
(1.0)
3,888.4
(459.3)
3,289.8
47.0
0.7
(130.0)
(37.0)
1,622.9
(159.8)
1,339.0
46.9
(2.4)
—
33.5
270.1
$
69.6
$
108.3
686.9
$
148.9
$
174.9
524.0
60.8
(4.2)
209.4
3.7
0.1
2.1
37.9
(2.0)
—
(5.8)
2,346.1
(175.0)
2,018.8
40.1
(0.2)
—
34.9
EBITDA for the year ended December 31, 2019
$
485.9
$
101.2
$
146.9
Below is a discussion of the factors that impacted EBITDA by segment for the year ended December 31, 2021 compared to the
year ended December 31, 2020.
Gathering and Processing North
EBITDA for our gathering and processing north segment increased by approximately $160.0 million during the year ended
December 31, 2021 compared to 2020. Our gathering and processing north segment’s EBITDA for the year ended December
31, 2020 was impacted by an $80.3 million goodwill impairment related to our Jackalope operations which is further discussed
in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.
Our gathering and processing north segment’s revenues increased by approximately $363.1 million during the year ended
December 31, 2021 compared to 2020, while our costs of product/services sold increased by approximately $292.2 million
during 2021 compared to 2020. The increases were primarily driven by higher natural gas volumes on our Arrow system
(described below) and higher average prices (i.e., more than 50% increase in commodity prices during the year ended
December 31, 2021 compared to 2020) that our gathering and processing north segment realized on its agreements under which
it purchases and sells crude oil, natural gas and NGLs. During the year ended December 31, 2021, Arrow’s natural gas
gathering and processing volumes both increased by 18% compared to 2020. During the first half of 2020, Arrow experienced
lower gathering and processing volumes due to certain of its customers shutting in production in response to low commodity
prices during that period.
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Our gathering and processing north segment’s operations and maintenance expenses decreased by approximately $4.6 million
during the year ended December 31, 2021 compared to 2020, primarily due to efforts we undertook starting in the second
quarter of 2020 to reduce costs in response to lower commodity prices during that period.
Our gathering and processing north segment’s EBITDA during the year ended December 31, 2020 was impacted by a $3.1
million loss on long-lived assets we recorded related to the removal and retirement of certain water gathering lines on our
Arrow system.
Gathering and Processing South
EBITDA for our gathering and processing south segment decreased by approximately $18.5 million during the year ended
December 31, 2021 compared to 2020. Our gathering and processing south segment’s EBITDA was impacted by $40.1 million
and $19.9 million of losses on long-lived assets we recorded during the years ended December 31, 2021 and 2020, respectively,
which are further described below.
Our gathering and processing south segment’s revenues decreased by approximately $14.4 million during the year ended
December 31, 2021 compared to 2020, while our costs of product/services sold were relatively flat during 2021 compared to
2020. The decrease in our gathering and processing south segment’s revenues was primarily driven by lower natural gas
gathering volumes of approximately 11% on our Marcellus East AOD during the year ended December 31, 2021 compared to
2020 due to natural declines in our customer’s natural gas production in that area. Also contributing to the decrease in our
gathering and processing south segment’s revenues were lower revenues from our Fayetteville operations due to the sale of
these assets in October 2020, as further discussed in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.
Our gathering and processing south segment’s operations and maintenance expenses decreased by approximately $6.3
million during the year ended December 31, 2021 compared to 2020, primarily due to the sale of our Fayetteville assets in
October 2020 and efforts we undertook starting in the second quarter of 2020 to reduce costs in response to lower commodity
prices during that period.
Our gathering and processing south segment’s EBITDA during the year ended December 31, 2021 was impacted by
$40.1 million of impairments of our property, plant and equipment related to our compressor stations in the Marcellus western
area of operation based on the actual or anticipated dismantlement and redeployment of those assets to other areas. In addition,
during the year ended December 31, 2020, we recorded a loss on long-lived assets of approximately $19.9 million related to the
sale of our Fayetteville assets in October 2020.
Our gathering and processing south segment’s EBITDA was also impacted by an increase in equity earnings of approximately
$10.6 million from our Crestwood Permian equity investment during the year ended December 31, 2021 compared to 2020.
During the year ended December 31, 2021, Crestwood Permian experienced an increase in its natural gas gathering and
processing revenues and volumes primarily due to its customers connecting more wells to its system during 2021 as a result of
the increases in commodity prices compared to 2020. In addition, Crestwood Permian also experienced an increase in its water
gathering revenues and volumes during the year ended December 31, 2021 compared to 2020, primarily due to placing in-
service its produced water gathering and disposal system in late 2020.
Storage and Logistics
EBITDA for our storage and logistics segment decreased by approximately $145.3 million during the year ended December 31,
2021 compared to 2020, which was primarily driven by a $177.0 million reduction to the equity earnings from our Stagecoach
Gas equity investment as further discussed below.
Our storage and logistics segment’s revenues increased by approximately $1,966.0 million during the year ended December 31,
2021 compared to 2020, while our costs of product/services sold increased by approximately $1.950.8 million during 2021
compared to 2020.
Our NGL marketing and logistics operations experienced an increase in revenues of approximately $1,326.9 million during the
year ended December 31, 2021 compared to 2020, and an increase in its costs of product/services sold of approximately
$1,309.9 million during 2021 compared to 2020. These increases were primarily due to increases in NGL prices during 2021
compared to 2020 as a result of overall increases in commodity prices and the unusually cold weather experienced during early
2021 compared to 2020. Also contributing to the increases in our NGL marketing and logistics operations was the impact of the
operating results of the NGL assets acquired from Plains in April 2020, which increased our ability to capture additional
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opportunities in the markets in which these assets operate. Included in our costs of product/services sold was a loss of $44.5
million and $20.7 million during the years ended December 31, 2021 and 2020 related to our price risk management activities.
Our crude and natural gas marketing operations experienced an increase in its revenues of approximately $644.0 million during
the year ended December 31, 2021 compared to 2020, and an increase in its product costs of approximately $641.5 million
during 2021 compared to 2020. These increases were driven primarily by higher crude oil purchases and sales as a result of
increases in commodity prices during 2021 compared to 2020 as well as an increase in marketing activity surrounding our
natural gas-related operations driven by the unusual winter weather conditions experienced during 2021.
During the year ended December 31, 2021, our COLT Hub operations experienced a 7% decrease in its rail loading volumes
compared to 2020 due to lower demand for its rail loading services as a result of lower basis differentials in the Bakken which
resulted in a decrease in revenues of approximately $4.9 million. Our COLT Hub’s costs of services were relatively flat during
the year ended December 31, 2021 compared to 2020.
Our storage and logistics segment’s EBITDA during the year ended December 31, 2020 was impacted by a loss on long-lived
assets of approximately $2.4 million primarily related to the impairment and loss on the sale of our Bakken transportation
assets.
Our storage and logistics segment’s EBITDA was also impacted by a net decrease in earnings from unconsolidated affiliates
during the year ended December 31, 2021 compared to 2020. During 2021, we recorded a $158.7 million reduction to the
equity earnings from our Stagecoach Gas equity method investment as a result of the sale (through a series of transactions) of
Stagecoach Gas to a subsidiary of Kinder Morgan. In addition, our equity earnings from Stagecoach Gas also decreased by
approximately $18.3 million during the year ended December 31, 2021 compared to 2020 due to our 2021 results not reflecting
a full year of equity earnings from the Stagecoach Gas assets due to the sale. For a further discussion of the Stagecoach Gas
divestiture, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6. During the year ended December 31, 2021,
earnings from our Tres Holdings equity investment increased by approximately $9.3 million compared to 2020, primarily due
to higher revenues from gas inventory sales and an increase in demand for its storage and transportation services due to the
unusually cold weather experienced during early 2021 compared to 2020. During the year ended December 31, 2021, earnings
from our PRBIC equity investment increased by $4.2 million compared to 2020, primarily as a result of recording our
proportionate share of a long-lived assets impairment recorded by our PRBIC equity investment during 2020.
Other EBITDA Results
General and Administrative Expenses. During the year ended December 31, 2021, Crestwood Midstream’s general and
administrative expenses increased by approximately $3.5 million compared to 2020, primarily due to higher unit-based
compensation charges driven by higher average awards outstanding under our long-term incentive plans.
During the year ended December 31, 2021, Crestwood Equity’s general and administrative expenses increased by
approximately $6.1 million compared to 2020 due to higher unit-based compensation charges as discussed above as well as an
increase in transaction costs that were expensed related to the Crestwood Holdings Transactions discussed in Part I, Item 1.
Business.
Items not affecting EBITDA include the following:
Depreciation, Amortization and Accretion Expense. During the year ended December 31, 2021, our depreciation, amortization
and accretion expense increased by approximately $7 million compared to 2020, primarily due to the expansion of our
gathering and processing facilities at our Arrow system, placing in-service the expansion of our processing capacity at our
Bucking Horse processing facility on our Powder River Basin system in early 2020, and the acquisition of the NGL assets
acquired from Plains in April 2020. Partially offsetting these increases was lower depreciation, amortization and accretion
expense due to the sale of our Fayetteville assets in late 2020.
Interest and Debt Expense, Net. Interest and debt expense, net decreased by approximately $1.5 million during the year ended
December 31, 2021 compared to 2020, primarily due to lower average outstanding balances on our Crestwood Midstream credit
facility. Partially offsetting the decrease in interest and debt expense, net was the issuance of $700 million unsecured senior
notes in January 2021 and lower capitalized interest in 2021 compared to 2020 due to the timing of growth capital projects
primarily in the Powder River Basin.
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The following table provides a summary of our interest and debt expense, net (in millions):
Credit facility
Senior notes
Other debt-related costs
Gross interest and debt expense
Less: capitalized interest
Interest and debt expense, net
Year Ended December 31,
2021
2020
2019
$
14.4 $
23.3 $
109.1
9.0
132.5
0.4
106.1
6.9
136.3
2.7
$
132.1 $
133.6 $
26.4
96.6
6.8
129.8
14.4
115.4
Loss on Extinguishment of Debt. During the year ended December 31, 2021, we recognized a loss on extinguishment of debt of
approximately $7.5 million primarily due to the redemption of our 2023 Senior Notes and the amendment of our credit facility
in December 2021.
Liquidity and Sources of Capital
Crestwood Equity is a holding company that derives all of its operating cash flow from its operating subsidiaries. Our principal
sources of liquidity include cash generated by operating activities from our subsidiaries, distributions from our joint ventures,
borrowings under the Crestwood Midstream credit facility, and sales of equity and debt securities. Our equity investments use
cash from their respective operations and contributions from us to fund their operating activities, maintenance and growth
capital expenditures, and service their outstanding indebtedness. We believe our liquidity sources and operating cash flows are
sufficient to address our future operating, debt service and capital requirements.
We make quarterly cash distributions to our common unitholders within approximately 45 days after the end of each fiscal
quarter in an aggregate amount equal to our available cash for such quarter. We also pay quarterly cash distributions of
approximately $15 million to our preferred unitholders and quarterly cash distributions of approximately $10 million to
Crestwood Niobrara’s non-controlling partner.
On January 20, 2022, we declared a quarterly cash distribution of $0.625 per unit to our common unitholders with respect to the
fourth quarter of 2021, which was paid on February 14, 2022 and was consistent with the distribution paid in November 2021.
In conjunction with the closing of the Merger, we plan to increase our quarterly cash distribution to $0.655 per unit with respect
to the distribution to be paid for the first quarter of 2022. Our Board of Directors evaluates the level of distributions to our
common and preferred unitholders every quarter and considers a wide range of strategic, commercial, operational and financial
factors, including current and projected operating cash flows and liquidity needs and the potential adverse impact of future
distribution reductions on our common unitholders. We believe our operating cash flows will exceed cash distributions to our
partners, preferred unitholders and non-controlling partner, and as a result, we will have adequate operating cash flows as a
source of liquidity for our growth capital expenditures.
In March 2021, Crestwood Equity’s board of directors authorized a $175 million common unit and preferred unit repurchase
program effective through December 31, 2022. Pursuant to the program, we may purchase common and preferred units from
time to time in the open market in accordance with applicable securities laws at current market prices. The timing and amount
of purchases under the program will be determined based on growth capital opportunities, financial performance and outlook,
and other factors, including acquisition opportunities and market conditions. The unit repurchase program does not obligate us
to purchase any specific dollar amount or number of units and may be suspended or discontinued at any time.
In December 2021, Crestwood Midstream entered into a Third Amended and Restated Credit Agreement (the CMLP Credit
Agreement). The CMLP Credit Agreement provides for a five-year $1.5 billion revolving credit facility (the CMLP Credit
Facility) that is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes
and allows Crestwood Midstream to increase its available borrowings under the facility by $350 million, subject to lender
approval and the satisfaction of certain other conditions, as described in the credit agreement. The CMLP Credit Facility also
includes a sub-limit of up to $25 million for same-day swing line advances and a sub-limit up to $350 million for letters of
credit. As of December 31, 2021, we had $961.7 million of available capacity under the Crestwood Midstream credit facility
considering the most restrictive debt covenants in the credit agreement, which was based on a $1.25 billion facility capacity that
was automatically increased to $1.5 billion upon the closing of the merger with Oasis Midstream on February 1, 2022. As of
December 31, 2021, we were in compliance with all of our debt covenants applicable to the credit facility and our senior notes.
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See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 9 for a more detailed description of the covenants related to
our credit facility and senior notes.
We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity
securities, in open market purchases, privately negotiated transactions, tender offers or otherwise. Such repurchases or
exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other
factors. The amounts involved may be material. During the year ended December 31, 2021, we redeemed and cancelled
approximately $687.2 million of principal outstanding under our senior notes due 2023, utilizing a portion of the proceeds from
the issuance of our senior notes due 2029 and borrowings under our Crestwood Midstream credit facility. During 2021, we sold
Stagecoach Gas to a subsidiary of Kinder Morgan and received approximately $629 million as our proportionate share of the
gross proceeds received from the sale. We utilized approximately $3 million of these proceeds to pay transaction costs related
to the sale described above, $40 million of these proceeds to pay our contingent consideration obligation and related accrued
interest, and the remainder of these proceeds to repay a portion of the amounts outstanding under the Crestwood Midstream
credit facility.
Cash Flows
The following table provides a summary of Crestwood Equity’s cash flows by category (in millions):
Net cash provided by operating activities
Net cash provided by (used in) investing activities
Net cash provided by (used in) financing activities
Operating Activities
Year Ended December 31,
2021
2020
2019
$
$
$
426.7 $
568.9 $
(996.3) $
408.1 $
(273.3) $
(146.5) $
420.4
(943.7)
531.8
Our operating cash flows increased by approximately $18.6 million during the year ended December 31, 2021 compared to
2020. The increase was primarily driven by higher operating revenues of approximately $2,314.7 million primarily from our
storage and logistics segment and gathering and processing north segment, partially offset by higher costs of product/services
sold of approximately $2,243.4 million primarily from these segments as discussed above. Partially offsetting this net increase
was a decrease in net cash inflow from working capital of approximately $42.8 million primarily related to our storage and
logistics operations as a result of higher average commodity prices during 2021 compared to 2020. In addition, during the year
ended December 31, 2021, our equity earnings from our Stagecoach Gas equity investment were lower due to the sale of our
equity investment as discussed , which resulted in a reduction in our net operating cash flows compared to 2020.
Investing Activities
Capital Expenditures. The energy midstream business is capital intensive, requiring significant investments for the acquisition
or development of new facilities. We categorize our capital expenditures as either:
•
growth capital expenditures, which are made to construct additional assets, expand and upgrade existing systems, or
acquire additional assets; or
• maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the
existing operating capacity of our assets, extend their useful lives or comply with regulatory requirements.
During 2022, we anticipate growth capital expenditures of approximately $160 million to $180 million, which includes
contributions to our equity investments related to their capital projects. In addition, we expect to spend between approximately
$30 million to $35 million on maintenance capital expenditures and approximately $5 million to $15 million on capital
expenditures that are directly reimbursable by our customers. Our anticipated growth capital and maintenance capital
expenditures during 2022 include expenditures related to the operations of Oasis Midstream which we acquired on February 1,
2022 (see “Outlook and Trends” above for a further discussion of this acquisition). We anticipate that our growth and
reimbursable capital expenditures in 2022 will increase the services we can provide to our customers and the operating
efficiencies of our systems. We expect to finance our capital expenditures with a combination of cash generated by our
operating subsidiaries, distributions received from our equity investments and borrowings under our credit facility. Additional
commitments or expenditures will be made at our discretion, and any discontinuation of the construction of these projects could
result in less future operating cash flows and earnings.
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The following table summarizes our capital expenditures for the year ended December 31, 2021 (in millions):
Growth capital
Maintenance capital
Other(1)
Purchases of property, plant and equipment
$
$
59.5
19.3
4.4
83.2
(1) Represents purchases of property, plant and equipment that are reimbursable by third parties.
Acquisition and Divestiture. Below is a summary of the acquisition and divestiture activities that impacted our investing
activities during the years ended December 31, 2021 and 2020. For a further discussion of these transactions, see Part IV, Item
15. Exhibits, Financial Statement Schedules, Note 3 and Note 6.
•
•
•
In November 2021, we sold our remaining Stagecoach Gas equity investment for approximately $15 million;
In April 2020, we acquired NGL assets from Plains for approximately $162 million; and
In October 2020, we sold our Fayetteville gathering assets for approximately $23 million.
Investments in Unconsolidated Affiliates. Pursuant to our joint venture agreements with our respective equity investments, we
periodically make contributions to our equity investments to fund their expansion projects and for other operating purposes.
During the years ended December 31, 2021 and 2020, we contributed approximately $6.9 million and $6.0 million to our Tres
Holdings equity investment for its operating purposes and we contributed approximately $10.7 million and $3.4 million to our
Crestwood Permian equity investment primarily to fund its expansion projects. During the year ended December 31, 2021, we
received a distribution from Stagecoach Gas of approximately $614 million, which represented our proportionate share of the
gross proceeds received by Stagecoach Gas related to the sale of certain of its assets to Kinder Morgan as discussed in “Outlook
and Trends” above. For further discussion of this distribution, see Part IV, Item 15. Exhibits, Financial Statement Schedules,
Note 6.
Financing Activities
Below is a summary of the equity and debt transactions that impacted our financing activities during the years ended
December 31, 2021 and 2020.
Equity and Debt Transactions
•
•
•
•
•
•
During the year ended December 31, 2021, CEQP paid approximately $275.6 million in conjunction with the
Crestwood Holdings Transactions;
During the year ended December 31, 2021, distributions to our partners decreased by approximately $18.4 million
compared to 2020, primarily due to the decrease in common units outstanding as a result of the Crestwood Holdings
Transactions;
During the year ended December 31, 2021, our taxes paid for unit-based compensation vesting decreased by
approximately $7.2 million compared to 2020, primarily due to lower vesting of unit-based compensation awards;
During the year ended December 31, 2021, we paid $690.5 million to repurchase and cancel approximately $687.2
million of our senior notes due 2023 and during the year ended December 31, 2020, we paid approximately $12.6
million to repurchase and cancel approximately $12.8 million of our senior notes due 2023;
During the year ended December 31, 2021, we received net proceeds of approximately $691.0 million from the
issuance of our senior notes due 2029; and
During the year ended December 31, 2021, our other debt-related transactions resulted in net repayments of
approximately $446.4 million compared to net proceeds of approximately $161.9 million during the year ended
December 31, 2020.
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Guarantor Summarized Financial Information
Crestwood Midstream and Crestwood Midstream Finance Corp. are issuers of our debt securities (the Issuers). Crestwood
Midstream is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries.
Crestwood Midstream Finance Corp. is Crestwood Midstream’s 100% owned subsidiary and has no material assets or
operations other than those related to its service as co-issuer of our senior notes. Obligations under Crestwood Midstream’s
senior notes and its credit facility are jointly and severally guaranteed by substantially all of its subsidiaries (collectively, the
Guarantor Subsidiaries), except for Crestwood Infrastructure Holdings LLC, Crestwood Niobrara LLC, Crestwood Pipeline and
Storage Northeast LLC, Powder River Basin Industrial Complex LLC, and Tres Palacios Holdings LLC and their respective
subsidiaries (collectively, Non-Guarantor Subsidiaries). The assets and credit of our Non-Guarantor Subsidiaries are not
available to satisfy the debts of the Issuers or Guarantor Subsidiaries, and the liabilities of our Non-Guarantor Subsidiaries do
not constitute obligations of the Issuers or Guarantor Subsidiaries. See Part IV, Item 15. Exhibits, Financial Statement
Schedules, Note 9 for additional information regarding our credit facility and senior notes and related guarantees.
The following tables provide summarized financial information for the Issuers and Guarantor Subsidiaries (collectively, the
Obligor Group) on a combined basis after elimination of significant intercompany balances and transactions between entities in
the Obligor Group. The investment balances in the Non-Guarantor Subsidiaries have been excluded from the supplemental
summarized combined financial information. Transactions with other related parties, including the Non-Guarantor Subsidiaries,
represent affiliate transactions and are presented separately in the summarized combined financial information below.
Summarized Combined Balance Sheet Information (in millions)
Current assets
Current assets - affiliates
Property, plant and equipment, net
Non-current assets
Current liabilities
Current liabilities - affiliates
Long-term debt, less current portion
Non-current liabilities
Summarized Combined Income Statement Information (in millions)
Revenues
Revenues - affiliates
Cost of products/services sold
Cost of products/services sold - affiliates
Operations and maintenance expenses(1)
General and administrative expenses(2)
Operating income
Net income
December 31, 2021
574.3
8.4
2,161.5
642.3
578.9
14.7
2,052.1
138.7
$
$
$
$
$
$
$
$
Year Ended December 31, 2021
$
$
$
$
$
$
$
$
4,461.4
30.3
3,692.4
136.8
102.0
90.2
230.4
92.8
(1) We have operating agreements with certain of our affiliates pursuant to which we charge them operations and maintenance expenses in accordance with
their respective agreements, and these charges are reflected as a reduction of operations and maintenance expenses in our consolidated statements of
operations. During the year ended December 31, 2021, we charged $31.8 million to our affiliates under these agreements. See Part IV, Item 15. Exhibits,
Financial Statement Schedules, Note 19 for a further description of our related party operating agreements.
(2)
Includes $30.9 million of net general and administrative expenses that were charged by our affiliates to us.
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Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Interest Rate Risk
In order to maintain a cost effective capital structure, it is our policy to borrow funds using a mix of fixed rate debt and variable
rate debt. The market risk inherent in our debt instruments is the potential change arising from increases or decreases in interest
rates as discussed below.
For fixed rate debt, changes in the interest rates generally affect the fair value of the debt instrument, but not our earnings or
cash flows. Conversely, for variable rate debt, changes in interest rates generally do not impact the fair value of the debt
instrument, but may affect our future earnings and cash flows.
As of December 31, 2021, the carrying value and fair value of our fixed rate debt instruments was approximately $1.8 billion
and $1.9 billion, respectively. As of December 31, 2020, both the carrying value and fair value of our fixed rate debt
instruments was approximately $1.8 billion. For a further discussion of our fixed rate debt, see Part IV, Item 15. Exhibits,
Financial Statement Schedules, Note 9.
We are subject to the risk of loss associated with changes in interest rates on our credit facility. At December 31, 2021, we had
obligations totaling $282.0 million outstanding under the credit facility. These floating rate obligations expose us to the risk of
increased interest payments in the event of increases in short-term interest rates. If the interest rate on our credit facility were to
fluctuate by 1% from the rate as of December 31, 2021, our annual interest expense would have changed by approximately $2.8
million.
Commodity Price, Market and Credit Risk
Inherent in our business are certain business risks, including market risk and credit risk.
Market Risk
We typically do not take title to the natural gas, NGLs or crude oil that we gather, store, or transport for our customers.
However, we do take title to crude oil, natural gas and NGLs under certain purchase and sale agreements and percentage-of-
proceeds contracts related to our gathering and processing services, and to NGLs and crude oil marketed or supplied by our
NGL and crude oil storage and logistics operations. Our current business model is designed to minimize our exposure to
fluctuations in commodity prices, although we are willing to assume commodity price risk in certain processing and marketing
activities. We remain subject to volumetric risk under contracts without minimum volume commitments or take-or-pay pricing
terms, for which market conditions can negatively influence our producer customers’ decisions to develop or produce
hydrocarbons.
In our storage and logistics operations, we consider market risk to be the risk that the value of our NGL and crude services
portfolio will change, either favorably or unfavorably, in response to changing market conditions. We take an active role in
managing and controlling market risk and have established control procedures, which are reviewed on an ongoing basis. We
monitor market risk through a variety of techniques, including daily reporting of the portfolio’s position to senior management.
We attempt to minimize credit risk exposure through credit policies and periodic monitoring procedures as well as through
customer deposits, letters of credit and entering into netting agreements that allow for offsetting counterparty receivable and
payable balances for certain financial transactions, as deemed appropriate. The counterparties associated with our price risk
management activities are energy marketers, propane retailers, resellers, and dealers.
We engage in hedging and risk management transactions, including various types of forward contracts, options, swaps and
futures contracts, to reduce the effect of price volatility on our product costs, protect the value of our inventory positions and to
help ensure the availability of propane during periods of short supply. We attempt to balance our contractual portfolio by
purchasing volumes only when we have a matching purchase commitment from our marketing customers. However, we may
experience net unbalanced positions from time to time, which we believe to be immaterial in amount. In addition to our ongoing
policy to maintain a balanced position, for accounting purposes we are required, on an ongoing basis, to track and report the
market value of our derivative portfolio. We also utilize hedging and risk management transactions to reduce the impact of
price risk under certain contracts in our gathering and processing operations. Our derivatives are not designated as hedges for
accounting purposes.
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The fair value of the derivatives contracts related to price risk management activities as of December 31, 2021 were assets of
$42.1 million and liabilities of $114.6 million. We use observable market values for determining the fair value of these
derivative contracts. In cases where actively quoted prices are not available, other external sources are used that incorporate
information about commodity prices in actively quoted markets, quoted prices in less active markets and other market
fundamental analysis. Our risk management function regularly compares valuations to independent sources and models on a
quarterly basis. The following table represents the impact that a 10% change in market prices would have on the underlying fair
value of our commodity-based derivative instruments, along with the net unbalanced position of those commodity-based
derivatives at December 31, 2021 and the inventory position that would substantially offset that theoretical change at
December 31, 2021:
Natural gas
NGLs
Crude oil
Credit Risk
December 31, 2021
Change in Fair Value
of Commodity-Based
Derivatives
(in millions)
Net Unbalanced
Derivative
Position
Inventory
Position
$
$
$
2.4
15.5
4.2
6.3 Bcf
1.7 Bcf
3.4 MMBbls
2.8 MMBbls
0.6 MMBbls
0.4 MMBbls
Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an
active role in managing and controlling credit risk and have established control procedures, which are reviewed on an ongoing
basis. We have diversified our credit risk through having long-term contracts with many investment grade customers and
creditworthy producers. Additionally, we perform credit analyses of our customers on a regular basis pursuant to our corporate
credit policy. We have not had any significant losses due to failures to perform by our counterparties.
Under a number of our customer contracts, there are provisions that provide for our right to request or demand credit assurances
from our customers including the posting of letters of credit, surety bonds, cash margin or collateral held in escrow for varying
levels of future revenues. We continue to closely monitor our producer customer base since a majority of our customers for our
gathering and processing services are either not rated by the major rating agencies or had below investment grade credit ratings.
Item 8. Financial Statements and Supplementary Data
Reference is made to the financial statements and report of independent registered public accounting firm included later in this
report under Part IV, Item 15. Exhibits, Financial Statement Schedules.
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
None.
Item 9A. Controls and Procedures
Disclosure Controls and Procedures
As of December 31, 2021, Crestwood Equity and Crestwood Midstream carried out an evaluation under the supervision and
with the participation of their respective management, including the Chief Executive Officers and Chief Financial Officers of
their General Partners, as to the effectiveness, design and operation of our disclosure controls and procedures (as defined in the
Securities Exchange Act of 1934, as amended (Exchange Act) Rules 13a-15(e) and 15d-15(e). Crestwood Equity and
Crestwood Midstream maintain controls and procedures designed to provide reasonable assurance that information required to
be disclosed in their respective reports that are filed or submitted under the Exchange Act of 1934, as amended, are recorded,
processed, summarized and reported within the time periods specified by the rules and forms of the SEC, and that information
is accumulated and communicated to their respective management, including the Chief Executive Officers and Chief Financial
Officers of their General Partners, as appropriate, to allow timely decisions regarding required disclosure. Such management,
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including the Chief Executive Officers and Chief Financial Officers of their General Partners, does not expect that the
disclosure controls and procedures or the internal controls will prevent and/or detect all errors and all fraud. A control system,
no matter how well conceived and operated, can provide only reasonable, not absolute, assurance that the objectives of the
control system are met. Further, the design of a control system must reflect the fact that there are resource constraints, and the
benefits of controls must be considered relative to their costs. Crestwood Equity’s and Crestwood Midstream’s disclosure
controls and procedures are designed to provide reasonable assurance of achieving their objectives and the Chief Executive
Officers and Chief Financial Officers of their General Partners concluded that such disclosure controls and procedures were
effective at the reasonable assurance level as of December 31, 2021.
Changes in Internal Control over Financial Reporting
There have been no changes in Crestwood Equity’s or Crestwood Midstream’s internal control over financial reporting during
the fourth quarter of 2021 that have materially affected, or are reasonably likely to materially affect Crestwood Equity’s and
Crestwood Midstream’s internal control over financial reporting.
Management’s Report on Internal Control Over Financial Reporting
Crestwood Equity’s and Crestwood Midstream’s management is responsible for establishing and maintaining adequate internal
control over financial reporting, pursuant to Exchange Act Rules 13a-15(f). Crestwood Equity’s and Crestwood Midstream’s
internal control systems were designed to provide reasonable assurance to their respective management and board of directors
regarding the preparation and fair presentation of published financial statements in accordance with GAAP.
Management recognizes that there are inherent limitations in the effectiveness of any system of internal control, and
accordingly, even effective internal control can provide only reasonable assurance with respect to financial statement
preparation and fair presentation. Further, because of changes in conditions, the effectiveness of internal control may vary over
time.
Under the supervision and with the participation of Crestwood Equity’s and Crestwood Midstream’s management, including the
Chief Executive Officers and Chief Financial Officers of their General Partners, Crestwood Equity and Crestwood Midstream
assessed the effectiveness of their respective internal control over financial reporting as of December 31, 2021. In making this
assessment, Crestwood Equity and Crestwood Midstream used the criteria set forth in the Internal Control-Integrated
Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework). Based
upon such assessment, Crestwood Equity and Crestwood Midstream concluded that, as of December 31, 2021, their respective
internal control over financial reporting is effective, based upon those criteria.
Crestwood Equity’s independent registered public accounting firm, Ernst & Young LLP, issued an attestation report dated
February 25, 2022, on the effectiveness of our internal control over financial reporting, which is included herein.
Item 9B. Other Information
None.
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PART III
Item 10, “Directors, Executive Officers and Corporate Governance;” Item 11, “Executive Compensation;” Item 12, Security
Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters;” and Item 13, “Certain
Relationships and Related Transactions, and Director Independence” have been omitted from this report for Crestwood
Midstream pursuant to the reduced disclosure format permitted by General Instruction I to Form 10-K.
Item 10. Directors, Executive Officers and Corporate Governance
Our General Partner Manages Crestwood Equity Partners LP
The information required to be disclosed under this Item 10 will be presented in our definitive proxy statement for the 2022
annual meeting of unitholders, which is expected to be filed pursuant to Regulation 14A (our Proxy Statement) within 120 days
after the end of the fiscal year covered by this Form 10-K under the following sections, which information is to be incorporated
by reference herein:
•
•
•
•
•
•
Director Election Proposal;
Executive Officers of our General Partner;
Section 16(a) Beneficial Ownership Regarding Compliance:
Code of Ethics;
Governance - Director Nominations; and
Governance - Board Committees
Item 11. Executive Compensation
The information required to be disclosed under this Item 11 will be presented in our Proxy Statement under the following
sections, which information is to be incorporated by reference herein:
•
•
•
Compensation of Directors and Executive Officers:
Governance - Compensation Committee - Interlocks and Insider Participation; and
Compensation of Directors and Executive Officers - Compensation Committee Report
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters
The information required to be disclosed under this Item 12 will be presented in our Proxy Statement under the following
sections, which information is to be incorporated by reference herein:
•
•
Securities Authorized for Issuance Under Equity Compensation Plans; and
Security Ownership of Certain Beneficial Owners and Management
Item 13. Certain Relationships, Related Transactions and Director Independence
The information required to be disclosed under this Item 13 will be presented in our Proxy Statement under the following
sections, which information is to be incorporated by reference herein:
•
•
Transactions with Related Persons, Promoters and Certain Control Persons; and
Governance - Director Independence
Item 14. Principal Accountant Fees and Services
The information required to be disclosed under this Item 14 will be presented in our Proxy Statement under the section
“Independent Auditor Proposal,” which information is to be incorporated by reference herein.
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Item 15. Exhibits, Financial Statement Schedules
(a) Exhibits, Financial Statements and Financial Statement Schedules:
PART IV
1. Financial Statements:
See Index Page for Financial Statements
2. Financial Statement Schedules:
Schedule I: Parent Only Condensed Financial Statements
Schedule II: Valuation and Qualifying Accounts
Other financial statement schedules have been omitted because they are either not required, are immaterial or are
not applicable or because equivalent information has been included in the financial statements, the notes thereto or
elsewhere herein.
3. Exhibits:
Exhibit
Number
2.1
2.2
2.3
2.4
2.5
3.1
3.2
3.3
3.4
3.5
Description
Contribution Agreement, dated as of April 20, 2016, by and between Crestwood Pipeline and Storage
Northeast LLC and Con Edison Gas Pipeline and Storage Northeast, LLC (incorporated herein by
reference to Exhibit 2.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 22, 2016).
Purchase Agreement dated as of April 9, 2019 by and between Crestwood Niobrara LLC and Williams
MLP Operating LLC (incorporated by reference to Exhibit 2.1 to Crestwood Equity Partners LP’s
Form 8-K filed on April 10, 2019)
Purchase Agreement, dated as of March 25, 2021, by and among Crestwood Holdings LLC, as the
seller, and Crestwood Equity Partners LP, as the purchaser, and, for the limited purposes set forth
therein, Crestwood Equity GP LLC (incorporated by reference to Exhibit 2.1 to Crestwood Equity
Partners LP’s Form 8-K filed on March 26, 2021).
Purchase and Sale Agreement, dated as of May 31, 2021 among Con Edison Gas Pipeline and Storage
Northeast, LLC, Crestwood Pipeline and Storage Northeast LLC, as the Sellers, Stagecoach Gas
Services LLC as the Company, Kinder Morgan Operating LLC “A” as Buyer, Con Edison
Transmission, Inc. (solely for the limited purposes set forth therein) and Crestwood Midstream
Partners LP (solely for the limited purposes set forth therein) (incorporated by reference to Exhibit 2.1
to Crestwood Equity Partners LP’s Form 8-K filed on June 1, 2021).
Agreement and Plan of Merger, dated as of October 25, 2021, by and among Oasis Midstream Partners
LP, OMP GP LLC, Crestwood Equity Partners LP, Project Falcon Merger Sub LLC, Project Phantom
Merger Sub LLC, and, solely for the purposes of Section 2.1(a)(i) thereof, Crestwood Equity GP LLC
(incorporated by reference to Exhibit 2.1 to Crestwood Equity Partners LP’s Form 8-K filed on
October 28, 2021).
Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by reference to Exhibit 3.1 to
Inergy, L.P.’s Registration Statement on Form S-1 (Registration No. 333-56976) filed on March 14,
2001)
Certificate of Correction of Certificate of Limited Partnership of Inergy, L.P. (incorporated herein by
reference to Exhibit 3.1 to Inergy, L.P.’s Form 10-Q filed on May 12, 2003)
Amendment to the Certificate of Limited Partnership of Crestwood Equity Partners LP (f/k/a Inergy,
L.P.) (the “Partnership”) dated as of October 7, 2013 (incorporated herein by reference to Exhibit 3.2
to Crestwood Equity Partners LP’s Form 8-K filed on October 10, 2013)
Sixth Amended and Restated Agreement of Limited Partnership of Crestwood Equity Partners LP
dated August 20, 2021 (incorporated by reference to Exhibit 3.1 to Crestwood Equity Partners LP’s
Form 8-K filed on August 20, 2021).
Certificate of Formation of Inergy GP, LLC (incorporated herein by reference to Exhibit 3.5 to Inergy,
L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7, 2001)
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Exhibit
Number
3.6
3.7
3.8
3.9
3.10
3.11
3.12
3.13
3.14
4.1
4.2
4.3
4.4
4.5
4.6
4.7
Description
Certificate of Amendment of Crestwood Equity GP LLC (f/k/a Inergy GP, LLC) dated October 7,
2013 (incorporated herein by reference to Exhibit 3.3A to Crestwood Equity Partners LP’s Form 10-Q
filed on November 8, 2013)
Second Amended and Restated Limited Liability Company Agreement of Crestwood Equity GP LLC
dated August 20, 2021 (incorporated by reference to Exhibit 3.2 to Crestwood Equity Partners LP’s
Form 8-K filed on August 20, 2021).
Certificate of Limited Partnership of Inergy Midstream, L.P. (incorporated herein by reference to
Exhibit 3.4 to Inergy Midstream, L.P.’s Form S-1/A filed on November 21, 2011)
Amendment to the Certificate of Limited Partnership of Crestwood Midstream Partners LP (f/k/a
Inergy Midstream, L.P.) (incorporated herein by reference to Exhibit 3.2 to Inergy Midstream, L.P.’s
Form 8-K filed on October 10, 2013)
Second Amended and Restated Agreement of Limited Partnership of Crestwood Midstream Partners
LP, dated as of September 30, 2015 (incorporated by reference to Exhibit 3.1 to Crestwood Midstream
Partners LP’s Form 8-K filed on October 1, 2015).
Certificate of Formation of NRGM GP, LLC (incorporated herein by reference to Exhibit 3.7 to Inergy
Midstream, L.P.’s Form S-1/A filed on November 21, 2011)
Certificate of Amendment of Crestwood Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated
herein by reference to Exhibit 3.37 to Crestwood Midstream Partners LP’s Form S-4/A filed on
October 28, 2013)
Amended and Restated Limited Liability Company Agreement of NRGM GP, LLC, dated December
21, 2011 (incorporated herein by reference to Exhibit 3.2 to Inergy Midstream, L.P.’s Form 8-K filed
on December 22, 2011)
Amendment No. 1 to the Amended and Restated Limited Liability Company Agreement of Crestwood
Midstream GP LLC (f/k/a NRGM GP, LLC) (incorporated herein by reference to Exhibit 3.39 to
Crestwood Midstream Partners LP’s Form S-4/A filed on October 28, 2013)
Specimen Unit Certificate for Common Units (incorporated herein by reference to Exhibit 4.3 to
Inergy L.P.’s Registration Statement on Form S-1/A (Registration No. 333-56976) filed on May 7,
2001)
Indenture, dated as of March 14, 2017, among Crestwood Midstream Partners LP, Crestwood
Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as
trustee (incorporated by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on
March 15, 2017)
Supplemental Indenture dated as of June 5, 2017, among Crestwood Midstream Partners LP,
Crestwood Midstream Finance Corporation, each existing Guarantor and U.S. Bank National
Association, as trustee (incorporated by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s
Form 10-Q filed on August 4, 2017)
Supplemental Indenture dated as of December 1, 2017, among Crestwood Midstream Partners LP,
Crestwood Midstream Finance Corporation, each existing Guarantor and U.S. Bank National
Association, as trustee (incorporated herein by reference to Exhibit 4.4 to Crestwood Equity Partners
LP’s Form 10-K filed on February 26, 2018)
Indenture, dated as of March 23, 2015, among Crestwood Midstream Partners LP, Crestwood
Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as
trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream Partners LP’s Form
8-K filed on March 27, 2015)
First Supplemental Indenture, dated March 4, 2016, by and among Crestwood Midstream Partners LP,
Crestwood Midstream Finance Corp., the Guarantors named therein and U.S. Bank National
Association (incorporated herein by reference to Exhibit 4.3 to Crestwood Midstream Partners LP’s
Form 8-K filed on March 7, 2016)
Supplemental Indenture, dated as of June 3, 2016, among Crestwood Midstream Partners LP,
Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National
Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream
Partners LP’s Form 10-Q filed on August 4, 2016)
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Exhibit
Number
4.8
4.9
4.10
4.11
4.12
4.13
4.14
4.15
4.16
4.17
4.18
4.19
4.20
4.21
Description
Supplemental Indenture, dated as of September 30, 2016, among Crestwood Midstream Partners LP,
Crestwood Midstream Finance Corp., the guarantors named therein and U.S. Bank National
Association, as trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Midstream
Partners LP’s Form 10-Q filed on November 4, 2016)
Indenture, dated as of April 15, 2019, among Crestwood Midstream Partners LP, Crestwood
Midstream Finance Corp., the guarantors named therein and U.S. Bank National Association, as
trustee (incorporated herein by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K
filed on April 16, 2019
Third Amended and Restated Limited Liability Company Agreement for Crestwood Niobrara LLC,
dated between Crestwood Midstream Partners LP and CN Jackalope Holdings, LLC (incorporated
herein by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 10-Q filed on May 2,
2019)
First Amendment to the Third Amended and Restated Limited Liability Company Agreement of
Crestwood Niobrara LLC dated as of April 9, 2019 (incorporated by reference to Exhibit 4.1 to
Crestwood Equity Partners LP’s Form 8-K filed on August 20, 2021).
Registration Rights Agreement, dated December 28, 2017, by and among Crestwood Equity Partners
LP and CN Jackalope Holdings, LLC (incorporated herein by reference to Exhibit 4.10 to Crestwood
Equity Partners LP’s Form 10-K filed on February 26, 2018)
First Amendment to Registration Rights Agreement dated as of April 9, 2019 by and between
Crestwood Equity Partners LP and CN Jackalope Holdings, LLC (incorporated herein by reference to
Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on April 10, 2019)
Registration Rights Agreement, dated March 14, 2017, by and among Crestwood Midstream Partners
LP, Crestwood Midstream Finance Corp., the guarantors named therein and J.P. Morgan Securities
LLC, as representative of the several initial purchasers, with respect to the 5.72% Senior Notes due
2025 (incorporated by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on
March 15, 2017).
Registration Rights Agreement, dated as of September 30, 2015, by and among Crestwood Equity
Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to
Crestwood Equity Partners LP’s Form 8-K filed on October 1, 2015)
Supplemental Indenture dated as of October 22, 2018, among Crestwood Midstream Partners LP,
Crestwood Midstream Finance Corporation, each existing Guarantor and U.S. Bank National
Association, as trustee (incorporated herein by reference to Exhibit 4.13 to Crestwood Equity Partners
LP’s Form 10-K filed on February 22, 2019)
Indenture, dated January 21, 2021, among Crestwood Midstream Partners LP, Crestwood Midstream
Finance Corp., the guarantors named therein and U.S. Bank National Association, as trustee
(incorporated herein by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on
January 21, 2021)
First Supplemental Indenture, dated as of February 1, 2022, among Crestwood Midstream Partners LP,
Crestwood Midstream Finance Corp., the guarantors named therein and Regions Bank (incorporated
herein by reference to Exhibit 4.1 to Crestwood Equity Partners LP’s Form 8-K filed on February 3,
2022).
Fourth Supplemental Indenture, dated as of February 1, 2022, among Crestwood Midstream Partners
LP, Crestwood Midstream Finance Corporation, the guarantors named therein and U.S. Bank National
Association (incorporated herein by reference to Exhibit 4.2 to Crestwood Equity Partners LP’s Form
8-K filed on February 3, 2022).
First Supplemental Indenture, dated as of February 1, 2022, among Crestwood Midstream Partners LP,
Crestwood Midstream Finance Corporation, the guarantors named therein and U.S. Bank National
Association (incorporated herein by reference to Exhibit 4.3 to Crestwood Equity Partners LP’s Form
8-K filed on February 3, 2022).
First Supplemental Indenture, dated as of February 1, 2022, among Crestwood Midstream Partners LP,
Crestwood Midstream Finance Corporation, the guarantors named therein and U.S. Bank National
Association (incorporated by reference to Exhibit 4.4 to Crestwood Equity Partners LP’s Form 8-K
filed on February 3, 2022).
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Exhibit
Number
4.22
**4.23
*10.1
*10.2
*10.3
*10.4
*10.5
*10.6
*10.7
*10.8
*10.9
*10.10
*10.11
10.12
10.13
10.14
10.15
*10.16
*10.17
Description
Registration Rights Agreement, dated as of February 1, 2022 by and among Crestwood Equity
Partners LP, Oasis Petroleum Inc., OMS Holdings LLC and Oasis Investment Holdings LLC
(incorporated herein by reference to Exhibit 4.6 to Crestwood Equity Partners LP’s Form 8-K filed on
February 3, 2022).
Description of Securities
Omnibus Amendment to Employment Agreements dated February 22, 2018 by and between
Crestwood Operations LLC and each of Robert G. Phillips, Robert Halpin, Steven Dougherty, Joel
Lambert and William H. Moore (incorporated herein by reference to Exhibit 10.2 to Crestwood Equity
Partners LP’s Form 10-K filed on February 26, 2018)
Employment Agreement between Robert G. Phillips and Crestwood Operations LLC dated as of
January 21, 2014 (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s
Form 8-K filed on January 27, 2014)
Employment Agreement between Joel Lambert and Crestwood Operations LLC dated as of January
21, 2014 (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s Form
10-K filed on February 28, 2014)
Employment Agreement between William H. Moore and Crestwood Operations LLC dated as of
January 21, 2014 (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity Partners LP’s
Form 10-K filed on March 2, 2015)
Employment Agreement between Steven M. Dougherty and Crestwood Operations LLC dated as of
January 21, 2014 (incorporated herein by reference to Exhibit 10.4 to Crestwood Equity Partners LP’s
Form 10-K filed on February 29, 2016)
Amended and Restated Employee Agreement between Robert T. Halpin and Crestwood Operations
LLC dated as of April 1, 2015 (incorporated herein by reference to Exhibit 10.5 to Crestwood Equity
Partners LP’s Form 10-K filed on February 29, 2016)
Crestwood Equity Partners LP Long Term Incentive Plan (incorporated herein by reference to Exhibit
10.7 to Crestwood Equity Partners LP’s Form 10-K filed on February 28, 2014)
Form of Crestwood Equity Partners LP’s Restricted Unit Award Agreement (incorporated herein by
reference to Exhibit 4.12 to Crestwood Equity Partner LP’s Form S-8 filed on January 16, 2015)
Form of Crestwood Equity Partners LP’s Phantom Unit Award Agreement (incorporated herein by
reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on January 23, 2015)
Form of Crestwood Equity Partners LP’s Performance Unit Grant Agreement (incorporated by
reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 10-Q filed on May 4, 2017)
Crestwood Equity Partners Non-Qualified Deferred Compensation Plan (incorporated herein by
reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on November 15, 2016)
Guaranty, dated as of April 20, 2016, made by Crestwood Equity Partners LP in favor of Con Edison
Gas Pipeline and Storage Northeast, LLC (incorporated herein by reference to Exhibit 10.1 to
Crestwood Equity Partners LP’s Form 8-K filed on April 22, 2016)
Amended and Restated Limited Liability Company Agreement of Stagecoach Gas Services LLC dated
as of June 3, 2016. (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners
LP’s Form 8-K filed on June 8, 2016)
Registration Rights Agreement, dated as of September 30, 2015, by and among Crestwood Equity
Partners LP and the Purchasers named therein (incorporated herein by reference to Exhibit 10.1 to
Crestwood Equity Partners LP’s Form 8-K filed on October 1, 2015)
Board Representation and Standstill Agreement, dated as of September 30, 2015, by and among
Crestwood Equity GP LLC, Crestwood Equity Partners LP and the Purchasers named therein
(incorporated herein by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 8-K filed
on October 1, 2015)
Crestwood Equity Partners LP 2018 Long Term Incentive Plan (incorporated by reference to Exhibit
10.1 to the Registrant’s Current Report on Form 8-K, filed with the Commission on May 16, 2018)
First Amendment to the Crestwood Equity Partners LP 2018 Long Term Incentive Plan (incorporated
by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on August 20, 2021).
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Exhibit
Number
*10.18
*10.19
*10.20
*10.21
*10.22
*10.23
10.24
10.25
10.26
10.27
*10.28
10.29
10.30
*10.31
16.1
**21.1
**22.1
**23.1
**23.2
**31.1
**31.2
Description
Crestwood Equity Partners LP Employee Unit Purchase Plan. (incorporated by reference to Exhibit
10.1 to the Registrant’s Form 8-K, filed with the Commission on August 24, 2018)
Form of Crestwood Equity Partners LP’s Executive Restricted Unit Award Grant Notice (incorporated
by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 10-Q filed November 1, 2018)
Form of Crestwood Equity Partners LP’s Non-Executive Restricted Unit Award Grant Notice
(incorporated by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 10-Q filed on
November 1, 2018)
Form of Crestwood Equity Partners LP’s Director Restricted Unit Award Grant Notice (incorporated
by reference to Exhibit 10.3 to Crestwood Equity Partners LP’s Form 10-Q filed on November 1,
2018)
Form of Crestwood Equity Partners LP’s Restricted Unit Award Agreement (incorporated by reference
to Exhibit 10.4 to Crestwood Equity Partners LP’s Form 10-Q filed on November 1, 2018)
Form of Director and Officer Indemnification Agreement filed as Exhibit 10.1 to Crestwood Equity
Partners LP’s Form 10-Q filed on August 6, 2020.
Common Unit Purchase Agreement, dated as of March 25, 2021, by and among Crestwood Equity
Partners LP, Crestwood Gas Services Holdings LLC and the Purchasers named therein (incorporated
by reference to Exhibit 10.2 to Crestwood Equity Partners LP’s Form 8-K filed on March 26, 2021).
Registration Rights Agreement, dated March 30, 2021, by and between Crestwood Equity Partners LP
and the Purchasers named therein (incorporated by reference to Exhibit 10.1 to Crestwood Equity
Partners LP’s Form 8-K filed on March 31, 2021).
Support Agreement, dated as of October 25, 2021, by and among Crestwood Equity Partners LP, Oasis
Midstream Partners LP, OMP GP LLC, Oasis Petroleum Inc. and OMS Holdings LLC (incorporated
by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on October 28, 2021).
Third Amended and Restated Credit Agreement, dated as of December 20, 2021, by and among
Crestwood Midstream Partners LP, as borrower, the lenders party thereto, and Wells Fargo Bank,
National Association, as Administrative Agent and Collateral Agent (incorporated by reference to
Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K filed on December 21, 2021).
Employment Agreement between Diaco Aviki and Crestwood Operations LLC dated as of January 18,
2022 (incorporated herein by reference to Exhibit 10.1 to Crestwood Equity Partners LP’s Form 8-K
filed on January 18, 2022).
Director Nomination Agreement, dated as of February 1, 2022, by and among Crestwood Equity
Partners LP, Crestwood Equity GP LLC and Oasis Petroleum Inc. (incorporated herein by reference to
Exhibit 10.2 to Crestwood Equity Partners LP’s Form 8-K filed on February 3, 2022).
Master Amendment to Commercial Agreements, dated as of February 1, 2022, by and among Oasis
Petroleum North America LLC, Oasis Petroleum Marketing LLC, Oasis Midstream Services LLC,
Oasis Midstream Partners LP, OMP Operating LLC and Bighorn Devco LLC (incorporated herein by
reference to Exhibit 10.3 to Crestwood Equity Partners LP’s Form 8-K filed on February 3, 2022).
Form of Director and Officer Indemnification Agreement (incorporated herein by reference to Exhibit
10.4 to Crestwood Equity Partners LP’s Form 8-K filed on February 3, 2022).
Letter Regarding Change in Certifying Accountant (incorporated herein by reference to Exhibit 16.1 to
Inergy, L.P.’s Form 8-K/A filed on July 23, 2013)
List of subsidiaries of Crestwood Equity Partners LP
List of Issuers of Guarantor Subsidiaries of Crestwood Midstream Partners LP
Consent of Ernst & Young LLP - Crestwood Equity Partners LP
Consent of Ernst & Young LLP - Stagecoach Gas Services LLC
Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended - Crestwood Equity Partners LP
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended - Crestwood Equity Partners LP
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Exhibit
Number
**31.3
**31.4
**32.1
**32.2
**32.3
**32.4
**99.1
Description
Certification of the Chief Executive Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended - Crestwood Midstream Partners LP
Certification of Chief Financial Officer pursuant to Rule 13a-14(a) and Rule 15d-14(a) of the
Securities Exchange Act, as amended - Crestwood Midstream Partners LP
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Equity Partners LP
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Equity Partners LP
Certification of the Chief Executive Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant
to Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Midstream Partners LP
Certification of the Chief Financial Officer pursuant to 18 U.S.C. Section 1350, as adopted pursuant to
Section 906 of the Sarbanes-Oxley Act of 2002 - Crestwood Midstream Partners LP
Financial Statements for Stagecoach Gas Services LLC as of November 24, 2021 and December 31,
2020 and for the period ended November 24, 2021 (unaudited) and the years ended December 31,
2020 and 2019 (audited) pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09)
**101.INS
Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File
because its XBRL tags are embedded within the Inline XBRL document
**101.SCH
Inline XBRL Taxonomy Extension Schema Document
**101.CAL
Inline XBRL Taxonomy Extension Calculation Linkbase Document
**101.LAB
Inline XBRL Taxonomy Extension Label Linkbase Document
**101.PRE
**101.DEF
104
Inline XBRL Taxonomy Extension Presentation Linkbase Document
Inline XBRL Taxonomy Extension Definition Linkbase Document
Cover Page Interactive Data File (contained in Exhibit 101)
*
**
Management contracts or compensatory plans or arrangements
Filed herewith
(b) Exhibits.
See exhibits identified above under Item 15(a)3.
(c) Financial Statement Schedules.
Financial Statements for Stagecoach Gas Services LLC as of November 24, 2021 and December 31, 2020 (audited)
and for the period ended November 24, 2021 (unaudited) and the years ended December 31, 2020 and 2019 (audited)
pursuant to Rule 3-09 of Regulation S-X (17 CFR 210.3-09) and is filed herein as Exhibit 99.1.
72
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Crestwood Equity Partners LP
Crestwood Midstream Partners LP
Index to Financial Statements
Crestwood Equity Partners LP
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)
Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial Reporting
Audited Consolidated Financial Statements:
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Comprehensive Income
Consolidated Statements of Partners’ Capital
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
Crestwood Midstream Partners LP
Report of Independent Registered Public Accounting Firm (PCAOB ID: 42)
Audited Consolidated Financial Statements:
Consolidated Balance Sheets
Consolidated Statements of Operations
Consolidated Statements of Partners’ Capital
Consolidated Statements of Cash Flows
Notes to Consolidated Financial Statements
74
76
77
78
79
80
81
90
83
85
86
87
88
90
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Report of Independent Registered Public Accounting Firm
The Board of Directors of Crestwood Equity GP LLC and Unitholders of Crestwood Equity Partners LP
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Crestwood Equity Partners LP (the Partnership) as of
December 31, 2021 and 2020, the related consolidated statements of operations, comprehensive income, partners’ capital and
cash flows for each of the three years in the period ended December 31, 2021, and the related notes and financial statement
schedules listed in the Index at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion,
the consolidated financial statements present fairly, in all material respects, the financial position of the Partnership at
December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended
December 31, 2021, in conformity with U.S. generally accepted accounting principles.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the Partnership's internal control over financial reporting as of December 31, 2021, based on criteria established in
Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission
(2013 framework) and our report dated February 25, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion
on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and
are required to be independent with respect to the Partnership in accordance with the U.S. federal securities laws and the
applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to
error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial
statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included
examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included
evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall
presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that
was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that
are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The
communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken
as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit
matters or on the accounts or disclosures to which it relates.
Description of the Matter As described in Note 2 to the consolidated financial statements, the Partnership recognizes
Revenue recognition – Measuring variable consideration
revenues for services and products under revenue contracts as obligations to perform services or
deliver/sell products under the contracts are satisfied. For a significant customer contract within
the Partnership’s Gathering and Processing North operating segment, consideration to be received
under the contact is estimated over the life of the contract and the contract’s transaction price is
allocated to each performance obligation in the contract and recognized as revenue when, or as,
the performance obligation is satisfied.
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Auditing the Partnership’s measurement of variable consideration under this contract involved
especially challenging judgment because the calculation involves subjective management
assumptions about estimates of future revenues including forecasted production of its customer
over the life of the contract. For example, the estimates of future revenues reflect management's
assumptions about future economic conditions and expected volumes to be gathered and
processed, and changes in those assumptions can have a material effect on the amount of revenue
recognized.
How We Addressed the
Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of
controls over the Partnership’s process to calculate the variable consideration, including the
underlying assumptions about estimates of expected volumes.
Our audit procedures included, among others, evaluating the significant assumptions and the
accuracy and completeness of the underlying data used in management’s calculation. This
included testing management’s forecasted volumes through comparison to the forecast production
of the customer, analyst forecasted commodity prices and historical data and the recalculation of
the transaction price based on the volumes and executed contract rates. In addition, we performed
sensitivity analyses to evaluate the changes in variable consideration that would result from
changes in the Partnership’s forecasted volumes included in the calculation of the transaction
price.
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 2013.
Houston, Texas
February 25, 2022
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Report of Independent Registered Public Accounting Firm on Internal Controls Over Financial Reporting
The Board of Directors of Crestwood Equity GP LLC and Unitholders of Crestwood Equity Partners LP
Opinion on Internal Control over Financial Reporting
We have audited Crestwood Equity Partners LP’s internal control over financial reporting as of December 31, 2021, based on
criteria established in Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the
Treadway Commission (2013 framework) (the COSO criteria). In our opinion, Crestwood Equity Partners LP (the Partnership)
maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on the
COSO criteria.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States)
(PCAOB), the consolidated balance sheets as of December 31, 2021 and 2020 and related consolidated statements of
operations, comprehensive income, partners’ capital and cash flows for each of the three years in the period ended December
31, 2021, and the related notes and financial statement schedules listed in the Index at Item 15(a) of the Partnership and our
report dated February 25, 2022 expressed an unqualified opinion thereon.
Basis for Opinion
The Partnership’s management is responsible for maintaining effective internal control over financial reporting and for its
assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Report
on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Partnership’s internal control
over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be
independent with respect to the Partnership in accordance with the U.S. federal securities laws and the applicable rules and
regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all
material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material
weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and
performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a
reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the
reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally
accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures
that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and
dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit
preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and
expenditures of the company are being made only in accordance with authorizations of management and directors of the
company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or
disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also,
projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate
because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young LLP
Houston, Texas
February 25, 2022
76
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Assets
Current assets:
CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(in millions, except unit information)
Cash
Accounts receivable, less allowance for doubtful accounts of $0.6 million and $0.9
million at December 31, 2021 and 2020
Inventory
Assets from price risk management activities
Prepaid expenses and other current assets
Total current assets
Property, plant and equipment
Less: accumulated depreciation
Property, plant and equipment, net
Intangible assets
Less: accumulated amortization
Intangible assets, net
Goodwill
Operating lease right-of-use assets, net
Investments in unconsolidated affiliates
Other non-current assets
Total assets
Liabilities and capital
Current liabilities:
Accounts payable
Accrued expenses and other liabilities
Liabilities from price risk management activities
Contingent consideration - current portion
Current portion of long-term debt
Total current liabilities
Long-term debt, less current portion
Contingent consideration
Other long-term liabilities
Deferred income taxes
Total liabilities
Commitments and contingencies (Note 10)
Interest of non-controlling partner in subsidiary
Crestwood Equity Partners LP partners' capital (62,991,511 common units issued and
outstanding at December 31, 2021 and 73,970,208 common and subordinated units
issued and outstanding at December 31, 2020)
Preferred units (71,257,445 units issued and outstanding at December 31, 2021 and 2020)
Total partners’ capital
Total liabilities and capital
See accompanying notes.
77
December 31,
2021
2020
$
13.3 $
14.0
378.0
156.5
42.1
14.8
604.7
3,771.5
992.1
2,779.4
1,126.1
393.2
732.9
138.6
27.4
155.8
6.9
262.2
89.1
27.2
13.4
405.9
3,759.6
842.5
2,917.1
1,126.1
331.8
794.3
138.6
36.8
943.7
7.3
$
4,445.7 $
5,243.7
$
336.5 $
147.1
114.6
—
0.2
598.4
2,052.1
—
258.7
2.3
2,911.5
160.3
122.0
76.3
19.0
0.2
377.8
2,483.8
38.0
253.3
2.7
3,155.6
434.6
432.7
487.6
612.0
1,099.6
$
4,445.7 $
1,043.4
612.0
1,655.4
5,243.7
Table of Contents
CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions, except per unit data)
Revenues:
Product revenues
Product revenues - related party (Note 19)
Service revenues
Service revenues - related party (Note 19)
Total revenues
Costs of product/services sold (exclusive of items shown separately below):
Product costs
Product costs - related party (Note 19)
Service costs
Total costs of products/services sold
Operating expenses and other:
Operations and maintenance
General and administrative
Depreciation, amortization and accretion
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
Operating income
Earnings (loss) from unconsolidated affiliates, net
Interest and debt expense, net
Gain (loss) on modification/extinguishment of debt
Other income (expense), net
Income (loss) before income taxes
Provision for income taxes
Net income (loss)
Net income attributable to non-controlling partner
Net income (loss) attributable to Crestwood Equity Partners LP
Net income attributable to preferred units
Net income (loss) attributable to partners
Net income (loss) per limited partner unit: (Note 14)
Basic
Diluted
Weighted-average limited partners’ units outstanding:
Basic
Dilutive
Diluted
See accompanying notes.
78
Year Ended December 31,
2020
2019
2021
$
4,145.4 $
1,793.0 $
2,752.4
25.8
396.4
1.4
27.3
433.5
0.5
2.9
426.6
—
4,569.0
2,254.3
3,181.9
3,688.8
136.8
18.3
3,843.9
1,558.8
2,469.7
21.0
20.7
45.4
29.8
1,600.5
2,544.9
121.0
97.6
244.2
39.6
—
—
502.4
222.7
(120.4)
(132.1)
(7.5)
0.1
(37.2)
(0.2)
(37.4)
41.1
(78.5)
60.1
131.8
91.5
237.4
26.0
80.3
—
567.0
86.8
32.5
138.8
103.4
195.8
6.2
—
(209.4)
234.8
402.2
32.8
(133.6)
(115.4)
0.1
(0.7)
(14.9)
(0.4)
(15.3)
40.8
(56.1)
60.1
—
0.6
320.2
(0.3)
319.9
34.8
285.1
60.1
225.0
3.11
2.93
71.8
5.1
76.9
$
(138.6) $
(116.2) $
$
$
(2.11) $
(2.11) $
(1.59) $
(1.59) $
65.6
—
65.6
73.2
—
73.2
Table of Contents
CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME
(in millions)
Year Ended December 31,
2020
2019
2021
Net income (loss)
Change in fair value of Suburban Propane Partners, L.P. units
Comprehensive income (loss)
Comprehensive income attributable to non-controlling partner
$
(37.4) $
(15.3) $
—
(37.4)
41.1
—
(15.3)
40.8
Comprehensive income (loss) attributable to Crestwood Equity Partners LP
$
(78.5) $
(56.1) $
319.9
0.3
320.2
34.8
285.4
See accompanying notes.
79
Table of Contents
CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in millions)
Preferred
Partners
Units
Capital
Common
Units
Subordinated
Units
Capital
Non-
Controlling
Partner
Total
Partners’
Capital
0.4 $ 1,240.5 $
181.3 $ 2,033.8
(172.4)
(6.6)
(239.1)
71.2
—
1.0
(0.3)
—
—
—
—
71.9
—
2.1
(0.6)
0.2
—
73.6
—
Balance at December 31, 2018
71.3 $ 612.0
Distributions to partners
Unit-based compensation charges
Taxes paid for unit-based
compensation vesting
Non-controlling interest
reclassification (Note 12)
Change in fair value of Suburban
Propane Partners, L.P. units
Other
Net income
Balance at December 31, 2019
Distributions to partners
Unit-based compensation charges
Taxes paid for unit-based
compensation vesting
Other
Net income (loss)
Balance at December 31, 2020
Crestwood Holdings Transactions
(Note 12)
Retirement of units (Note 12)
Distributions to partners
Unit-based compensation charges
Taxes paid for unit-based
compensation vesting
—
—
—
—
—
—
—
71.3
—
—
—
—
—
71.3
—
—
—
—
—
(60.1)
—
—
—
—
—
60.1
612.0
(60.1)
—
—
—
60.1
612.0
—
—
(60.1)
—
—
Other
Net income (loss)
Balance at December 31, 2021
—
—
—
60.1
71.3 $ 612.0
—
—
—
—
—
—
—
42.4
(11.0)
—
0.3
(4.0)
225.0
0.4
1,320.8
—
—
—
—
—
(182.7)
34.0
(15.6)
3.1
(116.2)
0.4
1,043.4
—
(273.2)
—
—
42.4
(11.0)
(178.8)
(178.8)
—
0.1
4.0
—
—
—
—
—
—
—
—
—
—
—
—
0.3
(3.9)
289.1
1,932.8
(242.8)
34.0
(15.6)
3.1
(56.1)
1,655.4
(273.2)
—
(224.4)
32.0
(8.4)
(3.3)
—
(78.5)
—
— $ 1,099.6
(11.5)
(0.4)
—
—
1.3
(0.4)
—
—
63.0
—
—
—
(164.3)
32.0
(8.4)
(3.3)
—
(138.6)
—
— $ 487.6 $
See accompanying notes.
80
Table of Contents
CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Operating activities
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion
Amortization of debt-related deferred costs
Unit-based compensation charges
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
(Gain) loss on modification/extinguishment of debt
(Earnings) loss from unconsolidated affiliates, net, adjusted for cash distributions
received
Deferred income taxes
Other
Changes in operating assets and liabilities:
Accounts receivable
Inventory
Prepaid expenses and other current assets
Accounts payable, accrued expenses and other liabilities
Reimbursements of property, plant and equipment
Change in price risk management activities, net
Net cash provided by operating activities
Investing activities
Acquisitions, net of cash acquired (Note 3)
Purchases of property, plant and equipment
Investments in unconsolidated affiliates
Capital distributions from unconsolidated affiliates
Net proceeds from sale of long-lived assets, including equity investments
Other
Net cash provided by (used in) investing activities
Year Ended December 31,
2021
2020
2019
$
(37.4) $
(15.3) $
319.9
244.2
237.4
195.8
6.7
34.9
39.6
—
—
7.5
138.0
(0.4)
0.3
(114.3)
(67.4)
(1.0)
148.3
4.3
23.4
426.7
6.5
30.7
26.0
80.3
—
(0.1)
6.5
0.1
(0.1)
(27.5)
(33.7)
(3.7)
(1.2)
15.7
86.5
408.1
6.2
47.0
6.2
—
(209.4)
—
6.9
—
—
42.9
10.9
0.1
(23.3)
24.8
(7.6)
420.4
—
(162.3)
(462.1)
(83.2)
(17.6)
(168.3)
(9.4)
(455.5)
(61.3)
652.0
17.7
—
568.9
39.4
27.3
—
35.5
0.8
(1.1)
(273.3)
(943.7)
81
Table of Contents
CRESTWOOD EQUITY PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(in millions)
Financing activities
Proceeds from the issuance of long-term debt
Payments on long-term debt
Payments on finance leases
Payments for deferred financing costs
Net proceeds from issuance of non-controlling interest
Payments for Crestwood Holdings Transactions
Distributions to partners
Distributions to non-controlling partner
Distributions to preferred unitholders
Taxes paid for unit-based compensation vesting
Net cash provided by (used in) financing activities
Net change in cash and restricted cash
Cash and restricted cash at beginning of period
Cash and restricted cash at end of period
Supplemental disclosure of cash flow information
Cash paid for interest
Cash paid for income taxes
Year Ended December 31,
2021
2020
2019
2,859.5
1,125.1
2,307.3
(3,287.5)
(975.8)
(1,729.5)
(2.8)
(17.9)
1.0
(275.6)
(3.1)
—
2.8
—
(3.5)
(9.0)
235.0
—
(164.3)
(182.7)
(172.4)
(40.2)
(60.1)
(8.4)
(37.1)
(60.1)
(15.6)
(25.0)
(60.1)
(11.0)
(996.3)
(146.5)
531.8
(0.7)
(11.7)
14.0
25.7
$
13.3 $
14.0 $
8.5
17.2
25.7
$
$
125.9 $
129.8 $
123.7
0.8 $
0.6 $
0.6
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued
expenses
$
(5.8) $
40.0 $
(27.7)
See accompanying notes.
82
Table of Contents
Report of Independent Registered Public Accounting Firm
The Board of Directors of Crestwood Equity GP LLC
Opinion on the Financial Statements
We have audited the accompanying consolidated balance sheets of Crestwood Midstream Partners (the Partnership) as of
December 31, 2021 and 2020, and the related consolidated statements of operations, partners’ capital and cash flows for each of
the three years in the period ended December 31, 2021, and the related notes and financial statement schedule listed in the Index
at Item 15(a) (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial
statements present fairly, in all material respects, the financial position of the Partnership at December 31, 2021 and 2020, and
the results of its operations and its cash flows for each of the three years in the period ended December 31, 2021, in conformity
with U.S. generally accepted accounting principles.
Basis for Opinion
These financial statements are the responsibility of the Partnership’s management. Our responsibility is to express an opinion
on the Partnership’s financial statements based on our audits. We are a public accounting firm registered with the Public
Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the
Partnership in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and
Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the
audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to
error or fraud. The Partnership is not required to have, nor were we engaged to perform, an audit of its internal control over
financial reporting. As part of our audits we are required to obtain an understanding of internal control over financial reporting
but not for the purpose of expressing an opinion on the effectiveness of the Partnership's internal control over financial
reporting. Accordingly, we express no such opinion.
Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due
to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis,
evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting
principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial
statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that
was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that
are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The
communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken
as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit
matters or on the accounts or disclosures to which it relates.
Description of the Matter As described in Note 2 to the consolidated financial statements, the Partnership recognizes
Revenue recognition – Measuring variable consideration
revenues for services and products under revenue contracts as obligations to perform services or
deliver/sell products under the contracts are satisfied. For a significant customer contract within
the Partnership’s Gathering and Processing North operating segment, consideration to be received
under the contact is estimated over the life of the contract and the contract’s transaction price is
allocated to each performance obligation in the contract and recognized as revenue when, or as,
the performance obligation is satisfied.
83
Table of Contents
Auditing the Partnership’s measurement of variable consideration under this contract involved
especially challenging judgment because the calculation involves subjective management
assumptions about estimates of future revenues including forecasted production of its customer
over the life of the contract. For example, the estimates of future revenues reflect management's
assumptions about future economic conditions and expected volumes to be gathered and
processed, and changes in those assumptions can have a material effect on the amount of revenue
recognized
How We Addressed the
Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of
controls over the Partnership’s process to calculate the variable consideration, including the
underlying assumptions about estimates of expected volumes.
Our audit procedures included, among others, evaluating the significant assumptions and the
accuracy and completeness of the underlying data used in management’s calculation. This
included testing management’s forecasted volumes through comparison to the forecast production
of the customer, analyst forecasted commodity prices and historical data and the recalculation of
the transaction price based on the volumes and executed contract rates. In addition, we performed
sensitivity analyses to evaluate the changes in variable consideration that would result from
changes in the Partnership’s forecasted volumes included in the calculation of the transaction
price.
/s/ Ernst & Young LLP
We have served as the Partnership’s auditor since 2013.
Houston, Texas
February 25, 2022
84
Table of Contents
Assets
Current assets:
CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED BALANCE SHEETS
(in millions)
Cash
Accounts receivable, less allowance for doubtful accounts of $0.6 million and $0.9
million at December 31, 2021 and 2020
Inventory
Assets from price risk management activities
Prepaid expenses and other current assets
Total current assets
Property, plant and equipment
Less: accumulated depreciation
Property, plant and equipment, net
Intangible assets
Less: accumulated amortization
Intangible assets, net
Goodwill
Operating lease right-of-use assets, net
Investments in unconsolidated affiliates
Other non-current assets
Total assets
Liabilities and capital
Current liabilities:
Accounts payable
Accrued expenses and other liabilities
Liabilities from price risk management activities
Contingent consideration, current portion
Current portion of long-term debt
Total current liabilities
Long-term debt, less current portion
Contingent consideration
Other long-term liabilities
Deferred income taxes
Total liabilities
Commitments and contingencies (Note 10)
Interest of non-controlling partner in subsidiary
Partners’ capital
Total liabilities and capital
See accompanying notes.
85
December 31,
2021
2020
$
12.9 $
13.7
378.0
156.5
42.1
14.4
603.9
4,100.8
1,193.0
2,907.8
1,126.1
393.2
732.9
138.6
27.4
155.8
4.8
262.2
89.1
27.2
13.4
405.6
4,089.6
1,028.3
3,061.3
1,126.1
331.8
794.3
138.6
36.8
943.7
5.2
$
4,571.2 $
5,385.5
$
336.4 $
146.1
114.6
—
0.2
597.3
2,052.1
—
254.1
0.8
157.8
120.1
76.3
19.0
0.2
373.4
2,483.8
38.0
251.8
0.7
2,904.3
3,147.7
434.6
1,232.3
$
4,571.2 $
432.7
1,805.1
5,385.5
Table of Contents
CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF OPERATIONS
(in millions)
Revenues:
Product revenues
Product revenues - related party (Note 19)
Service revenues
Service revenues - related party (Note 19)
Total revenues
Costs of product/services sold (exclusive of items shown separately below):
Product costs
Product costs - related party (Note 19)
Service costs
Total costs of products/services sold
Operating expenses and other:
Operations and maintenance
General and administrative
Depreciation, amortization and accretion
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
Operating income
Earnings (loss) from unconsolidated affiliates, net
Interest and debt expense, net
Gain (loss) on modification/extinguishment of debt
Other income, net
Income (loss) before income taxes
(Provision) benefit for income taxes
Net income (loss)
Net income attributable to non-controlling partner
Year Ended December 31,
2021
2020
2019
$
4,145.4 $
1,793.0 $
2,752.4
25.8
396.4
1.4
27.3
433.5
0.5
2.9
426.6
—
4,569.0
2,254.3
3,181.9
3,688.8
136.8
18.3
3,843.9
1,558.8
2,469.7
21.0
20.7
45.4
29.8
1,600.5
2,544.9
121.0
90.2
258.4
39.4
—
—
509.0
216.1
(120.4)
(132.1)
(7.5)
—
(43.9)
(0.1)
(44.0)
41.1
131.8
86.7
251.5
26.0
80.3
—
576.3
77.5
32.5
138.8
98.2
209.9
6.2
—
(209.4)
243.7
393.3
32.8
(133.6)
(115.4)
0.1
—
(23.5)
0.1
(23.4)
40.8
—
0.2
310.9
(0.3)
310.6
34.8
275.8
Net income (loss) attributable to Crestwood Midstream Partners LP
$
(85.1) $
(64.2) $
See accompanying notes.
86
Table of Contents
CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF PARTNERS’ CAPITAL
(in millions)
Balance at December 31, 2018
Distributions to partners
Unit-based compensation charges
Taxes paid for unit-based compensation vesting
Non-controlling interest reclassification (Note 12)
Other
Net income
Balance at December 31, 2019
Distributions to partner
Unit-based compensation charges
Taxes paid for unit-based compensation vesting
Other
Net loss
Balance at December 31, 2020
Distributions to partner
Unit-based compensation charges
Taxes paid for unit-based compensation vesting
Other
Net loss
Partners
Non-controlling
Partners
Total Partners’
Capital
$
2,028.2 $
181.3 $
2,209.5
(235.8)
(6.6)
42.4
(11.0)
—
(0.3)
275.8
2,099.3
(242.6)
29.3
(15.6)
(1.1)
(64.2)
1,805.1
(509.7)
30.5
(8.4)
(0.1)
(85.1)
—
—
(178.8)
0.1
4.0
—
—
—
—
—
—
—
—
—
—
—
—
(242.4)
42.4
(11.0)
(178.8)
(0.2)
279.8
2,099.3
(242.6)
29.3
(15.6)
(1.1)
(64.2)
1,805.1
(509.7)
30.5
(8.4)
(0.1)
(85.1)
Balance at December 31, 2021
$
1,232.3 $
— $
1,232.3
See accompanying notes.
87
Table of Contents
CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in millions)
Operating activities
Net income (loss)
Adjustments to reconcile net income (loss) to net cash provided by operating activities:
Depreciation, amortization and accretion
Amortization of debt-related deferred costs
Unit-based compensation charges
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
(Gain) loss on modification/extinguishment of debt
(Earnings) loss from unconsolidated affiliates, net, adjusted for cash distributions
received
Deferred income taxes
Other
Changes in operating assets and liabilities:
Accounts receivable
Inventory
Prepaid expenses and other current assets
Accounts payable, accrued expenses and other liabilities
Reimbursements of property, plant and equipment
Change in price risk management activities, net
Net cash provided by operating activities
Investing activities
Acquisitions, net of cash acquired (Note 3)
Purchases of property, plant and equipment
Investments in unconsolidated affiliates
Capital distributions from unconsolidated affiliates
Net proceeds from sale of long-lived assets, including equity investments
Other
Net cash provided by (used in) investing activities
Year Ended December 31,
2021
2020
2019
$
(44.0) $
(23.4) $
310.6
258.4
251.5
209.9
6.7
34.9
39.4
—
—
7.5
138.0
—
0.3
(114.3)
(67.4)
(0.6)
147.8
4.3
23.4
434.4
6.5
30.7
26.0
80.3
—
(0.1)
6.5
—
(0.1)
(27.8)
(33.7)
(4.6)
(6.1)
15.7
86.5
407.9
6.2
47.0
6.2
—
(209.4)
—
6.9
0.2
—
41.6
10.9
0.1
(23.3)
24.8
(7.6)
424.1
—
(162.3)
(462.1)
(81.3)
(17.6)
652.0
17.7
—
570.8
(168.3)
(9.4)
39.4
27.3
—
(455.5)
(61.3)
35.5
0.8
(1.1)
(273.3)
(943.7)
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CRESTWOOD MIDSTREAM PARTNERS LP
CONSOLIDATED STATEMENTS OF CASH FLOWS (continued)
(in millions)
Financing activities
Proceeds from the issuance of long-term debt
Payments on long-term debt
Payments on finance leases
Payments for deferred financing costs
Net proceeds from issuance of non-controlling interest
Distributions to partner
Distributions to non-controlling partner
Taxes paid for unit-based compensation vesting
Net cash provided by (used in) financing activities
Net change in cash and restricted cash
Cash and restricted cash at beginning of period
Cash and restricted cash at end of period
Supplemental disclosure of cash flow information
Cash paid for interest
Cash paid for income taxes
Year Ended December 31,
2021
2020
2019
2,859.5
1,125.1
2,307.3
(3,287.5)
(975.8) (1,729.5)
(2.8)
(3.1)
(3.5)
(17.9)
1.0
(509.7)
(40.2)
(8.4)
—
2.8
(242.6)
(37.1)
(15.6)
(9.0)
235.0
(235.8)
(25.0)
(11.0)
(1,006.0)
(146.3)
528.5
(0.8)
(11.7)
13.7
25.4
$
12.9 $
13.7 $
8.9
16.5
25.4
$
$
125.9 $
129.8 $
123.7
0.5 $
0.5 $
0.6
Supplemental schedule of noncash investing activities
Net change to property, plant and equipment through accounts payable and accrued
expenses
$
(5.8) $
40.0 $
(27.7)
See accompanying notes.
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CRESTWOOD EQUITY PARTNERS LP
CRESTWOOD MIDSTREAM PARTNERS LP
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 – Organization and Description of Business
The accompanying notes to the consolidated financial statements apply to Crestwood Equity Partners LP (the Company,
Crestwood Equity or CEQP) and Crestwood Midstream Partners LP (Crestwood Midstream or CMLP) unless otherwise
indicated.
Organization
Crestwood Equity Partners LP. CEQP is a publicly-traded (NYSE: CEQP) Delaware limited partnership formed in March
2001. Crestwood Equity GP LLC (Crestwood Equity GP), our wholly-owned subsidiary, owns our non-economic general
partnership interest. Prior to the Crestwood Holdings Transactions described below, Crestwood Equity was indirectly owned by
Crestwood Holdings LLC (Crestwood Holdings), which was substantially owned and controlled by First Reserve Management,
L.P. (First Reserve).
Crestwood Midstream Partners LP. Crestwood Equity owns a 99.9% limited partnership interest in Crestwood Midstream and
Crestwood Gas Services GP LLC (CGS GP), a wholly-owned subsidiary of Crestwood Equity, owns a 0.1% limited partnership
interest in Crestwood Midstream. Crestwood Midstream GP LLC, a wholly-owned subsidiary of Crestwood Equity, owns the
non-economic general partnership interest of Crestwood Midstream.
Crestwood Holdings Transactions. In March 2021, CEQP paid Crestwood Holdings approximately $268 million to (i) acquire
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)
acquire 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, which owns CEQP’s non-economic general partner interest) in August
2021 (collectively, the Crestwood Holdings Transactions). The purchase price was funded through borrowings under the
Crestwood Midstream credit facility. CEQP retired the common and subordinated units acquired in the Crestwood Holdings
Transactions.
Unless otherwise indicated, references in this report to “we,” “us,” “our,” “ours,” “our company,” the “partnership,” the
“Company,” “Crestwood Equity,” “CEQP,” and similar terms refer to either Crestwood Equity Partners LP itself or Crestwood
Equity Partners LP and its consolidated subsidiaries, as the context requires. Unless otherwise indicated, references to
“Crestwood Midstream” and “CMLP” refer to Crestwood Midstream Partners LP and its consolidated subsidiaries.
Description of Business
Crestwood Equity develops, acquires, owns or controls, and operates primarily fee-based assets and operations within the
energy midstream sector. We provide broad-ranging infrastructure solutions across the value chain to service premier liquids-
rich natural gas and crude oil shale plays across the United States. We own and operate a diversified portfolio of NGL, crude
oil, natural gas and produced water gathering, processing, storage, disposal and transportation assets that connect fundamental
energy supply with energy demand across the United States. Crestwood Equity is a holding company and all of its consolidated
operating assets are owned by or through its wholly-owned subsidiary, Crestwood Midstream.
See Note 16 for information regarding our operating and reporting segments.
Note 2 – Basis of Presentation and Summary of Significant Accounting Policies
Basis of Presentation
Our consolidated financial statements are prepared in accordance with GAAP and include the accounts of all consolidated
subsidiaries after the elimination of all intercompany accounts and transactions. Certain amounts in prior periods have been
reclassified to conform to the current year presentation, none of which impacted our previously reported net income, earnings
per unit or partners’ capital. In management’s opinion, all necessary adjustments to fairly present our results of operations,
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financial position and cash flows for the periods presented have been made and all such adjustments are of a normal and
recurring nature.
Significant Accounting Policies
Principles of Consolidation
We consolidate entities when we have the ability to control or direct the operating and financial decisions of the entity or when
we have a significant interest in the entity that gives us the ability to direct the activities that are significant to that entity. The
determination to consolidate or apply the equity method of accounting to an entity can also require us to evaluate whether that
entity is considered a variable interest entity. This evaluation, along with the determination of our ability to control, direct or
exert significant influence over an entity involves the use of judgment. We apply the equity method of accounting where we can
exert significant influence over, but do not control or direct the policies, decisions or activities of an entity. We use the cost
method of accounting where we are unable to exert significant influence over the entity.
Use of Estimates
The preparation of our consolidated financial statements in conformity with GAAP requires the use of estimates and
assumptions that affect the amounts we report as assets, liabilities, revenues and expenses and our disclosures in these
consolidated financial statements. Actual results can differ from those estimates.
Cash
We consider all highly liquid investments with an original maturity of less than three months to be cash.
Accounts Receivable
On January 1, 2020, we adopted the provisions of ASU 2016-13, Financial Instruments - Credit Losses (Topic 326), which
provides revised guidance on evaluating accounts and notes receivable and other financial instruments for impairment. We
record accounts receivable when products or services are delivered and it is probable that payment will be received for those
products or services, and we do not record any interest or penalties on accounts receivable that are past due under the terms of
the related arrangement or invoice until those amounts are received. Topic 326 requires companies to evaluate their financial
instruments for impairment by recording an allowance for doubtful accounts and/or bad debt expense based on certain
categories of instruments rather than a specific identification approach. We adopted the provisions of this standard using a
method to estimate the allowance for doubtful accounts that considered both the aging of our accounts receivable and the
projected loss rate of our receivables. We write off accounts receivable, and the related allowance for doubtful accounts, when
it becomes remote that payment for products or services will be received. On January 1, 2020, we recorded a $0.7 million
increase to our allowance for doubtful accounts and a $0.7 million decrease to partners’ capital to reflect the cumulative effect
of adopting the new standard. In addition, on January 1, 2020, Crestwood Permian Basin Holdings LLC (Crestwood Permian),
our 50% equity investment, also adopted the provisions of Topic 326 and we recorded a decrease of approximately $0.2 million
to our equity investment and a corresponding decrease to our partners’ capital to reflect our proportionate share of the
cumulative effect of accounting change recorded by the equity investment related to the new standard. The adoption of this
standard was not material to our other equity investments.
Inventory
Our inventory, which is stated at the lower of cost or net realizable value and cost is computed predominantly using the average
cost method, consisted of the following (in millions):
NGLs, crude oil and natural gas
Spare parts
Total inventory
91
December 31,
2021
2020
$
$
155.6 $
0.9
156.5 $
88.0
1.1
89.1
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Property, Plant and Equipment
Property, plant and equipment is recorded at is original cost of construction or, upon acquisition, at the fair value of the assets
acquired. For assets we construct, we capitalize direct costs, such as labor and materials, and indirect costs, such as overhead
and interest. We capitalize major units of property replacements or improvement and expense minor items. Depreciation is
computed using the straight-line method over the estimated useful lives of the assets, as follows:
Gathering systems and pipelines
Facilities and equipment
Buildings, rights-of-way and easements
Office furniture and fixtures
Vehicles
Years
15 - 20
3 - 25
1 - 40
5- 10
5
We evaluate our long-lived assets for impairment whenever events or changes in circumstances indicate that the carrying
amount of an asset may not be recoverable. If such events or changes in circumstances are present, a loss is recognized if the
carrying value of the asset is in excess of the sum of the undiscounted cash flows expected to result from the use of the asset
and its eventual disposition. An impairment loss is measured as the amount by which the carrying amount of the asset exceeds
the fair value of the asset, which is typically based on discounted cash flow projections using assumptions as to revenues, costs
and discount rates typical of third party market participants, which is a Level 3 fair value measurement.
Projected cash flows of our property, plant and equipment are generally based on current and anticipated future market
conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition,
operating costs, constructions costs, legal and regulatory issues and other factors that may extend many years into the future and
are often outside of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often
do, differ from our estimates.
During 2021, we recorded $40.1 million of impairments of our property, plant and equipment to reflect our gathering and
processing south segment’s compressor stations in our western Marcellus operations at fair value based on the actual or
anticipated dismantlement and redeployment of those assets to other areas. At December 31, 2021, our estimates of fair value
considered a number of factors, including the potential value we would receive if we sold the asset and projected cash flows
discounted at a 12% discount rate, which are Level 3 fair value measurements. During 2020 and 2019, we recorded $3.1 million
and $4.3 million of impairments of our property, plant and equipment primarily related to the removal and retirement of certain
water gathering facilities in response to several produced water releases on our Arrow system over the past few years, which is
further discussed in Note 10. During 2020, we sold our Fayetteville assets and recorded a loss on long-lived assets of
approximately $19.9 million (see Note 3 for a further discussion of the assets sale).
Identifiable Intangible Assets
Our identifiable intangible assets consist of customer accounts, trademarks and certain revenue contracts. These intangible
assets have arisen primarily from acquisitions. We amortize certain of our revenue contracts based on the projected cash flows
associated with these contracts if the projected cash flows are readily determinable, otherwise we amortize our revenue
contracts on a straight-line basis. We recognize acquired intangible assets separately if the benefit of the intangible asset is
obtained through contractual or other legal rights, or if the intangible asset can be sold, transferred, licensed, rented or
exchanged, regardless of the acquirer’s intent to do so.
Projected cash flows of our intangible assets are generally based on current and anticipated future market conditions, which
require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs,
construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside
of our control. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our
estimates.
We did not record any impairments of our intangible assets during the years ended December 31, 2021, 2020 or 2019.
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Certain intangible assets are amortized on a straight-line basis over their estimated economic lives, as follows:
Customer accounts
Revenue contracts
Trademarks
Goodwill
Weighted-Average
Life
(years)
22
18
10
Our goodwill represents the excess of the amount we paid for a business over the fair value of the net identifiable assets
acquired. We evaluate goodwill for impairment annually on December 31, and whenever events indicate that it is more likely
than not that the fair value of a reporting unit could be less than its carrying amount. This evaluation requires us to compare the
fair value of each of our reporting units to its carrying value (including goodwill). If the fair value exceeds the carrying amount,
goodwill of the reporting unit is not considered impaired.
We estimate the fair value of our reporting units based on a number of factors, including discount rates, projected cash flows
and the potential value we would receive if we sold the reporting unit. Estimating projected cash flows requires us to make
certain assumptions as it relates to the future operating performance of each of our reporting units (which includes assumptions,
among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the
cost and timing of facility expansions) and assumptions related to our customers, such as their future capital and operating plans
and their financial condition. When considering operating performance, various factors are considered such as current and
changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these
projections and assumptions, actual results can and often do, differ from our estimates. If the assumptions embodied in the
projections prove inaccurate, we could incur a future impairment charge. In addition, the use of the income approach to
determine the fair value of our reporting units (see further discussion of the use of the income approach below) could result in a
different fair value if we had utilized a market approach, or a combination thereof.
Upon acquisition, we are required to record the assets, liabilities and goodwill of a reporting unit at its fair value on the date of
acquisition. As a result, any level of decrease in the forecasted cash flows of these businesses or increases in the discount rates
utilized to value those businesses from their respective acquisition dates would likely result in the fair value of the reporting
unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s
goodwill is impaired.
We acquired our Powder River Basin reporting unit in 2019 and recorded it at fair value at that time. During 2020, current and
forward commodity prices significantly declined from their levels at December 31, 2019 due primarily to the decreases in
energy demand as a result of the outbreak of the COVID-19 pandemic and actions taken by the Organization of the Petroleum
Exporting Countries, Russia, the United States and other oil-producing countries relating to the oversupply of oil. Based on
these events, we determined that the forecasted cash flows, and therefore the fair value, of our Powder River Basin reporting
unit significantly decreased during 2020, and accordingly performed a quantitative impairment assessment of the goodwill
related to that reporting unit during that period. Based on our quantitative assessment, which utilized the income approach, we
determined that the goodwill associated with the Powder River Basin reporting unit should be fully impaired, and accordingly
we recorded an $80.3 million impairment of the goodwill attributed to that reporting unit during the year ended December 31,
2020.
The following table summarizes the goodwill of our reporting units (in millions). We did not record any impairments of the
goodwill associated with our Arrow or NGL Marketing and Logistics reporting units during the years ended December 31,
2021, 2020 and 2019. At December 31, 2021, our accumulated goodwill impairments at CEQP and CMLP were approximately
$1,736.8 million and $1,479.6 million, respectively.
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Gathering and Processing North
Arrow
Powder River Basin
Storage and Logistics
NGL Marketing and Logistics
Total
Leases
Goodwill at
January 1, 2020
Impairment during
the Year Ended
December 31, 2020
Goodwill at
December 31, 2020
Goodwill at
December 31, 2021
$
$
45.9 $
80.3
92.7
218.9 $
— $
(80.3)
—
(80.3) $
45.9 $
—
92.7
138.6 $
45.9
—
92.7
138.6
We enter into leases with third parties for the right to utilize certain office buildings, crude oil railroad cars, vehicles and other
operating facilities and equipment. For contracts that extend for a period greater than 12 months, we recognize a right-of-use
asset and a corresponding lease liability on our consolidated balance sheet based on the present value of each lease, which is
based on the future minimum lease payments and is determined by discounting these payments using our incremental
borrowing rate. We recognize operating lease expense on our consolidated statements of operations as either costs of product/
services sold, operations and maintenance expenses or general and administrative expenses on a straight-line basis over the
lease term. We do not have any material leases where we are considered to be the lessor. Our lease agreements do not contain
any material residual value guarantees or material restrictive covenants. We do not have any material revenue contracts that are
considered leases.
Investments in Unconsolidated Affiliates
Equity method investments in which we exercise significant influence, but do not control and are not the primary beneficiary,
are accounted for using the equity method of accounting. Differences in the basis of investments and the separate net asset
values of the investees, if any, are amortized into net income or loss over the remaining useful lives of the underlying assets and
liabilities, except for the excess related to goodwill. We evaluate our equity method investments for impairment when events or
circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other
than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the
investment. If an impairment is indicated, or if we decide to sell an investment in an unconsolidated affiliate, we adjust the
carrying values of the asset downward, if necessary, to their estimated fair values. We did not record impairments of our equity
method investments during the years ended December 31, 2021, 2020 and 2019. See Note 6 for a discussion of the impairments
recorded by our Stagecoach Gas equity method investment related to the sale of its assets, including our proportionate share of
the losses which we recorded as a reduction to our earnings from unconsolidated affiliates during the year ended December 31,
2021.
Asset Retirement Obligations
An asset retirement obligation (ARO) is an estimated liability for the cost to retire a tangible asset. We record a liability for
legal or contractual obligations to retire our long-lived assets associated with our facilities and right-of-way contracts we hold.
We record a liability in the period the obligation is incurred and estimable. An ARO is initially recorded at its estimated fair
value with a corresponding increase to property, plant and equipment. This increase in property, plant and equipment is then
depreciated over the useful life of the asset to which that liability relates. An ongoing expense is recognized for changes in the
fair value of the liability as a result of the passage of time, which we record as depreciation, amortization and accretion expense
on our consolidated statements of operations.
We have various obligations to remove property, plant and equipment on rights-of-way and leases for which we cannot
currently estimate the fair value of those obligations because the associated assets have indeterminate lives. An asset retirement
obligation liability (and related assets), if any, will be recorded for these obligations once sufficient information is available to
reasonably estimate the fair value of the obligations. Our current AROs are reflected in accrued expenses and other liabilities
and our long-term AROs are reflected in other long-term liabilities on our consolidated balance sheets.
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Deferred Financing Costs
Deferred financing costs represent costs associated with obtaining long-term financing and are amortized over the term of the
related debt using a method which approximates the effective interest method and has a weighted average remaining life of six
years. Our net deferred financing costs are reflected as a reduction of long-term debt on our consolidated balance sheets.
Environmental Costs and Other Contingencies
We recognize liabilities for environmental and other contingencies when there is an exposure that indicates it is both probable
that a liability has been incurred and the amount of loss can be reasonably estimated. Where the most likely outcome of a
contingency can be reasonably estimated, we accrue a liability for that amount. Where the most likely outcome cannot be
estimated, a range of potential losses is established and if no one amount in that range is more likely than any other, the low end
of the range is accrued.
We record liabilities for environmental contingencies at their undiscounted amounts on our consolidated balance sheets as
accrued expenses and other liabilities when environmental assessments indicate that remediation efforts are probable and costs
can be reasonably estimated. Estimates of our liabilities are based on currently available facts and presently enacted laws and
regulations, taking into consideration the likely effects of other societal and economic factors. These estimates are subject to
revision in future periods based on actual costs or new circumstances. We capitalize costs that benefit future periods and
recognize a current period charge in operations and maintenance expenses when clean-up efforts do not benefit future periods.
We evaluate potential recoveries of amounts from third parties, including insurance coverage, separately from our liability.
Recovery is evaluated based on the solvency of the third party, among other factors. When recovery is assured, we record and
report an asset separately from the associated liability on our consolidated balance sheet.
Revenue Recognition
We provide gathering, processing, compression, storage, fractionation, and transportation (consisting of pipelines, truck and rail
terminals, truck/trailer units and rail cars) services and we sell commodities (including crude oil, natural gas and NGLs) under
various contracts, which are described below.
•
•
•
•
Fixed-fee contracts. Under these contracts, we do not take title to the underlying crude oil, natural gas, NGLs and
water but charge our customers a fixed-fee for the services we provide, which can be a firm reservation charge and/or a
charge per volume gathered, processed, compressed, stored, loaded and/or transported (which, in certain contracts, can
be subject to a minimum level of volumes).
Percentage-of-proceeds service contracts. Under these contracts, we take title to crude oil, natural gas or NGLs after
the commodity leaves our gathering and processing facilities. We often market and sell those commodities to third
parties after they leave our facilities and we will remit a portion of the sales proceeds to our producers.
Percentage-of-proceeds product contracts. Under these contracts, we take title to crude oil, natural gas or NGLs
before the commodity enters our facilities. We market and sell those commodities to third parties and we will remit a
portion of the sales proceeds to our producers.
Purchase and sale contracts. Under these contracts, we purchase crude oil, natural gas or NGLs before the commodity
enters our facilities, and we market and sell those commodities to third parties.
We recognize revenues for services and products under revenue contracts as our obligations to perform services or deliver/sell
products under the contracts are satisfied. A contract’s transaction price is allocated to each performance obligation in the
contract and recognized as revenue when, or as, the performance obligation is satisfied. Our fixed-fee contracts and our
percentage-of-proceeds service contracts primarily have a single performance obligation to deliver a series of distinct goods or
services that are substantially the same and have the same pattern of transfer to our customers. For performance obligations
associated with these contracts, we recognize revenues over time utilizing the output method based on the actual volumes of
products delivered/sold or services performed, because the single performance obligation is satisfied over time using the same
performance measure of progress toward satisfaction of the performance obligation. The transaction price under certain of our
fixed-fee contracts and percentage-of-proceeds service contracts includes variable consideration that varies primarily based on
actual volumes that are delivered under the contracts. Because the variable consideration specifically relates to our efforts to
transfer the services and/or products under the contracts, we allocate the variable consideration entirely to the distinct service,
and accordingly recognize the variable consideration as revenues at the time the good or service is transferred to the customer.
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Certain of our fixed-fee contracts contain minimum volume features under which the customers must utilize our services to
gather, compress or load a specified quantity of crude oil or natural gas or pay a deficiency fee based on the difference between
actual volumes and the contractual minimum volume. We recognize revenues from these contracts when actual volumes are
gathered, compressed or loaded and the likelihood of a customer exercising its remaining rights to make up the deficient
volumes under minimum volume commitments becomes remote.
We recognize revenues at a point in time for performance obligations associated with our percentage-of proceeds product
contracts and purchase and sale contracts, and these revenues are recognized because control of the underlying product is
transferred to the customer when the distinct good is provided to the customer.
The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our
performance obligations requires significant judgments and assumptions, including our evaluation of the timing of when control
of the underlying good or service has transferred to our customers and the relative standalone selling price of goods and
services provided to customers under contracts with multiple performance obligations. Actual results can significantly vary
from those judgments and assumptions. We did not have any material contracts with multiple performance obligations or under
which we receive material amounts of non-cash consideration during the year ended December 31, 2021.
Amounts due from our customers under our revenue contracts are typically billed as the service is being provided or on a
weekly, bi-weekly or monthly basis and are due within 30 days of billing. Under certain of our contracts, we recognize
revenues in excess of billings which we present as contract assets on our consolidated balance sheets.
Under certain contracts, we are entitled to receive payments in advance of satisfying our performance obligations under the
contracts. We recognize a liability for these payments in excess of revenue recognized and present it as deferred revenue or
contract liabilities on our consolidated balance sheets. Our deferred revenue primarily relates to:
•
•
Capital Reimbursements. Certain of our contracts require that our customers reimburse us for capital expenditures
related to the construction of long-lived assets utilized to provide services to them under the respective revenue
contracts. Because we consider these amounts as consideration from customers associated with ongoing services to be
provided to customers, we defer these upfront payments in deferred revenue and recognize the amounts in revenue
over the life of the associated revenue contract as the performance obligations are satisfied under the contract.
Contracts with Increasing (Decreasing) Rates per Unit. Certain of our contracts have fixed rates per volume that
increase and/or decrease over the life of the contract once certain time periods or thresholds are met. We record
revenues on these contracts ratably per unit over the life of the contract based on the remaining performance
obligations to be performed, which can result in the deferral of revenue for the difference between the consideration
received and the ratable revenue recognized.
Credit Risk and Concentrations
Inherent in our contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers,
customers or financial counterparties to a contract. We take an active role in managing credit risk and have established control
procedures, which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure through credit policies and
periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that
allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate.
Income Taxes
Crestwood Equity is a master limited partnership and Crestwood Midstream is a limited partnership. Partnerships are generally
not subject to federal income tax, although publicly-traded partnerships are treated as corporations for federal income tax
purposes and therefore are subject to federal income tax, unless the partnership generates at least 90% of its gross income from
qualifying sources. If the qualifying income requirement is satisfied, the publicly-traded partnership will be treated as a
partnership for federal income tax purposes. We satisfy the qualifying income requirement and are treated as a partnership for
federal and state income tax purposes. Our consolidated earnings are included in the federal and state income tax returns of our
partners. However, legislation in certain states allows for taxation of partnerships, and as such, certain state taxes have been
included in our accompanying financial statements as income taxes due to the nature of the tax in those particular states as
discussed below. In addition, federal and state income taxes are provided on the earnings of the subsidiaries incorporated as
taxable entities. We are required to recognize deferred tax assets and liabilities for the expected future tax consequences of
events that have been included in the financial statements or tax returns. Under this method, deferred tax assets and liabilities
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are determined based on the differences between the financial reporting and tax basis of assets and liabilities using expected
rates in effect for the year in which the differences are expected to reverse.
We are responsible for the Texas Margin tax included in our Texas franchise tax returns. The margin tax qualifies as an income
tax under GAAP, which requires us to recognize the impact of this tax on the temporary differences between the financial
statement assets and liabilities and their tax basis attributable to such tax.
Net earnings for financial statement purposes may differ significantly from taxable income reportable to unitholders as a result
of differences between the tax basis and the financial reporting basis of assets and liabilities and the taxable income allocation
requirements under the partnership agreement.
Price Risk Management Activities
We utilize certain derivative financial instruments to (i) manage our exposure to commodity price risk, specifically, the related
change in the fair value of inventory, as well as the variability of cash flows related to forecasted transactions; and (ii) ensure
the availability of adequate physical supply of commodity. We record all derivative instruments as either assets or liabilities on
our consolidated balance sheets at their fair values. Changes in the fair value of these derivative financial instruments are
recorded through current earnings. We do not have any derivatives designated as fair value hedges or cash flow hedges for
accounting purposes.
Unit-Based Compensation
Long-term incentive awards are granted under the Crestwood Equity Partners LP Long Term Incentive Plan (Crestwood LTIP).
Unit-based compensation awards consist of restricted units and performance units that are recognized in our consolidated
statements of operations based on their grant date at fair value. For restricted units, we generally recognize the expense over the
vesting period on a straight line basis. For performance units, we remeasure compensation expense at each balance sheet date
because the vesting is subject to the attainment of certain performance and market goals over a three-year period. For those
awards that are settled in cash, the associated liability is remeasured at every balance sheet date through settlement, such that
the vested portion of the liability is adjusted to reflect its revised fair value through compensation expense.
Note 3 – Acquisitions and Divestiture
Acquisitions
NGL Asset Acquisition
In April 2020, we acquired several NGL storage and rail-to-truck terminals from Plains All American Pipeline, L.P. for
approximately $162 million (NGL Asset Acquisition). The acquired assets include 7 MMBbls of NGL storage and seven
terminals, and resulted in an increase of approximately $110 million to our property, plant and equipment, $50 million to our
intangible assets and $2 million to our other assets and liabilities, net. The identifiable intangible assets primarily consist of
customer accounts with a weighted-average remaining life of 20 years on the date of acquisition. We allocated the purchase
price to these assets and liabilities based on their fair values, which are Level 3 fair value measurements and were developed by
management with the assistance of a third-party valuation firm utilizing market-related information about the property, plant
and equipment and customer relationships acquired. These assets are included in our storage and logistics segment. The
transaction costs related to this acquisition were not material during the year ended December 31, 2020.
Jackalope Acquisition
On April 9, 2019, Crestwood Niobrara LLC (Crestwood Niobrara), our consolidated subsidiary, acquired Williams Partners
LP’s (Williams) 50% equity interest in Jackalope Gas Gathering Services, L.L.C. (Jackalope) for approximately $484.6 million
(Jackalope Acquisition). The acquisition was funded through a combination of borrowings under the CMLP credit facility and
the issuance of $235 million of new preferred units to CN Jackalope Holdings LLC (Jackalope Holdings) (see Note 12 for a
further discussion of the issuance of the new preferred units). Prior to the Jackalope Acquisition, Crestwood Niobrara owned a
50% equity interest in Jackalope, which we accounted for under the equity method of accounting. As a result of this transaction,
Crestwood Niobrara controls and owns 100% of the equity interests in Jackalope. The financial results of Jackalope are
included in our gathering and processing north segment. Transaction costs related to the Jackalope Acquisition were
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approximately $2.8 million during the year ended December 31, 2019. These costs are included in operations and maintenance
expenses in our consolidated statements of operations.
The fair values of the assets acquired and liabilities assumed were determined primarily utilizing market-related information
and other projections on the anticipated performance of the assets acquired, including an analysis of the future discounted cash
flows to be generated by the acquired assets at a discount rate of approximately 12%. Those fair values are Level 3 fair value
measurements and were developed by management with the assistance of a third-party valuation firm.
The following table summarizes the final valuation of the assets acquired and liabilities assumed at the acquisition date (in
millions):
Cash
Other current assets
Property, plant and equipment
Intangible assets
Goodwill
Current liabilities
Other long-term liabilities
Estimated fair value of 100% interest in Jackalope
Less:
Elimination of equity investment in Jackalope
Gain on acquisition of Jackalope
Total purchase price
$
$
22.5
30.9
532.9
306.0
80.3
(30.4)
(21.5)
920.7
226.7
209.4
484.6
The identifiable intangible assets primarily consists of a customer contract with a weighted-average remaining life of 17 years
on the date of acquisition. The goodwill recognized related primarily to anticipated operating synergies between the assets
acquired and our existing operations. The fair value of the assets acquired and liabilities assumed in the Jackalope Acquisition
exceeded the sum of the cash consideration paid and the historical book value of our 50% equity interest in Jackalope (which
was remeasured at fair value and derecognized) and, as a result, we recognized a gain of approximately $209.4 million during
the year ended December 31, 2019. This gain is included in gain on acquisition in our consolidated statements of operations.
Our consolidated statements of operations include the results of Jackalope in our gathering and processing north segment since
April 9, 2019, the closing date of the acquisition. During the year ended December 31, 2019, we recognized approximately
$70.1 million of revenues and $20.9 million of net income related to Jackalope’s operations.
The tables below present selected unaudited pro forma information as if the Jackalope Acquisition had occurred on January 1,
2019 (in millions). The pro forma information is not necessarily indicative of the financial results that would have occurred if
the transaction had been completed as of the date indicated. The amounts were calculated after applying our accounting policies
and adjusting the results to reflect the depreciation, amortization and accretion expense that would have been charged assuming
the fair value adjustments to property, plant and equipment and intangible assets had been made at the beginning of the
reporting period. The pro forma net income also includes the effects of interest expense on incremental borrowings and
recognition of deferred revenue.
Crestwood Equity
Revenues
Net income
Crestwood Midstream
Revenues
Net income
Year Ended December 31, 2019
$
$
3,202.6
313.5
Year Ended December 31, 2019
$
$
3,202.6
304.2
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Divestiture
On October 1, 2020, we sold our gathering systems in the Fayetteville Shale to a third party for approximately $23 million, and
during the year ended December 31, 2020, we recognized a loss on the sale of approximately $19.9 million, which is included
in loss on long-lived assets, net on our consolidated statement of operations. The sale of our Fayetteville assets resulted in a
decrease of approximately $44.4 million of property, plant and equipment, net and a decrease of approximately $1.4 million in
our asset retirement obligation liabilities. Our Fayetteville assets were previously included in our gathering and processing
south segment and consisted of five natural gas gathering systems and related compression, dehydration and treating facilities
located in Arkansas.
Note 4 – Certain Balance Sheet Information
Property, Plant and Equipment
Property, plant and equipment consisted of the following (in millions):
CEQP
December 31,
CMLP
December 31,
2021
2020
2021
2020
Gathering systems and pipelines and related assets
$
1,052.5 $
1,035.2 $
1,195.2 $
1,178.0
Facilities and equipment
Buildings, land, rights-of-way, storage rights and easements
Vehicles
Construction in process
Finance leases
Office furniture and fixtures
Less: accumulated depreciation
2,200.6
391.8
2,193.5
389.0
2,385.8
395.5
2,378.6
392.7
17.0
64.7
12.3
32.6
13.9
83.6
13.3
31.1
14.5
64.7
12.3
32.8
12.1
83.6
13.3
31.3
3,771.5
992.1
3,759.6
842.5
4,100.8
1,193.0
4,089.6
1,028.3
Total property, plant and equipment, net
$
2,779.4 $
2,917.1 $
2,907.8 $
3,061.3
Depreciation. CEQP’s depreciation expense totaled $180.9 million, $174.8 million and $139.5 million for the years ended
December 31, 2021, 2020 and 2019. CMLP’s depreciation expense totaled $195.1 million, $188.9 million and $153.5 million
for the years ended December 31, 2021, 2020 and 2019.
Capitalized Interest. During the years ended December 31, 2021, 2020 and 2019, we capitalized interest of $0.4 million, $2.7
million and $14.4 million related to certain expansion projects.
Intangible Assets
Our intangible assets consisted of the following (in millions):
Customer accounts(1)
Revenue contracts
Trademarks
Less: accumulated amortization
Total intangible assets, net
December 31,
2021
2020
$
488.7 $
631.2
6.2
1,126.1
393.2
$
732.9 $
488.7
631.2
6.2
1,126.1
331.8
794.3
(1) This amount includes $49.8 million related to customer accounts acquired in conjunction with the NGL Asset Acquisition which is further discussed in
Note 3.
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The following table summarizes total accumulated amortization of our intangible assets (in millions):
Customer accounts
Revenue contracts
Trademarks
Total accumulated amortization
December 31,
2021
2020
$
183.2 $
204.6
5.4
$
393.2 $
158.5
168.6
4.7
331.8
Amortization expense related to our intangible assets for the years ended December 31, 2021, 2020 and 2019, was
approximately $61.4 million, $60.7 million and $54.6 million.
Estimated amortization of our intangible assets for the next five years is as follows (in millions):
Year Ending December 31,
2022
2023
2024
2025
2026
Accrued Expenses and Other Liabilities
Accrued expenses and other liabilities consisted of the following (in millions):
CMLP
Accrued expenses
Accrued property taxes
Income tax payable
Interest payable
Accrued additions to property, plant and equipment
Operating leases
Finance leases
Contract liabilities
Asset retirement obligations
Total CMLP accrued expenses and other liabilities
CEQP
Accrued expenses
Income tax payable
Total CEQP accrued expenses and other liabilities
$
$
$
$
$
61.4
57.6
54.2
51.5
51.3
December 31,
2021
2020
$
66.3 $
4.4
0.4
30.6
17.4
13.2
1.7
10.7
1.4
45.4
8.4
0.2
24.9
12.3
14.7
2.9
10.3
1.0
$
$
146.1 $
120.1
0.9
0.1
147.1 $
1.9
—
122.0
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Other Long-Term Liabilities
Other long-term liabilities consisted of the following (in millions):
CMLP
Contract liabilities
Operating leases
Asset retirement obligations
Other
Total CMLP other long-term liabilities
CEQP
Other
Total CEQP other long-term liabilities
Note 5 - Asset Retirement Obligations
December 31,
2021
2020
$
$
$
187.1 $
19.4
34.8
12.8
254.1 $
4.6
258.7 $
172.2
28.5
34.1
17.0
251.8
1.5
253.3
We have legal obligations associated with our facilities and right-of-way contracts we hold. Where we can reasonably estimate
the ARO, we accrue a liability based on an estimate of the timing and amount of settlement. We record changes in these
estimates based on changes in the expected amount and timing of payments to settle our obligations. We did not have any
material assets that were legally restricted for use in settling asset retirement obligations as of December 31, 2021 and 2020.
The following table presents the changes in our net asset retirement obligations (in millions):
Net asset retirement obligations at January 1
Liabilities acquired(1)
Liabilities incurred
Liabilities settled
Accretion expense
Other(2)
Net asset retirement obligations at December 31(3)
December 31,
2021
2020
35.1 $
—
—
(0.4)
1.9
(0.4)
36.2 $
34.8
0.3
0.3
(0.8)
1.9
(1.4)
35.1
$
$
(1) Primarily relates to the NGL Asset Acquisition in 2020. See Note 3 for a further discussion of these acquisitions.
(2) Relates to obligations associated with the abandonment and dismantlement of our Marcellus West Union compressor assets in 2021 as further discussed in
Note 2 and the obligations included in the sale of our Fayetteville assets in 2020 as further discussed in Note 3.
(3)
Includes $1.4 million and $1.0 million of current ARO liabilities at December 31, 2021 and 2020.
Note 6 - Investments in Unconsolidated Affiliates
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. We received cash proceeds of approximately
$15.4 million related to the Second Closing.
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In conjunction with the Initial Closing and Second Closing, we recorded a $155.6 million reduction in our equity earnings from
unconsolidated affiliates during the year ended December 31, 2021 related to losses recorded by us and our Stagecoach equity
investment associated with the sale, which also eliminated our $51.3 million historical basis difference between our investment
balance and the equity in the underlying net assets of Stagecoach Gas. In addition, our earnings from unconsolidated affiliates
during the year ended December 31, 2021 were also reduced by our proportionate share of transaction costs of approximately
$3.1 million related to the Initial Closing and Second Closing, which were paid by us during 2021 on behalf of Stagecoach Gas.
Net Investments and Earnings (Loss)
We account for each of our investments in unconsolidated affiliates under the equity method of accounting. Our Tres Palacios
Holdings LLC (Tres Holdings), Powder River Basin Industrial Complex, LLC (PRBIC) and Stagecoach Gas (prior to its
divestiture) equity investments are included in our storage and logistics segment. Our Crestwood Permian equity investment is
included in our gathering and processing south segment.
Our net investments in and earnings (loss) from our unconsolidated affiliates are as follows (in millions, unless otherwise
stated):
Stagecoach Gas Services LLC
Tres Palacios Holdings LLC
Powder River Basin Industrial Complex, LLC
Crestwood Permian Basin Holdings LLC
Jackalope Gas Gathering Services, L.L.C.(1)
Total
Ownership
Percentage
Investment
Earnings (Loss) from Unconsolidated
Affiliates
December 31,
December 31,
Year Ended December 31,
2021
2021
2020
2021
2020
2019
— % $ —
$ 792.5
$ (139.2) $
37.8
$
34.2
50.01 %
50.01 %
36.2
3.5
35.5
3.6
50.00 %
116.1
112.1
— %
—
—
9.3
(0.1)
9.6
—
—
(4.3)
(1.0)
—
0.9
(0.2)
(5.8)
3.7
$ 155.8
$ 943.7
$ (120.4) $
32.5
$
32.8
(1) On April 9, 2019, Crestwood Niobrara acquired Williams’s 50% equity interest in Jackalope and, as a result, Crestwood Niobrara controls and owns
100% of the equity interests in Jackalope. Our Jackalope equity investment was previously included in our gathering and processing north segment. See
Note 3 for a further discussion of this acquisition.
Summarized Financial Information of Unconsolidated Affiliates
Below is summarized financial information for our significant unconsolidated affiliates (in millions; amounts represent 100%
of unconsolidated affiliate information):
Financial Position Data
2021
2020
December 31,
Current
Assets
Non-
Current
Assets
Current
Liabilities
Non-
Current
Liabilities
Members’
Equity
Current
Assets
Non-
Current
Assets
Current
Liabilities
Non-
Current
Liabilities
Members’
Equity
Stagecoach Gas(1)
Other(2)
$ — $ — $ — $ — $ — $ 47.4 $ 1,645.5 $
3.9 $
1.4 $ 1,687.6
46.5
679.2
58.6
236.5
430.6
23.5
661.9
33.6
233.7
418.1
Total
$ 46.5 $ 679.2 $ 58.6 $ 236.5 $ 430.6 $ 70.9 $ 2,307.4 $ 37.5 $ 235.1 $ 2,105.7
(1) As discussed above, in November 2021, we sold our equity interest in our Stagecoach Gas equity investment.
(2)
Includes our Tres Holdings, PRBIC and Crestwood Permian equity investments. As of December 31, 2021, our equity in the underlying net assets of Tres
Holdings exceeded our investment balance by approximately $21.4 million. As of December 31, 2021, our equity in the underlying net assets of PRBIC
approximates our investment balance. During the year ended December 31, 2020, we recorded our share of a long-lived asset impairment recorded by our
PRBIC equity investment, which eliminated our $5.5 million historical basis difference between our investment and the equity in the underlying net assets
of PRBIC. As of December 31, 2021, our equity in the underlying net assets of Crestwood Permian exceeded our investment balance by approximately
$8.2 million, and this excess amount is not subject to amortization.
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Operating Results Data
2021
Operating
Revenues
Operating
Expenses
Net
Income
(Loss)
Year Ended December 31,
2020
2019
Operating
Revenues
Operating
Expenses
Net
Income
Operating
Revenues
Operating
Expenses
Net
Income
Stagecoach Gas(1)
Other(2)
Total
$
81.9 $ 456.7 $ (374.6) $ 154.3 $
78.8 $
75.5 $ 163.8 $
83.6 $
80.6
335.6
300.8
35.0
121.3
146.1
(24.6)
119.9
125.9
(6.0)
$ 417.5 $ 757.5 $ (339.6) $ 275.6 $ 224.9 $
50.9 $ 283.7 $ 209.5 $
74.6
(1) As discussed above, in November 2021, we sold our equity interest in our Stagecoach Gas equity investment and, as a result, the information for the
period ended 2021 is presented through November 24, 2021, the date of the Stagecoach Gas divestiture.
(2)
Includes our Tres Holdings, PRBIC, Crestwood Permian and Jackalope (prior to the acquisition of the remaining 50% interest from Williams in April
2019) equity investments. We amortize the excess basis in certain of our equity investments as an increase in our earnings from unconsolidated affiliates.
We recorded amortization of the excess basis in our Tres Holdings equity investment of approximately $1.3 million for each of the years ended
December 31, 2021, 2020 and 2019, which we amortize over the life of Tres Palacios’s sublease agreement. We recorded amortization of the excess basis
in our PRBIC equity investment of approximately $0.4 million for the year ended December 31, 2019, which we amortized over the life of PRBIC’s
property, plant and equipment. We recorded amortization of the excess basis in our Jackalope equity investment of less than $0.1 million for the year
ended December 31, 2019, which we amortized over the life of Jackalope’s gathering and processing agreement with Chesapeake Energy Corporation.
Distributions and Contributions
Stagecoach Gas
Tres Holdings
PRBIC
Crestwood Permian
Jackalope
Total
Distributions(1)
Contributions(2)
Year Ended December 31,
2020
2019
2021
Year Ended December 31,
2020
2019
2021
$
640.9 $
59.7 $
52.3 $
— $
— $
15.5
—
16.3
—
6.4
0.4
11.9
—
6.3
—
5.0
11.6
6.9
—
10.7
—
6.0
—
3.4
—
$
672.7 $
78.4 $
75.2 $
17.6 $
9.4 $
2.1
6.3
0.2
28.3
24.4
61.3
(1)
In July 2021, Stagecoach Gas closed on the sale of certain of its wholly-owned subsidiaries to a subsidiary of Kinder Morgan and distributed to us
approximately $613.9 million as our proportionate share of the gross proceeds received from the sale. We utilized approximately $3 million of these
proceeds to pay transaction costs related to the sale described above, $40 million of these proceeds to pay our remaining contingent consideration
obligation and related accrued interest described below, and the remaining proceeds to repay a portion of the amounts outstanding under the Crestwood
Midstream credit facility. In January 2022, we received cash distributions from Crestwood Permian of approximately $8.5 million.
(2)
In January 2022, we made cash contributions of approximately $6.0 million and $8.5 million to our Tres Holdings and Crestwood Permian equity
investments, respectively.
Other
Contingent Consideration. Pursuant to the Stagecoach Gas limited liability company agreement, we were required to make
payments to CEGP because certain performance targets on growth capital projects were not achieved by December 31, 2020.
During the year ended December 31, 2021, we fully satisfied this obligation by paying $57 million plus accrued interest of
$2.1 million to CEGP.
Note 7 – Risk Management
We are exposed to certain market risks related to our ongoing business operations. These risks include exposure to changing
commodity prices. We utilize derivative instruments to manage our exposure to fluctuations in commodity prices, which is
discussed below. Additional information related to our derivatives is discussed in Note 2 and Note 8.
Risk Management Activities
We sell NGLs (such as propane, ethane, butane and heating oil), crude oil and natural gas to energy-related businesses and may
use a variety of financial and other instruments including forward contracts involving physical delivery of NGLs, crude oil and
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natural gas. We periodically enter into offsetting positions to economically hedge against the exposure our customer contracts
create. Certain of these contracts and positions are derivative instruments. We do not designate any of our commodity-based
derivatives as hedging instruments for accounting purposes. Our commodity-based derivatives are reflected at fair value in our
consolidated balance sheets, and changes in the fair value of these derivatives that impact our consolidated statements of
operations are reflected in costs of product/services sold. Our commodity-based derivatives that are settled with physical
commodities are reflected as an increase to product revenues, and the commodity inventory that is utilized to satisfy those
physical obligations is reflected as an increase to product costs in our consolidated statements of operations. The following table
summarizes the impact to our consolidated statements of operations related to our commodity-based derivatives during the
years ended December 31, 2021, 2020 and 2019 (in millions):
Product revenues
Gain (loss) reflected in product costs
December 31,
2021
2020
2019
$
$
486.7 $
(44.5) $
214.3 $
(20.7) $
252.3
19.5
We attempt to balance our contractual portfolio in terms of notional amounts and timing of performance and delivery
obligations. This balance in the contractual portfolio significantly reduces the volatility in product costs related to these
instruments.
Notional Amounts and Terms
The notional amounts of our derivative financial instruments include the following:
Propane, ethane, butane, heating oil and crude oil (MMBbls)
Natural gas (Bcf)
December 31, 2021
December 31, 2020
Fixed Price
Payor
Fixed Price
Receiver
Fixed Price
Payor
Fixed Price
Receiver
71.6
31.9
75.8
43.4
72.7
22.6
76.5
28.6
Notional amounts reflect the volume of transactions, but do not represent the amounts exchanged by the parties to the financial
instruments. Accordingly, notional amounts do not reflect our monetary exposure to market or credit risks. All contracts subject
to price risk had a maturity of 37 months or less; however, 87% of the contracted volumes will be delivered or settled within 12
months.
Credit Risk
Inherent in our contractual portfolio are certain credit risks. Credit risk is the risk of loss from nonperformance by suppliers,
customers or financial counterparties to a contract. We take an active role in managing credit risk and have established control
procedures, which are reviewed on an ongoing basis. We attempt to minimize credit risk exposure through credit policies and
periodic monitoring procedures as well as through customer deposits, letters of credit and entering into netting agreements that
allow for offsetting counterparty receivable and payable balances for certain financial transactions, as deemed appropriate. The
counterparties associated with our price risk management activities are energy marketers and propane retailers, resellers and
dealers.
Certain of our derivative instruments have credit limits that require us to post collateral. The amount of collateral required to be
posted is a function of the net liability position of the derivative as well as our established credit limit with the respective
counterparty. If our credit rating were to change, the counterparties could require us to post additional collateral. The amount of
additional collateral that would be required to be posted would vary depending on the extent of change in our credit rating as
well as the requirements of the individual counterparty. In addition, we have margin requirements with a derivative clearing
broker and a third party broker related to our net asset or liability position with each respective broker. All collateral amounts
have been netted against the asset or liability with the respective counterparty and are reflected in our consolidated balance
sheets as assets and liabilities from price risk management activities.
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The following table presents the fair value of our commodity derivative instruments with credit-risk-related contingent features
and their associated collateral (in millions):
Aggregate fair value liability of derivative instruments with credit-risk-related contingent
features(1)
Broker-related net derivative asset position
Broker-related cash collateral received
Cash collateral received, net
December 31,
2021
2020
$
$
$
$
57.9 $
104.8 $
76.8 $
11.4 $
38.5
35.9
18.3
12.4
(1) At December 31, 2021 and 2020, we posted $1.5 million and less than $0.1 million of collateral associated with these derivatives.
Note 8 – Fair Value Measurements
The accounting standard for fair value measurement establishes a three-tier fair value hierarchy, which prioritizes the inputs
used in measuring fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical
assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three
levels of the fair value hierarchy are as follows:
•
•
Level 1—Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active
markets are those in which transactions for Level 1 primarily consists of financial instruments such as exchange-traded
derivatives, listed equities and US government treasury securities.
Level 2—Pricing inputs are other than quoted prices in active markets included in Level 1, which are either directly or
indirectly observable as of the reporting date. Level 2 includes those financial instruments that are valued using models
or other valuation methodologies. These models are primarily industry-standard models that consider various
assumptions, including quoted forward prices for commodities, time value, volatility factors, and current market and
contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these
assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from
observable data or are supported by observable levels at which transactions are executed in the marketplace.
Instruments in this category include non-exchange-traded derivatives such as over the counter (OTC) forwards, options
and physical exchanges.
•
Level 3—Pricing inputs include significant inputs that are generally less observable from objective sources. These
inputs may be used with internally developed methodologies that result in management’s best estimate of fair value.
Financial Assets and Liabilities
As of December 31, 2021 and 2020, we held certain assets and liabilities that are required to be measured at fair value on a
recurring basis, which include our derivative instruments related to crude oil, NGLs and natural gas. Our derivative instruments
consist of forwards, swaps, futures, physical exchanges and options.
Our derivative instruments that are traded on the NYMEX have been categorized as Level 1.
Our derivative instruments also include OTC contracts, which are not traded on a public exchange. The fair values of these
derivative instruments are determined based on inputs that are readily available in public markets or can be derived from
information available in publicly quoted markets. These instruments have been categorized as Level 2.
Our OTC options are valued based on the Black Scholes option pricing model that considers time value and volatility of the
underlying commodity. The inputs utilized in the model are based on publicly available information as well as broker quotes.
These options have been categorized as Level 2.
Our financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair
value measurement. The assessment of the significance of a particular input to the fair value measurement requires judgment,
and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.
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The following tables set forth by level within the fair value hierarchy, our financial instruments that were accounted for at fair
value on a recurring basis at December 31, 2021 and 2020 (in millions):
December 31, 2021
Level 1 Level 2 Level 3
Gross Fair
Value
Contract
Netting(1)
Collateral/
Margin
Received or
Paid
Fair Value
Assets
Assets from price risk management
Other investments(2)
$ 33.3 $ 695.6 $ — $
728.9 $
(607.4) $
(79.4) $
2.2
—
—
2.2
—
—
Total assets at fair value
$ 35.5 $ 695.6 $ — $
731.1 $
(607.4) $
(79.4) $
42.1
2.2
44.3
Liabilities
Liabilities from price risk management
$ 26.9 $ 686.3 $ — $
713.2 $
(607.4) $
Total liabilities at fair value
$ 26.9 $ 686.3 $ — $
713.2 $
(607.4) $
8.8 $
8.8 $
114.6
114.6
December 31, 2020
Level 1 Level 2 Level 3
Gross Fair
Value
Contract
Netting(1)
Collateral/
Margin
Received or
Paid
Fair Value
Assets
Assets from price risk management
Other investments(2)
$ 20.2 $ 480.5 $ — $
500.7 $
(455.0) $
(18.5) $
2.1
—
—
2.1
—
—
Total assets at fair value
$ 22.3 $ 480.5 $ — $
502.8 $
(455.0) $
(18.5) $
27.2
2.1
29.3
Liabilities
Liabilities from price risk management
$ 25.1 $ 494.0 $ — $
519.1 $
(455.0) $
Total liabilities at fair value
$ 25.1 $ 494.0 $ — $
519.1 $
(455.0) $
12.2 $
12.2 $
76.3
76.3
(1) Amounts represent the impact of legally enforceable master netting agreements that allow us to settle positive and negative positions.
(2) Amount primarily relates to our investment in Suburban Propane Partners, L.P. units which is reflected in other non-current assets on CEQP’s consolidated
balance sheets.
Cash, Accounts Receivable and Accounts Payable
As of December 31, 2021 and 2020, the carrying amounts of cash, accounts receivable and accounts payable approximate fair
value based on the short-term nature of these instruments.
Credit Facility
The fair value of the amounts outstanding under our Crestwood Midstream credit facility approximates the carrying amounts as
of December 31, 2021 and 2020, due primarily to the variable nature of the interest rate of the instrument, which is considered a
Level 2 fair value measurement.
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Senior Notes
We estimate the fair value of our senior notes primarily based on quoted market prices for the same or similar issuances
(representing a Level 2 fair value measurement). The following table represents the carrying amount (reduced for deferred
financing costs associated with the respective notes) and fair value of our senior notes (in millions):
2023 Senior Notes
2025 Senior Notes
2027 Senior Notes
2029 Senior Notes
Note 9 – Long-Term Debt
Long-term debt consisted of the following (in millions):
Credit Facility
2023 Senior Notes
2025 Senior Notes
2027 Senior Notes
2029 Senior Notes
Other(1)
Less: deferred financing costs, net
Total debt
Less: current portion
December 31, 2021
December 31, 2020
Carrying
Amount
Fair
Value
Carrying
Amount
Fair
Value
$
$
$
$
— $
496.5 $
594.2 $
690.8 $
— $
511.9 $
615.0 $
727.3 $
683.8 $
495.5 $
593.2 $
— $
691.5
509.9
594.1
—
December 31,
2021
2020
$
282.0 $
—
500.0
600.0
700.0
0.2
29.9
2,052.3
0.2
719.0
687.2
500.0
600.0
—
0.4
22.6
2,484.0
0.2
Total long-term debt, less current portion
$
2,052.1 $
2,483.8
(1) Represents non-interest bearing obligations related to certain companies acquired in 2014 with payments due through 2022.
Credit Facility
In December 2021, Crestwood Midstream entered into a Third Amended and Restated Credit Agreement (the CMLP Credit
Agreement). The CMLP Credit Agreement provides for a five-year $1.5 billion revolving credit facility (the CMLP Credit
Facility), which matures in December 2026 and is available to fund acquisitions, working capital and internal growth projects
and for general partnership purposes. The CMLP Credit Agreement increased from $1.25 billion to $1.5 billion upon the
closing of the merger with Oasis Midstream Partners LP (Oasis Midstream) on February 1, 2022, which is further discussed in
Note 20. The credit agreement allows Crestwood Midstream to increase its available borrowings under the facility by $350
million, subject to lender approval and the satisfaction of certain other conditions, as described in the credit agreement. The
CMLP Credit Facility also includes a sub-limit of up to $25 million for same-day swing line advances and a sub-limit up to
$350 million for letters of credit. Subject to limited exception, the CMLP Credit Facility is guaranteed and secured by
substantially all of the equity interests and assets of Crestwood Midstream’s subsidiaries, except for Crestwood Infrastructure
Holdings LLC, Crestwood Niobrara, PRBIC and Tres Holdings and their respective subsidiaries. Crestwood Equity also
guarantees Crestwood Midstream’s payment obligations under its $1.5 billion credit agreement. We recognized a loss on
extinguishment of debt of approximately $0.8 million for the year ended December 31, 2021 in conjunction with amending and
restating the CMLP Credit Agreement.
Prior to amending and restating its credit agreement in December 2021, Crestwood Midstream had a five-year $1.25 billion
senior secured revolving credit facility, which would have expired in October 2023 (2023 Credit Facility). Contemporaneous
with the Crestwood Holdings Transactions in March 2021, Crestwood Midstream amended the 2023 Credit Facility in order to,
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among other things, permit the borrowings under the 2023 Credit Facility to fund the Crestwood Holdings Transactions and
revise the definition of Change in Control in the credit agreement as it relates to the control of CEQP’s general partner.
The CMLP Credit Agreement contains various covenants and restrictive provisions that limit our ability to, among other things,
(i) incur additional debt; (ii) make distributions on or redeem or repurchase units; (iii) make certain investments and
acquisitions; (iv) incur or permit certain liens to exist; (v) merge, consolidate or amalgamate with another company; (vi)
transfer or dispose of assets; and (vii) incur a change in control at either Crestwood Equity or Crestwood Midstream.
Borrowings under the CMLP Credit Facility (other than the swing line loans) bear interest at either:
•
•
the Alternate Base Rate, which is defined as the highest of (i) the federal funds rate plus 0.50%; (ii) Wells Fargo
Bank’s prime rate; or (iii) the Adjusted Term SOFR (as defined in the credit agreement) for a one-month tenor plus 1%
per annum; plus a margin varying from 0.50% to 1.50% depending on Crestwood Midstream’s most recent
consolidated total leverage ratio; or
Adjusted Term SOFR plus a margin varying from 1.50% to 2.50% depending on Crestwood Midstream’s most recent
consolidated total leverage ratio.
Swing line loans bear interest at the Alternate Base Rate as described above. The unused portion of the CMLP Credit Facility is
subject to a commitment fee ranging from 0.30% to 0.50% according to CMLP’s most recent consolidated total leverage ratio.
Interest on the Alternate Base Rate loans is payable quarterly, or if the Adjusted Term SOFR applies, interest is payable at
certain intervals selected by Crestwood Midstream.
Crestwood Midstream is required under its credit agreement to maintain a net debt to consolidated EBITDA ratio (as defined in
its credit agreement) of not more than 5.50 to 1.0, a consolidated EBITDA to consolidated interest expense ratio (as defined in
its credit agreement) of not less than 2.50 to 1.0, and a senior secured leverage ratio (as defined in its credit agreement) of not
more than 3.50 to 1.0. At December 31, 2021, the net debt to consolidated EBITDA was approximately 3.53 to 1.0, the
consolidated EBITDA to consolidated interest expense was approximately 4.93 to 1.0, and the senior secured leverage ratio was
0.48 to 1.0.
At December 31, 2021, Crestwood Midstream had $961.7 million of available capacity under its credit facility considering the
most restrictive covenants in its credit agreement. At December 31, 2021 and 2020, Crestwood Midstream’s outstanding
standby letters of credit were $6.3 million and $23.9 million. The interest rates on borrowings under the credit facility were
between 1.90% and 4.00% at December 31, 2021 and 2.40% and 4.50% at December 31, 2020. The weighted-average interest
rates on outstanding borrowings as of December 31, 2021 and 2020 was 1.91% and 2.45%.
If Crestwood Midstream fails to perform its obligations under these and other covenants, the lenders’ credit commitment could
be terminated and any outstanding borrowings, together with accrued interest, under the CMLP Credit Facility could be
declared immediately due and payable. The CMLP Credit Facility also has cross default provisions that apply to any of its other
material indebtedness.
Senior Notes
2023 Senior Notes. The 6.25% Senior Notes due 2023 (the 2023 Senior Notes) were scheduled to mature on April 1, 2023.
During the year ended December 31, 2021, we redeemed $687.2 million of principal under the 2023 Senior Notes. In
conjunction with the repayment of the notes, we recognized a loss on extinguishment of debt of approximately $6.7 million
during the year ended December 31, 2021, and paid approximately $8.6 million of accrued interest on the 2023 Senior Notes on
the dates they were repurchased. We funded the repayment using a portion of the proceeds from the issuance of the 2029 Senior
Notes (described below) and borrowings under the 2023 Credit Facility. During the year ended December 31, 2020, we paid
approximately $12.6 million to repurchase and cancel approximately $12.8 million of the 2023 Senior Notes.
2025 Senior Notes. The 5.75% Senior Notes due 2025 (the 2025 Senior Notes) mature on April 1, 2025, and interest is payable
semi-annually in arrears on April 1 and October 1 of each year.
2027 Senior Notes. In April 2019, Crestwood Midstream issued $600 million of 5.625% unsecured senior notes due 2027 (the
2027 Senior Notes). The 2027 Senior Notes mature on May 1, 2027, and interest is payable semi-annually in arrears on May 1
and November 1 of each year, beginning November 1, 2019. The net proceeds from this offering of approximately $591.1
million were used to fund the acquisition of the remaining 50% equity interest in Jackalope.
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2029 Senior Notes. In January 2021, Crestwood Midstream issued $700 million of 6.00% unsecured senior notes due 2029 (the
2029 Senior Notes). The 2029 Senior Notes mature on February 1, 2029, and interest is payable semiannually in arrears on
February 1 and August 1 of each year, beginning on August 1, 2021. The net proceeds from this offering of approximately
$691.0 million were used to repay a portion of the 2023 Senior Notes and to repay indebtedness under the 2023 Credit Facility.
In general, each series of Crestwood Midstream’s senior notes are fully and unconditionally guaranteed, joint and severally, on
a senior unsecured basis by Crestwood Midstream’s domestic restricted subsidiaries (other than Crestwood Midstream Finance
Corp., which has no assets). The indentures contain customary release provisions, such as (i) disposition of all or substantially
all the assets of, or the capital stock of, a guarantor subsidiary to a third person if the disposition complies with the indentures;
(ii) designation of a guarantor subsidiary as an unrestricted subsidiary in accordance with its indentures; (iii) legal or covenant
defeasance of a series of senior notes, or satisfaction and discharge of the related indenture; and (iv) guarantor subsidiary ceases
to guarantee any other indebtedness of Crestwood Midstream or any other guarantor subsidiary, provided it no longer
guarantees indebtedness under the CMLP Credit Facility.
The indentures restrict the ability of Crestwood Midstream and its restricted subsidiaries to, among other things, sell assets;
redeem or repurchase subordinated debt; make investments; incur or guarantee additional indebtedness or issue preferred units;
create or incur certain liens; enter into agreements that restrict distributions or other payments to Crestwood Midstream from its
restricted subsidiaries; consolidate, merge or transfer all or substantially all of their assets; engage in affiliate transactions;
create unrestricted subsidiaries; and incur a change in control at either Crestwood Equity or Crestwood Midstream. These
restrictions are subject to a number of exceptions and qualifications, and many of these restrictions will terminate when the
senior notes are rated investment grade by either Moody’s Investors Service, Inc. or Standard & Poor’s Rating Services and no
default or event of default (each as defined in the respective indentures) under the indentures has occurred and is continuing.
At December 31, 2021, Crestwood Midstream was in compliance with the debt covenants and restrictions in each of its credit
agreements discussed above.
The CMLP Credit Facility and senior notes are secured by the net assets of its guarantor subsidiaries. Accordingly, such assets
are only available to the creditors of Crestwood Midstream. Crestwood Equity had restricted net assets of approximately
$1,232.3 million as of December 31, 2021.
Maturities
The aggregate maturities of principal amounts on our outstanding long-term debt as of December 31, 2021 for the next five
years and in total thereafter are as follows (in millions):
2022
2023
2024
2025
2026
Thereafter
Total debt
$
$
0.2
—
—
500.0
282.0
1,300.0
2,082.2
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Note 10 – Commitments and Contingencies
Legal Proceedings
Oasis Unitholder Lawsuit. On December 17, 2021, Kristen Eckert-Smith (Plaintiff), a common unitholder of Oasis Midstream
filed a complaint in the United States District Court for the District of Delaware on behalf of all Oasis common unitholders.
This complaint alleges that the merger between Oasis Midstream and Crestwood Equity violates the Securities Exchange Act of
1934. In addition, the Plaintiff filed a lawsuit against Oasis Midstream, its board of directors and Crestwood Equity GP,
claiming the Registration Statement filed with the SEC omitted material information with respect to Oasis Midstream’s
calculated projections and financial analyses. The Plaintiff is seeking to block the parties from closing the merger and in the
alternative, to revise the Registration Statement and award plaintiff the attorney’s and expert’s fees. We are currently evaluating
the potential impact of this lawsuit, but currently do not believe it will have a material impact on our financial condition or
results of operations.
Linde Lawsuit. On December 23, 2019, Linde Engineering North America Inc. (Linde) filed a lawsuit in the District Court of
Harris County, Texas alleging that Arrow Field Services, LLC, our consolidated subsidiary, and Crestwood Midstream
breached a contract entered into in March 2018 under which Linde was to provide engineering, procurement and construction
services to us related to the completion of the construction of the Bear Den II cryogenic processing plant. During the year ended
December 31, 2021, we paid approximately $19.5 million to Linde related to this matter, and Linde claims remaining unpaid
invoices of approximately $36 million, along with other damages. This matter is not an insurable event based on our insurance
policies, and we are unable to predict the outcome for this matter.
General. We are periodically involved in litigation proceedings. If we determine that a negative outcome is probable and the
amount of loss is reasonably estimable, then we accrue the estimated amount. The results of litigation proceedings cannot be
predicted with certainty. We could incur judgments, enter into settlements or revise our expectations regarding the outcome of
certain matters, and such developments could have a material adverse effect on our results of operations or cash flows in the
period in which the amounts are paid and/or accrued. As of December 31, 2021 and 2020, we had approximately $16.8 million
and $10.4 million accrued for outstanding legal matters. Based on currently available information, we believe it is remote that
future costs related to known contingent liability exposures for which we can estimate will exceed current accruals by an
amount that would have a material adverse impact on our consolidated financial statements. As we learn new facts concerning
contingencies, we reassess our position both with respect to accrued liabilities and other potential exposures.
Any loss estimates are inherently subjective, based on currently available information, and are subject to management’s
judgment and various assumptions. Due to the inherently subjective nature of these estimates and the uncertainty and
unpredictability surrounding the outcome of legal proceedings, actual results may differ materially from any amounts that have
been accrued.
Regulatory Compliance
In the ordinary course of our business, we are subject to various laws and regulations. In the opinion of our management,
compliance with current laws and regulations will not have a material effect on our results of operations, cash flows or financial
condition.
Environmental Compliance
Our operations are subject to stringent and complex laws and regulations pertaining to worker health, safety, and the
environment. We are subject to laws and regulations at the federal, state, regional and local levels that relate to air and water
quality, hazardous and solid waste management and disposal, and other environmental matters. The cost of planning, designing,
constructing and operating our facilities must incorporate compliance with environmental laws and regulations and safety
standards. Failure to comply with these laws and regulations may trigger a variety of administrative, civil and potentially
criminal enforcement measures.
During 2019, we experienced two produced water releases on our Arrow water gathering system located within the Fort
Berthold Indian Reservation in North Dakota. In January 2021, we received a Notice of Violation and Opportunity to Confer
from the EPA related to the water releases. In March 2021, we executed a Consent Agreement with the EPA and in January
2022, we paid approximately $0.1 million in civil penalties to resolve the matter. We are also substantially complete with all
remediation efforts related to the water releases and continue to monitor any remaining impacts. We believe these events are
insurable under our policies. We have not recorded an insurance receivable as of December 31, 2021.
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At December 31, 2021 and 2020, our accrual of approximately $1.0 million and $1.3 million was based on our undiscounted
estimate of amounts we will spend on compliance with environmental and other regulations, and any associated fines or
penalties. We estimate that our potential liability for reasonably possible outcomes related to our environmental exposures
could range from approximately $1.0 million to $1.9 million at December 31, 2021.
Self-Insurance
We utilize third-party insurance subject to varying retention levels of self-insurance, which management considers prudent.
Such self-insurance relates to losses and liabilities primarily associated with medical claims, workers’ compensation claims and
general, product, vehicle and environmental liability. Losses are accrued based upon management’s estimates of the aggregate
liability for claims incurred using certain assumptions followed in the insurance industry and based on past experience. The
primary assumption utilized is actuarially determined loss development factors. The loss development factors are based
primarily on historical data. Our self-insurance reserves could be affected if future claim developments differ from the historical
trends. We believe changes in health care costs, trends in health care claims of our employee base, accident frequency and
severity and other factors could materially affect the estimate for these liabilities. We continually monitor changes in employee
demographics, incident and claim type and evaluate our insurance accruals and adjust our accruals based on our evaluation of
these qualitative data points. We are liable for the development of claims for our previously disposed of retail propane
operations, provided they were reported prior to August 1, 2012. The following table summarizes CEQP’s and CMLP’s self-
insurance reserves (in millions):
Self-insurance reserves(1)
CEQP
December 31,
CMLP
December 31,
2021
2020
2021
2020
$
5.5 $
7.7 $
4.7 $
6.7
(1) At December 31, 2021, CEQP and CMLP classified approximately $3.5 million and $2.9 million, respectively of these reserves as other long-term
liabilities on their consolidated balance sheets.
Purchase Commitments
We periodically enter into agreements with suppliers to purchase fixed quantities of NGLs, distillates, crude oil and natural gas
at fixed prices. At December 31, 2021, the total of these firm purchase commitments was $2,760.9 million, of which
approximately $2,493.6 million will occur over the next twelve months. We also enter into non-binding agreements with
suppliers to purchase quantities of NGLs, distillates, crude oil and natural gas at variable prices at future dates at the then
prevailing market prices.
We have entered into certain purchase commitments which totaled approximately $15.6 million at December 31, 2021. These
purchase commitments primarily relate to future growth projects and maintenance obligations in our gathering and processing
north segment. The purchases associated with our commitments are expected to occur over the next twelve months.
Guarantees and Indemnifications
We are involved in various joint ventures that sometimes require financial and performance guarantees. In a financial guarantee,
we are obligated to make payments if the guaranteed party fails to make payments under, or violates the terms of, the financial
arrangement. In a performance guarantee, we provide assurance that the guaranteed party will execute on the terms of the
contract. If they do not, we are required to perform on their behalf. We also periodically provide indemnification arrangements
related to assets or businesses we have sold.
Our potential exposure under guarantee and indemnification arrangements can range from a specified amount to an unlimited
dollar amount, depending on the nature of the claim, specificity as to duration, and the particular transaction. As of
December 31, 2021, we have no amounts accrued for these guarantees.
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Note 11 - Leases
The following table summarizes the balance sheet information related to our operating and finance leases (in millions):
Operating leases
Operating lease right-of-use assets, net
Accrued expenses and other liabilities
Other long-term liabilities
Total operating lease liabilities
Finance leases
Property, plant and equipment
Less: accumulated depreciation
Property, plant and equipment, net
Accrued expenses and other liabilities
Other long-term liabilities
Total finance lease liabilities
December 31,
2021
2020
$
$
$
$
$
$
$
27.4 $
13.2 $
19.4
32.6 $
36.8
14.7
28.5
43.2
12.3 $
13.3
9.2
3.1 $
1.7 $
1.2
2.9 $
7.9
5.4
2.9
1.9
4.8
The following table presents the weighted-average remaining lease term and the weighted-average discount rate associated with
our operating and finance leases:
Weighted-average remaining lease term (in years)
Operating leases(1)
Finance leases(2)
Weighted-average discount rate
Operating leases(3)
Finance leases(3)
December 31,
2021
2020
3.9
2.6
5.9 %
5.5 %
4.3
1.7
6.2 %
7.3 %
(1) Remaining terms vary from one year to 18 years as of December 31, 2021.
(2) Remaining terms vary from one year to five years as of December 31, 2021.
(3) As of December 31, 2021 and 2020, we utilized discount rates ranging from 1.5% to 8.3% and 2.6% to 12.8%, respectively, to estimate the discounted
cash flows used in estimating our right-of-use assets and lease liabilities, which were primarily based on our credit-adjusted collateralized incremental
borrowing rate.
The estimation of our right-of-use assets and lease liabilities requires us to make significant assumptions and judgments about
the terms of the leases, variable payments, and discount rates. Certain of our operating leases have renewal options to extend the
leases from one year to 10 years at the end of each lease term, or terminate the leases at our sole discretion. In addition, certain
of our finance leases have options to purchase the lease property by the end of the lease term. We make significant assumptions
on the likelihood on whether we will renew our leases or purchase the property at the end of the lease terms in determining the
discounted cash flows to measure our right-of-use assets and lease liabilities. The estimation of variable lease payments in
determining discounted cash flows, including those with usage-based costs, also requires us to make significant assumptions on
the timing and nature of the variability of those payments based on the lease terms.
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We recognize operating lease expense and amortize our right-of-use assets for our finance leases on a straight-line basis over
the term of the respective leases. We have applied the practical expedient of not separating the lease and non-lease components
for our leases where the predominant consideration paid related to the underlying operating and finance lease contracts relate to
the lease component. The following table presents the costs and sublease income associated with our operating and finance
leases (in millions):
Operating leases
Operating lease expense(1)(2)
Lease income(3)
Total operating lease expense, net
Finance leases
Amortization of right-of-use assets(4)
Interest on lease liabilities(5)
Total finance lease expense
Year Ended December 31,
2021
2020
2019
$
$
$
$
20.0 $
(3.7)
16.3 $
3.0 $
0.3
3.3 $
27.2 $
(1.7)
25.5 $
3.5 $
0.5
4.0 $
28.3
(1.0)
27.3
3.6
0.7
4.3
(2)
(1) Approximately $13.4 million, $17.6 million and $17.5 million is included in costs of product/services sold, $3.9 million, $6.7 million and $8.0 million is
included in operations and maintenance expense and $2.7 million, $2.9 million and $2.8 million is included in general and administrative expense on our
consolidated statements of operations for the years ended December 31, 2021, 2020 and 2019, respectively.
Includes short-term and variable lease costs of approximately $2.2 million, $5.5 million and $3.7 million for the years ended December 31, 2021, 2020
and 2019.
Included in service revenues on our consolidated statements of operations.
Included in depreciation, amortization and accretion expense on our consolidated statements of operations.
Included in interest and debt expense, net on our consolidated statements of operations.
(3)
(4)
(5)
The following table presents supplemental cash flow information for our operating and finance leases (in millions):
Cash paid for lease liabilities
Operating cash flows from operating leases
Operating cash flows from finance leases
Financing cash flows from finance leases
Right-of-use assets obtained in exchange for lease obligations
Operating leases
Finance leases
Year Ended December 31,
2021
2020
2019
$
$
$
$
$
19.0 $
21.3 $
0.3 $
2.8 $
— $
1.5 $
0.5 $
3.1 $
2.1 $
0.4 $
22.9
0.7
3.5
4.2
1.8
The following table presents the future minimum lease liabilities for our leases as of December 31, 2021 for the next five years
and in total thereafter (in millions):
Year Ending December 31,
2022
2023
2024
2025
2026
Thereafter
Total lease payments
Less: interest
Operating
Leases
Finance
Leases
Total
$
14.6 $
1.8 $
16.4
7.5
6.6
3.2
3.0
2.0
36.9
4.3
0.5
0.3
0.3
0.2
—
3.1
0.2
8.0
6.9
3.5
3.2
2.0
40.0
4.5
35.5
Present value of lease liabilities
$
32.6 $
2.9 $
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Note 12 – Partners’ Capital and Non-Controlling Partner
Preferred Units
Subject to certain conditions, the holders of the preferred units will have the right to convert preferred units into (i) common
units on a 1-for-10 basis, or (ii) a number of common units determined pursuant to a conversion ratio set forth in Crestwood
Equity’s partnership agreement upon the occurrence of certain events, such as a change in control. The preferred units have
voting rights that are identical to the voting rights of the common units and will vote with the common units as a single class,
with each preferred units entitled to one vote for each common unit into which such preferred unit is convertible, except that the
preferred units are entitled to vote as a separate class on any matter on which all unitholders are entitled to vote that adversely
affects the rights, powers, privileges or preferences of the preferred units in relation to CEQP’s other securities outstanding.
Common and Subordinated Units
In conjunction with the Crestwood Holdings Transactions discussed in Note 1, in March 2021, CEQP acquired approximately
11.5 million CEQP common units and 0.4 million subordinated units of CEQP from Crestwood Holdings for approximately
$268 million. CEQP reflected the purchase price as a reduction to its common unitholders’ partners’ capital in its consolidated
statement of partners’ capital during the year ended December 31, 2021. The Crestwood Holdings Transactions resulted in
CEQP retiring the common and subordinated units acquired from Crestwood Holdings. Transaction costs related to the
Crestwood Holdings Transactions of approximately $7.6 million are reflected as a reduction of CEQP’s common unitholders’
partners’ capital in its consolidated statement of partners’ capital during the year ended December 31, 2021.
Distributions
Crestwood Equity
Limited Partners. Crestwood Equity makes quarterly distributions to its partners within approximately 45 days after the end of
each quarter in an aggregate amount equal to its available cash for such quarter. Available cash generally means, with respect to
each quarter, all cash on hand at the end of the quarter less the amount of cash that the general partner determines in its
reasonable discretion is necessary or appropriate to:
•
•
•
provide for the proper conduct of its business;
comply with applicable law, any of its debt instruments, or other agreements; or
provide funds for distributions to unitholders for any one or more of the next four quarters;
plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings
made after the end of the quarter. The amount of cash CEQP has available for distribution depends primarily upon its cash flow
(which consists of the cash distributions it receives in connection with its ownership of Crestwood Midstream).
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A summary of CEQP’s limited partner quarterly cash distributions for the years ended December 31, 2021, 2020 and 2019 is
presented below:
Record Date
Payment Date
Per Unit Rate
Cash Distributions
(in millions)
2021
February 5, 2021
May 7, 2021
August 6, 2021
February 12, 2021
May 14, 2021
August 13, 2021
November 5, 2021
November 12, 2021
2020
February 7, 2020
May 8, 2020
August 7, 2020
February 14, 2020
May 15, 2020
August 14, 2020
November 6, 2020
November 13, 2020
2019
February 7, 2019
May 8, 2019
August 7, 2019
February 14, 2019
May 15, 2019
August 14, 2019
November 7, 2019
November 14, 2019
$
$
$
$
$
$
$
$
$
$
$
$
0.625 $
0.625
0.625
0.625
$
0.625 $
0.625
0.625
0.625
$
0.60 $
0.60
0.60
0.60
$
46.4
39.3
39.3
39.3
164.3
45.3
45.7
45.7
46.0
182.7
43.1
43.1
43.1
43.1
172.4
On February 14, 2022, we paid a distribution of $0.625 per limited partner unit to unitholders of record on February 7, 2022
with respect to the fourth quarter of 2021.
Preferred Unitholders. The holders of our preferred units are entitled to receive fixed quarterly distributions of $0.2111 per
unit. Distributions on the preferred units are paid in cash unless, subject to certain exceptions, (i) there is no distribution being
paid on our common units; and (ii) our available cash (as defined in our partnership agreement) is insufficient to make a cash
distribution to our preferred unitholders. If we fail to pay the full amount payable to our preferred unitholders in cash, then (x)
the fixed quarterly distribution on the preferred units will increase to $0.2567 per unit, and (y) we will not be permitted to
declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the
preferred units have been paid in full in cash. In addition, if we fail to pay in full any preferred distribution (as defined in our
partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for
which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of
2.8125% per quarter.
During each of the years ended December 31, 2021, 2020 and 2019, we paid cash distributions to our preferred unitholders of
approximately $60.1 million. On February 14, 2022, we made a cash distribution of approximately $15.0 million to our
preferred unitholders with respect to the fourth quarter of 2021.
Crestwood Midstream
In accordance with the partnership agreement, Crestwood Midstream’s general partner may, from time to time, cause
Crestwood Midstream to make cash distributions at the sole discretion of the general partner. During the years ended
December 31, 2021, 2020 and 2019, Crestwood Midstream paid cash distributions of $509.7 million, $242.6 million and $235.8
million, which represented net amounts due to Crestwood Midstream related to cash advances to CEQP for its general corporate
activities.
Non-Controlling Partner
Crestwood Niobrara issued $175 million of Series A-2 Preferred Interests to CN Jackalope Holdings LLC (Jackalope Holdings)
in conjunction with its equity interest in Jackalope. In April 2019, Crestwood Niobrara issued $235 million in new Series A-3
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Preferred Units (collectively with the Series A-2 Preferred Units defined as the Crestwood Niobrara Preferred Units) to
Jackalope Holdings in conjunction with Crestwood Niobrara’s acquisition of the remaining 50% equity interest in Jackalope
from Williams. In connection with the issuance of the Series A-3 Preferred Units, we entered into a Third Amended and
Restated Limited Liability Company Agreement (Crestwood Niobrara Amended Agreement) with Jackalope Holdings,
pursuant to which we serve as managing member of Crestwood Niobrara. The Crestwood Niobrara Amended Agreement
modified certain provisions under the previous limited liability company agreement related to the conversion and redemption of
the Series A-2 Preferred Units, as follows:
•
•
•
The Crestwood Niobrara Preferred Units are convertible by the preferred interest holder starting on January 1, 2021
into Crestwood Niobrara common units. The preferred interest holder has the option to contribute additional capital to
Crestwood Niobrara to increase their common ownership percentage in Crestwood Niobrara to 50% upon the
conversion.
The Crestwood Niobrara Preferred Units are redeemable by the preferred interest holder starting on December 31,
2023 for an amount equal to the Liquidation Preference (as defined in the Crestwood Niobrara Amended Agreement).
If redemption is elected by the preferred interest holder, we have the option to elect to give consideration equal to the
Liquidation Preference in either (i) unregistered CEQP common units (subject to a Registration Rights Agreement)
with a total value of up to $100 million and/or cash; or (ii) proceeds from a full liquidation of Crestwood Niobrara’s
assets and unregistered CEQP common units (subject to a Registration Rights Agreement).
The Crestwood Niobrara Preferred Units are redeemable by us starting on January 1, 2023 for either (i) unregistered
CEQP common units (subject to a Registration Rights Agreement) with a total value of up to $100 million and/or cash;
or (ii) proceeds from a full liquidation of Crestwood Niobrara’s assets and registered CEQP common units (subject to
a Registration Rights Agreement).
As a result of the modification of the conversion and redemption provisions of the Crestwood Niobrara Preferred Units, we
continue to consolidate Crestwood Niobrara and have reflected the preferred interests as a non-controlling interest in subsidiary
apart from partners’ capital (i.e., temporary equity) on our consolidated balance sheets at December 31, 2021 and 2020. We
adjust the carrying amount of the non-controlling interest to its redemption value each period through net income attributable to
non-controlling partner.
The following table shows the change in the interest of our non-controlling partner in subsidiary at December 31, 2021, 2020
and 2019 (in millions):
Balance at December 31, 2018
Reclassification of Series A-2 Preferred Units
Issuance of Series A-3 Preferred Units
Distributions to non-controlling partner
Net income attributable to non-controlling partner
Balance at December 31, 2019
Contributions from non-controlling partner
Distributions to non-controlling partner
Net income attributable to non-controlling partner
Balance at December 31, 2020
Contributions from non-controlling partner
Distributions to non-controlling partner
Net income attributable to non-controlling partner
Balance at December 31, 2021
$
$
—
178.8
235.0
(18.4)
30.8
426.2
2.8
(37.1)
40.8
432.7
1.0
(40.2)
41.1
434.6
Crestwood Niobrara is required to make quarterly cash distributions on its preferred interests within 30 days after the end of
each quarter. During the years ended December 31, 2021, 2020 and 2019, Crestwood Niobrara paid cash distributions of $40.2
million, $37.1 million and $25.0 million to Jackalope Holdings. In January 2022, Crestwood Niobrara paid a cash distribution
of $10.3 million to Jackalope Holdings with respect to the fourth quarter of 2021.
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Note 13 - Equity Plans
Long-term incentive awards are granted under the Crestwood LTIP in order to align the economic interests of key employees
and directors with those of CEQP’s common unitholders and to provide an incentive for continuous employment. Long-term
incentive compensation consist of grants of restricted, phantom and performance units which vest based upon continued
service.
As of December 31, 2021 and 2020, we had total unamortized compensation expense of approximately $33.2 million and $29.7
million related to restricted, phantom, and performance units, which will be amortized during the next three years (or sooner in
certain cases, which generally represents the original vesting period of these instruments), except for grants to non-employee
directors of our general partner, which vest over one year. We recognized compensation expense of approximately $39.5
million, $35.1 million and $45.1 million under the Crestwood LTIP during the years ended December 31, 2021, 2020 and 2019,
which is included in general and administrative expenses on our consolidated statements of operations. During the years ended
December 31, 2021 and 2020, compensation expense includes approximately $4.4 million and $1.4 million related to equity
awards under the Crestwood LTIP that was included in accrued expenses and other liabilities on our consolidated balance
sheets. As of February 18, 2022, we had 2,530,862 units available for issuance under the Crestwood LTIP.
Restricted Units. The Crestwood LTIP permits grants of restricted units that are designed to provide an incentive for
continuous employment to certain key employees. Restricted units vest over a three-year period following the grant date or, if
earlier, upon change of control of Crestwood Equity’s general partner or due to death or disability of the employee.
Phantom Units. The Crestwood LTIP permits grants of phantom units that entitle the holder to receive upon vesting one CEQP
common unit pursuant to the Crestwood LTIP and the Crestwood Equity Phantom Unit Agreement. The Crestwood Equity
Phantom Unit Agreement provides for vesting to occur at the end of three years following the grant date or, if earlier, upon the
named executive officer’s termination without cause or due to death or disability or the named executive officer’s resignation
for employee cause (each, as defined in the Crestwood Equity Phantom Unit Agreement). In addition, the Crestwood Equity
Phantom Unit Agreement provides for distribution equivalent rights with respect to each phantom unit which are paid in
additional phantom units and settled in common units upon vesting of the underlying phantom units.
Performance Units. The Crestwood LTIP permits grants of performance units that are designed to provide an incentive for
continuous employment to certain key employees. The vesting of performance units is subject to the attainment of certain
performance and market goals over a three-year period and entitle a participant to receive common units of Crestwood Equity
without payment of an exercise price upon vesting. The number of units issued are based on a performance multiplier ranging
between 50% and 200%, determined based on the actual performance in the third year of the performance period compared to
pre-established performance goals. The performance goals are based on achieving a specified level of distributable cash flow
per unit, Adjusted EBITDA, return on capital invested, and three-year relative total shareholder return.
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The following table summarizes information regarding restricted, phantom and performance unit activity during the years ended
December 31, 2021, 2020 and 2019.
Units
Weighted-Average
Grant Date Fair Value
Unvested - January 1, 2019
Granted - restricted units
Granted - phantom units
Granted - performance units
Vested - restricted units
Vested - performance units
Forfeited - restricted units
Unvested - December 31, 2019
Granted - restricted units
Granted - phantom units
Granted - performance units
Vested - restricted units
Vested - phantom units
Vested - performance units
Forfeited - restricted units
Forfeited - phantom units
Forfeited - performance units
Unvested - December 31, 2020
Granted - restricted units
Granted - phantom units
Granted - performance units
Vested - restricted units
Vested - phantom units
Forfeited - restricted units
Unvested - December 31, 2021
2,187,970 $
988,096 $
7,164 $
238,263 $
(985,751) $
(32,246) $
(47,547) $
2,355,949 $
1,569,451 $
17,726 $
715,674 $
(906,275) $
(2,118) $
(846,306) $
(149,001) $
(14,157) $
(17,087) $
2,723,856 $
1,399,781 $
5,795 $
71,286 $
(1,148,928) $
(2,117) $
(48,565) $
3,001,108 $
24.78
31.48
29.03
34.21
23.39
34.21
27.85
28.94
25.42
28.48
28.46
28.75
26.63
29.85
28.24
27.91
27.35
26.62
20.51
18.88
25.60
27.65
26.63
21.67
23.42
Under the Crestwood LTIP, participants who have been granted restricted units and/or performance units may elect to have us
withhold common units to satisfy minimum statutory tax withholding obligations arising in connection with the vesting of non-
vested common units. Any such common units withheld are returned to the Crestwood LTIP on the applicable vesting dates,
which correspond to the times at which income is recognized by the employee. When we withhold these common units, we are
required to remit to the appropriate taxing authorities the fair value of the units withheld as of the vesting date. The number of
units withheld is determined based on the closing price per common unit as reported on the NYSE on such dates. During the
years ended December 31, 2021, 2020, and 2019, we withheld 423,330, 581,608 and 336,548 common units to satisfy
employee tax withholding obligations for the restricted and performance units.
Employee Unit Purchase Plan
In August 2018, the board of directors of our general partner approved an employee unit purchase plan under which employees
of the general partner may purchase our common units through payroll deductions up to a maximum of 10% of the employees’
eligible compensation, not to exceed $25,000 for any calendar year. Under the plan, we anticipate purchasing our common units
on the open market for the benefit of participating employees based on their payroll deductions. In addition, we may match up
to 10% of participating employees’ payroll deductions to purchase additional Crestwood common units for participating
employees. The board of directors of our general partner authorized 1,500,000 common units (subject to adjustment as provided
in the employee unit purchase plan) to be available for purchase. During the years ended December 31, 2021, 2020 and 2019,
9,932, 29,784 and 6,341 common units were purchased under the plan.
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Note 14 - Earnings Per Limited Partner Unit
Prior to the Crestwood Holdings transactions, we calculated basic net income per limited partner unit using the two-class
method. Our income (loss) was allocated to our common units and other participating securities (i.e., subordinated units) based
on the amount of dividends paid in the current period plus an allocation of the undistributed earnings or excess distributions
over earnings to the extent that each security participates in income (loss) or excess distributions over income (loss). The
dilutive effect of the unit-based compensation performance units is calculated using the treasury stock method which considers
the impact to net income or loss attributable to Crestwood Equity Partners and limited partner units from the potential issuance
of limited partner units. The dilutive effect of the preferred units and Crestwood Niobrara preferred units are calculated using
the if-converted method which assumes units are converted at the beginning of the period (beginning with their respective
issuance date), and the resulting common units are included in the denominator of the diluted net income per common unit
calculation for the period being presented. Distributions declared in the period and undeclared distributions that accumulated
during the period are added back to the numerator for purposes of the if-converted calculation.
We exclude potentially dilutive securities from the determination of diluted earnings per unit (as well as their related income
statement impacts) when their impact is anti-dilutive. The following table summarizes information regarding the weighted-
average of common units excluded during the years ended December 31, 2021, 2020 and 2019 (in millions):
Preferred units(1)
Crestwood Niobrara’s preferred units(1)
Unit-based compensation performance units(2)
Subordinated units(3)
Year Ended December 31,
2021
2020
2019
7.1
4.2
0.2
0.1
7.1
5.7
0.1
0.4
7.1
—
—
—
(1) See Note 12 for additional information regarding the potential conversion of our preferred units and Crestwood Niobrara’s preferred units to common
units.
(2) For a description of our unit-based compensation performance units, see Note 13.
(3)
In conjunction with the Crestwood Holdings Transactions, in March 2021, CEQP retired the subordinated units. For additional information regarding the
retirement of the subordinated units, see Note 12.
The following table shows net income (loss) and weighted-average limited partner units used in computing basic and diluted net
income (loss) per limited partner unit for the years ended December 31, 2021, 2020 and 2019 (in millions, except per unit data):
Year Ended December 31,
2021
2020
2019
$
$
(138.6) $
(116.2) $
223.6
—
—
1.4
(138.6) $
(116.2) $
225.0
65.6
—
—
—
65.6
73.2
—
—
—
73.2
71.8
4.3
0.4
0.4
76.9
$
$
(2.11) $
(2.11) $
(1.59) $
(1.59) $
3.11
2.93
Common unitholders’ interest in net income (loss)
Dilutive effect of net income attributable to subordinated units
Diluted net income (loss)
Weighted-average limited partners’ units outstanding - basic
Dilutive effect of Crestwood Niobrara preferred units
Dilutive effect of stock-based compensation performance units
Dilutive effect of subordinated units
Weighted-average limited partners’ units outstanding - diluted
Net income (loss) per limited partner unit:
Basic
Diluted
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Note 15 - Employee Benefit Plan
A 401(k) plan is available to all of our employees after meeting certain requirements. The plan permits employees to make
contributions of up to 90% of their salary, subject to statutory limits, which was $19,500 in 2021, $19,500 in 2020 and $19,000
in 2019. We match 100% of participants’ basic contributions up to 6% of eligible compensation. Employees may participate in
the plans immediately and certain employees are not eligible for matching contributions until after a 90-day waiting period.
During the years ended December 31, 2021, 2020 and 2019, aggregate matching contributions made by us were $4.0 million,
$4.2 million and $4.7 million.
Note 16 – Segments
In conjunction with the divestiture of our Stagecoach Gas equity method investment as discussed in Note 6 and the definitive
merger agreement we entered into with Oasis Midstream as discussed in Note 20, 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 operations (includes our Arrow and Jackalope operations); (ii) gathering and processing south operations (includes our
Marcellus and Barnett operations and our Crestwood Permian Basin Holdings LLC equity method investment); and (iii) storage
and logistics operations (includes our crude oil, NGL and natural gas storage and logistics operations, 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. The financial results of our operations described above
are now reflected in the new respective segments for all periods presented. Our corporate operations include all general and
administrative expenses that are not allocated to our reportable segments.
Below is a description of our operating and reporting segments.
•
•
•
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.
We assess the performance of our operating segments based on EBITDA, which is defined as income before income taxes, plus
debt-related costs (net interest and debt expense and gain (loss) on modification/extinguishment of debt) and depreciation,
amortization and accretion expense.
Below is a reconciliation of CEQP’s and CMLP’s net income (loss) to EBITDA (in millions):
Net income (loss)
Add:
CEQP
CMLP
Year Ended December 31,
Year Ended December 31,
2021
2020
2019
2021
2020
2019
$
(37.4) $
(15.3) $ 319.9
$
(44.0) $
(23.4) $ 310.6
Interest and debt expense, net
132.1
133.6
115.4
132.1
133.6
115.4
(Gain) loss on modification/extinguishment of debt
Provision (benefit) for income taxes
Depreciation, amortization and accretion
7.5
0.2
244.2
(0.1)
0.4
237.4
—
0.3
7.5
0.1
(0.1)
(0.1)
—
0.3
195.8
258.4
251.5
209.9
EBITDA
$ 346.6 $ 356.0 $ 631.4
$ 354.1 $ 361.5 $ 636.2
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The following tables summarize CEQP’s and CMLP’s reportable segment data for the years ended December 31, 2021, 2020
and 2019 (in millions). Intersegment revenues included in the following tables are accounted for as arms-length transactions
that apply our revenue recognition policy described in Note 2. Included in earnings (loss) from unconsolidated affiliates, net
reflected in the tables below was approximately $187.4 million, $42.9 million and $42.1 million of our proportionate share of
interest expense, depreciation and amortization expense, goodwill impairments and gains (losses) on long-lived assets, net
recorded by our equity investments for the years ended December 31, 2021, 2020 and 2019, respectively.
Segment EBITDA Information
—
3,843.9
121.0
90.2
(39.4)
(120.4)
354.1
7.4
(0.2)
0.1
Crestwood Midstream
Revenues
Intersegment revenues
Costs of product/services sold
Operations and maintenance expense
General and administrative expense
Gain (loss) on long-lived assets, net
Earnings (loss) from unconsolidated affiliates, net
Year Ended December 31, 2021
Gathering and
Processing
North
Gathering and
Processing
South
Storage and
Logistics
Corporate
Total
$
574.7 $
105.9 $
3,888.4 $
— $
4,569.0
459.3
553.2
51.1
—
0.4
—
—
0.9
22.9
—
(40.6)
9.6
(459.3)
3,289.8
47.0
—
0.7
(130.0)
—
—
—
90.2
0.1
—
Crestwood Midstream EBITDA
$
430.1 $
51.1 $
(37.0) $
(90.1) $
Crestwood Equity
General and administrative expense
Loss on long-lived assets, net
Other income
—
—
—
—
—
—
—
—
—
7.4
(0.2)
0.1
Crestwood Equity EBITDA
$
430.1 $
51.1 $
(37.0) $
(97.6) $
346.6
Year Ended December 31, 2020
Gathering and
Processing
North
Gathering and
Processing
South
Storage and
Logistics
Corporate
Total
Crestwood Midstream
Revenues
Intersegment revenues
Costs of product/services sold
Operations and maintenance expense
General and administrative expense
Gain (loss) on long-lived assets, net
Goodwill impairment
Earnings (loss) from unconsolidated affiliates, net
$
510.4 $
160.5
261.0
55.7
—
(3.8)
(80.3)
—
Crestwood Midstream EBITDA
$
270.1 $
Crestwood Equity
General and administrative expense
Other expense
—
—
121.0 $
(0.7)
0.5
1,622.9 $
(159.8)
1,339.0
29.2
—
46.9
—
(20.0)
(2.4)
—
33.5
—
(1.0)
69.6 $
—
—
— $
—
—
2,254.3
—
1,600.5
—
86.7
0.2
—
—
131.8
86.7
(26.0)
(80.3)
32.5
361.5
4.8
(0.7)
108.3 $
(86.5) $
—
—
4.8
(0.7)
Crestwood Equity EBITDA
$
270.1 $
69.6 $
108.3 $
(92.0) $
356.0
121
—
2,544.9
138.8
98.2
(6.2)
209.4
32.8
0.2
636.2
5.2
0.4
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Crestwood Midstream
Revenues
Intersegment revenues
Costs of product/services sold
Operations and maintenance expense
General and administrative expense
Gain (loss) on long-lived assets, net
Gain on acquisition
Earnings (loss) from unconsolidated affiliates, net
Other income, net
Year Ended December 31, 2019
Gathering and
Processing
North
Gathering and
Processing
South
Storage and
Logistics
Corporate
Total
$
686.9 $
148.9 $
2,346.1 $
— $
3,181.9
174.9
524.0
60.8
—
(4.2)
209.4
3.7
—
0.1
2.1
37.9
—
(2.0)
—
(5.8)
—
(175.0)
2,018.8
40.1
—
(0.2)
—
34.9
—
—
—
—
98.2
0.2
—
—
0.2
Crestwood Midstream EBITDA
$
485.9 $
101.2 $
146.9 $
(97.8) $
Crestwood Equity
General and administrative expense
Other income
—
—
—
—
—
—
5.2
0.4
Crestwood Equity EBITDA
$
485.9 $
101.2 $
146.9 $
(102.6) $
631.4
Other Segment Information
Total Assets
Gathering and Processing North
Gathering and Processing South
Storage and Logistics
Corporate
Total assets
CEQP
CMLP
Year Ended December 31,
Year Ended December 31,
2021
2020
2021
2020
$
$
2,408.0 $
886.5
1,125.1
26.1
4,445.7 $
2,480.4
984.2
1,749.6
29.5
5,243.7
$
$
2,408.0 $
1,017.4
1,125.1
20.7
4,571.2 $
2,480.4
1,129.3
1,749.6
26.2
5,385.5
Year Ended December 31,
2021
2020
2019
Purchases of property, plant and equipment
Crestwood Midstream
Gathering and Processing North
Gathering and Processing South
Storage and Logistics
Corporate
$
Total Crestwood Midstream purchases of property, plant and equipment $
Crestwood Equity
Corporate
Total Crestwood Equity purchases of property, plant and equipment
$
Major Customers
66.1 $
7.9
6.6
0.7
81.3 $
1.9
83.2 $
156.5 $
3.2
7.5
1.1
168.3 $
—
168.3 $
434.4
13.3
5.9
1.9
455.5
—
455.5
No customer accounted for 10% or more of our total consolidated revenues for the years ended December 31, 2021 and 2020 at
CEQP or CMLP. For the year ended December 31, 2019, revenues from British Petroleum and its affiliates of approximately
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$333.9 million (reflected primarily in our storage and logistics segment) accounted for approximately 10% of our total
consolidated revenues at CEQP and CMLP.
Note 17 - Revenues
Contract Assets and Contract Liabilities
Our contract assets and contract liabilities are reported in a net position on a contract-by-contract basis at the end of each
reporting period. Our receivables related to our revenue contracts accounted for under Topic 606 totaled $331.0 million and
$219.9 million at December 31, 2021 and 2020, and are included in accounts receivable on our consolidated balance sheets.
Our contract assets are included in other non-current assets on our consolidated balance sheets. Our contract liabilities primarily
consist of current and non-current deferred revenues. On our consolidated balance sheets, our current deferred revenues are
included in accrued expenses and other liabilities and our non-current deferred revenues are included in other long-term
liabilities. The majority of revenues associated with our deferred revenues is expected to be recognized as the performance
obligations under the related contracts are satisfied over the next 15 years.
The following table summarizes our contract assets and contract liabilities (in millions):
Contract assets (non-current)
Contract liabilities (current)(1)
Contract liabilities (non-current)(1)
December 31,
2021
2020
$
$
$
1.3 $
10.7 $
187.1 $
1.0
10.3
172.2
(1) During the year ended December 31, 2021, we recognized revenues of approximately $14.0 million that were previously included in contract liabilities at
December 31, 2020. The remaining change in our contract liabilities during the year ended December 31, 2021 related to capital reimbursements
associated with our revenue contracts and revenue deferrals associated with our contracts with increasing (decreasing) rates.
The following table summarizes the transaction price allocated to our remaining performance obligations under certain
contracts that have not been recognized as of December 31, 2021 (in millions):
2022
2023
2024
2025
Total
$
$
72.7
52.6
31.7
0.1
157.1
Our remaining performance obligations presented in the table above exclude estimates of variable rate escalation clauses in our
contracts with customers, and is generally limited to fixed-fee and percentage-of-proceeds service contracts which have fixed
pricing and minimum volume terms and conditions. Our remaining performance obligations generally exclude, based on the
following practical expedients that we elected to apply, disclosures for (i) variable consideration allocated to a wholly-
unsatisfied promise to transfer a distinct service that forms part of the identified single performance obligation; (ii) unsatisfied
performance obligations where the contract term is one year or less; and (iii) contracts for which we recognize revenues as
amounts are invoiced.
Disaggregation of Revenues
The following tables summarize our revenues from contracts with customers disaggregated by type of product/service sold and
by commodity type for each of our segments for the years ended December 31, 2021, 2020 and 2019 (in millions). In addition,
the revenues from contracts with customers are presented in the three operating and reporting segments that are further
discussed in Note 16 for all periods presented. We believe this summary best depicts how the nature, amount, timing and
uncertainty of our revenues and cash flows are affected by economic factors. Our non-Topic 606 revenues presented in the
tables below primarily represent revenues related to our commodity-based derivatives.
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Table of Contents
Topic 606 revenues
Gathering
Natural gas
Crude oil
Water
Processing
Natural gas
Compression
Natural gas
Storage
Crude oil
NGLs
Pipeline
Crude oil
NGLs
Transportation
Crude oil
NGLs
Rail Loading
Crude oil
Product Sales
Natural gas
Crude oil
NGLs
Other
Total Topic 606 revenues
Non-Topic 606 revenues
Total revenues
$
Year Ended December 31, 2021
Gathering and
Processing
North
Gathering and
Processing
South
Storage and
Logistics
Intersegment
Elimination
Total
$
56.3 $
73.1
94.0
24.4
—
0.3
—
—
—
2.7
—
—
83.2 $
—
—
5.0
17.1
—
—
—
—
—
—
—
— $
—
—
—
—
0.5
11.5
2.6
0.2
—
17.3
4.6
— $
—
—
—
—
(0.3)
—
—
—
(0.1)
—
—
139.5
73.1
94.0
29.4
17.1
0.5
11.5
2.6
0.2
2.6
17.3
4.6
327.1
1,556.6
1,800.8
1.7
4,078.6
490.4
4,569.0
171.4
401.5
209.4
—
1,033.1
0.9
1,034.0 $
0.6
—
—
—
105.9
—
105.9 $
326.2
1,237.7
1,796.6
1.7
3,398.9
489.5
3,888.4 $
(171.1)
(82.6)
(205.2)
—
(459.3)
—
(459.3) $
124
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Topic 606 revenues
Gathering
Natural gas
Crude oil
Water
Processing
Natural gas
Compression
Natural gas
Storage
Crude oil
NGLs
Pipeline
Crude oil
NGLs
Transportation
Crude oil
NGLs
Rail Loading
Crude oil
Product Sales
Natural gas
Crude oil
NGLs
Other
Total Topic 606 revenues
Non-Topic 606 revenues
Total revenues
Year Ended December 31, 2020
Gathering and
Processing
North
Gathering and
Processing
South
Storage and
Logistics
Intersegment
Elimination
Total
$
53.4 $
95.3
92.6
22.4
—
1.1
—
—
—
6.2
—
—
53.7
292.2
54.0
—
670.9
—
670.9
87.2 $
—
—
9.5
23.9
—
—
—
—
—
—
—
(0.3)
—
—
—
120.3
—
120.3
— $
—
—
—
—
1.9
13.1
4.1
0.3
1.9
10.9
7.4
90.9
660.7
614.2
1.5
1,406.9
216.0
1,622.9
— $
—
—
—
—
(0.3)
—
—
—
(0.1)
—
—
(52.8)
(53.0)
(53.6)
—
(159.8)
—
(159.8)
140.6
95.3
92.6
31.9
23.9
2.7
13.1
4.1
0.3
8.0
10.9
7.4
91.5
899.9
614.6
1.5
2,038.3
216.0
2,254.3
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Topic 606 revenues
Gathering
Natural gas
Crude oil
Water
Processing
Natural gas
NGLs
Compression
Natural gas
Storage
Crude oil
NGLs
Pipeline
Crude oil
Transportation
Crude oil
NGLs
Water
Rail Loading
Crude oil
Product Sales
Natural gas
Crude oil
NGLs
Other
Total Topic 606 revenues
Non-Topic 606 revenues
Total revenues
$
Note 18 - Income Taxes
Year Ended December 31, 2019
Gathering and
Processing
North
Gathering and
Processing
South
Storage and
Logistics
Intersegment
Elimination
Total
$
51.2 $
75.0
79.6
18.9
—
—
1.9
—
—
7.0
—
—
—
112.0 $
—
—
— $
—
—
10.0
—
24.9
—
—
—
—
—
—
—
—
—
—
3.5
6.3
5.2
5.8
11.7
0.2
11.0
— $
—
—
—
—
—
(0.4)
—
—
(0.1)
—
—
—
55.6
532.1
40.5
—
861.8
—
861.8 $
1.2
—
0.9
—
149.0
—
149.0 $
72.3
1,315.6
659.3
1.9
2,092.8
253.3
2,346.1 $
(33.4)
(121.1)
(20.0)
—
(175.0)
—
(175.0) $
163.2
75.0
79.6
28.9
—
24.9
5.0
6.3
5.2
12.7
11.7
0.2
11.0
95.7
1,726.6
680.7
1.9
2,928.6
253.3
3,181.9
The (provision) benefit for income taxes for the years ended December 31, 2021, 2020, and 2019 consisted of the following (in
millions):
CEQP
CMLP
Year Ended December 31,
2020
2019
2021
Year Ended December 31,
2020
2019
2021
Current:
Federal
State
Total current
Deferred:
Federal
State
Total deferred
$
(0.4) $
(0.2) $
(0.1) $
— $
0.1 $
(0.2)
(0.6)
0.3
0.1
0.4
(0.1)
(0.3)
(0.1)
—
(0.1)
(0.4) $
(0.2)
(0.3)
0.1
(0.1)
—
(0.1)
(0.1)
—
—
—
—
0.1
—
—
—
(0.3) $
(0.1) $
0.1 $
0.1
(0.2)
(0.1)
—
(0.2)
(0.2)
(0.3)
(Provision) benefit for income taxes
$
(0.2) $
The effective rate differs from the statutory rate for the years ended December 31, 2021, 2020 and 2019, primarily due to the
partnerships not being treated as a corporation for federal income tax purposes as discussed in Note 2.
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Table of Contents
Deferred income taxes related to the operations of CEQP’s wholly-owned taxable subsidiaries, IPCH Acquisition Corp. and
Crestwood Gas Services GP LLC, and the impact of Texas Margin tax on our operations, and reflects the net tax effects of
temporary differences between the carrying amounts of assets and liabilities for financial reporting purposes and the amounts
used for income tax purposes.
Components of our deferred income taxes at December 31, 2021 and 2020 are as follows (in millions).
Total deferred tax asset(1)
Total deferred tax liability(1)
Net deferred tax liability
(1) Relates to the basis difference in the stock of a company.
CEQP
December 31,
CMLP
December 31,
2021
2020
2021
2020
$
$
0.2 $
(2.5)
(2.3) $
0.2 $
(2.9)
(2.7) $
— $
(0.8)
(0.8) $
—
(0.7)
(0.7)
Uncertain Tax Positions. We evaluate the uncertainty in tax positions taken or expected to be taken in the course of preparing
our consolidated financial statements to determine whether the tax positions are more likely than not of being sustained by the
applicable tax authority. Such tax positions, if any, would be recorded as a tax benefit or expense in the current year. We
believe that there were no uncertain tax positions that would impact our results of operations for the years ended December 31,
2021, 2020 and 2019 and that no provision for income tax was required for these consolidated financial statements. However,
our conclusions regarding the evaluation of uncertain tax positions are subject to review and may change based on factors
including, but not limited to, ongoing analyses of tax laws, regulations and interpretations thereof.
Note 19 – Related Party Transactions
We enter into transactions with our affiliates within the ordinary course of business, including product purchases, marketing
services and various operating agreements, including operating leases. We also enter into transactions with our affiliates related
to services provided on our expansion projects.
Prior to August 2021, Crestwood Holdings indirectly owned our general partner and the affiliates of Crestwood Holdings and
its owners were considered CEQP’s and CMLP’s related parties. With the completion of the Crestwood Holdings Transactions
in August 2021, Crestwood Holdings and its affiliates are no longer considered related parties of CEQP and CMLP. During the
years ended December 31, 2021, 2020, 2019 and we paid approximately $0.6 million, $3.5 million, and $9.9 million of capital
expenditures to Applied Consultants, Inc., an affiliate of Crestwood Holdings.
Below is a discussion of certain of our related party services and agreements.
Shared Services. CMLP shares common management, general and administrative and overhead costs with CEQP, and as such,
CMLP allocates a portion of its costs to CEQP. CEQP grants long-term incentive awards under the Crestwood LTIP as
discussed in Note 13 and, as such, CEQP allocates certain of its unit-based compensation costs to CMLP. Prior to the
Crestwood Holdings Transactions as discussed in Note 1, Crestwood Holdings allocated its unit-based compensation charges to
CEQP and CMLP.
Stagecoach Gas Management Agreement. Prior to the sale of our equity interest in Stagecoach Gas as further discussed in
Note 6, Crestwood Midstream Operations, LLC (Crestwood Midstream Operations), our wholly-owned subsidiary, provided
management and operating services to Stagecoach Gas under a management agreement pursuant to which we operated and
maintained Stagecoach Gas’s facilities. Reimbursements received from Stagecoach Gas under this agreement were reflected as
a reduction of operations and maintenance expenses in our consolidated statements of operations.
Tres Holdings Operating Agreement. CMLP Tres Manager, LLC, a consolidated subsidiary of Crestwood Midstream, entered
into an operating agreement with Tres Holdings, pursuant to which we operate and maintain their facilities as well as provide
certain administrative and other general services identified in the agreement. Under the operating agreement, Tres Holdings
reimburses us for all costs incurred on its behalf. These reimbursements are reflected as a reduction of operations and
maintenance expenses in our consolidated statements of operations.
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Crestwood Permian Operating Agreement. Crestwood Midstream Operations entered into an operating agreement with
Crestwood Permian, pursuant to which we provide operating services for Crestwood Permian’s facilities, as well as certain
administrative and other general services identified in the agreement. Under the operating agreement, Crestwood Permian
reimburses us for all costs incurred on its behalf. These reimbursements are reflected as a reduction of operations and
maintenance expenses in our consolidated statements of operations.
Jackalope Marketing Services Agreement. Prior to the acquisition of the remaining interest in Jackalope as further discussed
in Note 3, Crestwood Niobrara provided marketing services to Jackalope as well as certain administrative and other general
services identified under a marketing services agreement. Under this marketing services agreement, Jackalope reimbursed us for
all costs incurred on its behalf. These reimbursements are reflected as a reduction of operations and maintenance expenses in
our consolidated statements of operations.
The following table shows transactions with our affiliates which are reflected in our consolidated statements of operations for
the years December 31, 2021, 2020 and 2019 (in millions):
Revenues at CEQP and CMLP(1)
Costs of product/services sold at CEQP and CMLP(2)
Operations and maintenance expenses at CEQP and CMLP charged to our
unconsolidated affiliates(3)
General and administrative expenses charged by CEQP to CMLP, net(4)
General and administrative expenses at CEQP charged to (from) Crestwood
Holdings, net(5)
$
$
$
$
$
Year Ended December 31,
2021
2020
2019
27.2 $
136.8 $
22.2 $
35.5 $
27.8 $
21.0 $
21.8 $
31.1 $
2.9
45.4
25.9
41.4
4.8 $
6.5 $
(0.6)
(1)
(2)
Includes (i) $26.2 million, $27.8 million and $1.0 million during the years ended December 31, 2021, 2020 and 2019 related to the sale of NGLs to a
subsidiary of Crestwood Permian; (ii) $1.0 million during the year ended December 31, 2021 related to a compressor lease with a subsidiary of Crestwood
Permian (iii) $1.2 million during the year ended December 31, 2019 related to the sale of natural gas to a subsidiary of Stagecoach Gas: and (iv) $0.7
million during the year ended December 31, 2019 related to the sale of NGLs to our affiliate, Westlake Chemical Corporation.
Includes (i) $110.7 million, $20.0 million and $19.0 million during the years ended December 31, 2021, 2020 and 2019 related to purchases of natural gas
and NGLs from a subsidiary of Crestwood Permian; (ii) $11.6 million and $0.6 million during the years ended December 31, 2021 and 2020 related to
purchases of natural gas from a subsidiary of Tres Holdings; (iii) $14.5 million, $0.4 million and $23.9 million during the years ended December 31,
2021, 2020 and 2019 related to purchases of NGLs from Ascent Resources - Utica, LLC (Ascent); (iv) $0.2 million during the year ended December 31,
2019 related to purchases of NGLs from Blue Racer Midstream, LLC (Blue Racer); and (v) $2.3 million during the year ended December 31, 2019 related
to purchases of natural gas from a subsidiary of Stagecoach Gas. Ascent and Blue Racer are affiliates of Crestwood Holdings for the respective periods
presented.
(3) We have operating agreements with certain of our unconsolidated affiliates pursuant to which we charge them operations and maintenance expenses in
accordance with their respective agreements described above. During the year ended December 31, 2021, we charged $3.4 million to Stagecoach Gas,
$4.9 million to Tres Holdings, and $13.9 million to Crestwood Permian under these agreements. During the year ended December 31, 2020, we charged
$6.6 million to Stagecoach Gas, $4.1 million to Tres Holdings and $11.1 million to Crestwood Permian under these agreements. During the year ended
December 31, 2019, we charged $7.5 million to Stagecoach Gas, $4.4 million to Tres Holdings, $13.5 million to Crestwood Permian and $0.5 million to
Jackalope under these agreements.
(4)
(5)
Includes $39.5 million, $35.1 million and $45.1 million of unit-based compensation charges allocated from CEQP to CMLP during the years ended
December 31, 2021, 2020 and 2019. In addition, includes $4.0 million, $4.0 million and $3.7 million of CMLP’s general and administrative costs
allocated to CEQP during the years ended December 31, 2021, 2020 and 2019.
Includes a $4.6 million and $4.4 million reduction of unit-based compensation charges allocated from Crestwood Holdings to CEQP and CMLP during
the years ended December 31, 2021 and 2020 and $1.9 million of unit-based compensation charges allocated from Crestwood Holdings to CEQP and
CMLP during the year ended December 31, 2019. CEQP allocates a portion of its general and administrative costs to Crestwood Holdings and during the
years ended December 31, 2021, 2020 and 2019, CEQP allocated $0.2 million, $2.1 million and $1.3 million of its general and administrative costs to
Crestwood Holdings.
The following table shows accounts receivable and accounts payable from our affiliates as of December 31, 2021 and 2020 (in
millions):
Accounts receivable at CEQP and CMLP
Accounts payable at CEQP
Accounts payable at CMLP
128
December 31,
2021
2020
$
$
$
8.2 $
12.0 $
12.0 $
2.5
7.5
5.0
Table of Contents
Note 20 - Subsequent Event
On October 25, 2021, we entered into a merger agreement to acquire Oasis Midstream in an equity and cash transaction (the
Merger). Oasis Midstream is a master limited partnership which operates a diversified portfolio of midstream assets in located
in the Williston and Delaware Basins and its operations include natural gas services (gathering, compression, processing and
gas lift supply) crude oil services (gathering, terminalling and transportation) and water services (gathering and disposal of
produced and flowback water and freshwater distribution).
On February 1, 2022, we completed the merger with Oasis Midstream, which was valued at approximately $1.8 billion.
Pursuant to the merger agreement, 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. .
We will account for the Merger as a business combination using the acquisition method of accounting. We are completing our
analysis of the purchase price consideration and estimating the fair value of assets acquired and liabilities assumed in
connection with the Merger, which is primarily comprised of property, plant and equipment, intangible assets, goodwill and
other long-term debt, however, due to the timing of the Merger, we are unable to provide amounts recognized as of the
acquisition date for these major classes of assets and liabilities acquired. During the year ended December 31, 2021, we
recognized approximately $2.9 million of transaction costs related to the Merger, which are included in general and
administrative expenses in our consolidated statements of operations.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this
report to be signed on its behalf by the undersigned, thereunto duly authorized.
CRESTWOOD EQUITY PARTNERS LP
By Crestwood Equity GP, LLC
(its general partner)
CRESTWOOD MIDSTREAM PARTNERS LP
By Crestwood Midstream GP LLC
(its general partner)
Dated: February 25, 2022
By /s/ ROBERT G. PHILLIPS
Robert G. Phillips
Founder, Chairman, Chief Executive Officer and Director
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following
officers of Crestwood Equity GP, LLC, as general partner of Crestwood Equity Partners LP, and Crestwood Midstream GP
LLC, as general partner of Crestwood Midstream Partners LP, and the following directors of Crestwood Equity GP LLC in the
capacities and on the dates indicated.
Date
February 25, 2022
February 25, 2022
February 25, 2022
February 25, 2022
February 25, 2022
February 25, 2022
February 25, 2022
February 25, 2022
February 25, 2022
February 25, 2022
February 25, 2022
February 25, 2022
Signature and Title
/s/ ROBERT G. PHILLIPS
Robert G. Phillips,
Founder, Chairman, Chief Executive Officer and Director
(Principal Executive Officer)
/s/ ROBERT T. HALPIN
Robert T. Halpin,
President and Chief Financial Officer
(Principal Financial Officer)
/s/ STEVEN M. DOUGHERTY
Steven M. Dougherty,
Executive Vice President and Chief Accounting Officer
(Principal Accounting Officer)
/s/ WARREN H. GFELLER
Warren H. Gfeller, Director
/s/ JOHN JACOBI
John Jacobi, Director
/s/ JANEEN S. JUDAH
Janeen S. Judah, Director
/s/ JOHN LANCASTER JR.
John Lancaster Jr., Director
/s/ DAVID LUMPKINS
David Lumpkins, Director
/s/ ANGELA A. MINAS
Angela A. Minas, Director
/s/ JOHN J. SHERMAN
John J. Sherman, Director
/s/ FRANCES M. VALLEJO
Frances M. Vallejo, Director
/s/ CLAY C. WILLIAMS
Clay C. Williams, Director
130
Schedule I
December 31,
2021
2020
$
0.2 $
0.4
0.6
2.5
0.2
—
0.2
0.9
1,100.1
2.1
1,655.7
2.1
$
1,105.3 $
1,658.9
$
0.1 $
1.0
1.1
4.6
0.1
1.9
2.0
1.5
1,099.6
$
1,105.3 $
1,655.4
1,658.9
Table of Contents
Assets
Current assets:
Cash
Prepaid expenses and other current assets
Total current assets
Property, plant and equipment, net
Investments in subsidiaries
Other assets
Total assets
Liabilities and partners’ capital
Current liabilities:
Accounts payable
Accrued expenses
Total current liabilities
Other long-term liabilities
Total partners’ capital
Total liabilities and partners’ capital
Crestwood Equity Partners LP
Parent Only
Condensed Balance Sheets
(in millions)
See accompanying notes.
131
Table of Contents
Crestwood Equity Partners LP
Parent Only
Condensed Statements of Comprehensive Income
(in millions)
Schedule I
Year Ended December 31,
2021
2020
2019
Revenues
Expenses
Operating loss
Equity in net income (loss) of subsidiaries
Other income (expense), net
Net income (loss) attributable to Crestwood Equity Partners LP
Other comprehensive income
$
— $
7.7
(7.7)
(70.9)
0.1
(78.5)
— $
4.9
(4.9)
(50.5)
(0.7)
(56.1)
Change in fair value of Suburban Propane Partners, L.P. units
—
—
Comprehensive income (loss) attributable to Crestwood Equity Partners LP $
(78.5) $
(56.1) $
—
5.3
(5.3)
290.0
0.4
285.1
0.3
285.4
See accompanying notes.
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Table of Contents
Crestwood Equity Partners LP
Parent Only
Condensed Statements of Cash Flows
(in millions)
Schedule I
Cash flows from operating activities
Year Ended December 31,
2021
2020
2019
$
(5.5) $
(9.4) $
(3.7)
Cash flows from investing activities
507.8
242.6
235.8
Cash flows from financing activities:
Payments for Crestwood Holdings Transactions
Distributions paid to partners
Change in intercompany balances
Net cash used in financing activities
Net change in cash
Cash at beginning of period
Cash at end of period
(275.6)
(224.4)
(2.3)
(502.3)
—
—
(242.8)
(232.5)
9.6
0.4
(233.2)
(232.1)
—
0.2
—
0.2
$
0.2 $
0.2 $
—
0.2
0.2
See accompanying notes.
133
Table of Contents
Crestwood Equity Partners LP
Parent Only
Notes to Condensed Financial Statements
Schedule I
Note 1. Basis of Presentation
In the parent-only financial statements, our investment in subsidiaries is stated at cost plus equity in undistributed earnings of
subsidiaries since the date of acquisition. Our share of net income of our unconsolidated subsidiaries is included in consolidated
income using the equity method. The parent-only financial statements should be read in conjunction with our consolidated
financial statements.
Note 2. Distributions
During the years ended December 31, 2021, 2020 and 2019, we received cash distributions from Crestwood Midstream Partners
LP of approximately $509.7 million, $242.6 million and $235.8 million.
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Table of Contents
Crestwood Equity Partners LP
Crestwood Midstream Partners LP
Valuation and Qualifying Accounts
For the Years Ended December 31, 2021, 2020 and 2019
(in millions)
Schedule II
Allowance for doubtful accounts
2021
2020
2019
Balance at
beginning
of period
Charged
to costs and
expenses
Other
additions(1)
Deductions
(write-offs)
Balance
at end
of period
$
$
$
0.9 $
0.3 $
0.3 $
0.6 $
0.5 $
0.1 $
— $
0.7 $
— $
(0.9) $
(0.6) $
(0.1) $
0.6
0.9
0.3
(1) Amount represents the cumulative effect of adopting the provisions of Topic 326 on January 1, 2020, which is further discussed in Note 2.
135