Document/ExhibitDescriptionPagesSize 1: 10-K Annual Report HTML 2.31M
2: EX-4.23 Instrument Defining the Rights of Security Holders HTML 90K
3: EX-21.1 Subsidiaries List HTML 43K
4: EX-22.1 Published Report re: Matters Submitted to a Vote HTML 41K
of Security Holders
5: EX-23.1 Consent of Expert or Counsel HTML 34K
6: EX-23.2 Consent of Expert or Counsel HTML 34K
15: EX-99.1 Miscellaneous Exhibit HTML 141K
7: EX-31.1 Certification -- §302 - SOA'02 HTML 38K
8: EX-31.2 Certification -- §302 - SOA'02 HTML 38K
9: EX-31.3 Certification -- §302 - SOA'02 HTML 38K
10: EX-31.4 Certification -- §302 - SOA'02 HTML 38K
11: EX-32.1 Certification -- §906 - SOA'02 HTML 35K
12: EX-32.2 Certification -- §906 - SOA'02 HTML 35K
13: EX-32.3 Certification -- §906 - SOA'02 HTML 35K
14: EX-32.4 Certification -- §906 - SOA'02 HTML 35K
21: R1 Cover Page HTML 116K
22: R2 Audit Information HTML 41K
23: R3 Consolidated Balance Sheets HTML 160K
24: R4 Consolidated Balance Sheets (Parenthetical) HTML 44K
25: R5 Consolidated Statements of Operations HTML 167K
26: R6 Consolidated Statements of Comprehensive Income HTML 60K
27: R7 Consolidated Statement of Partners' Capital HTML 111K
28: R8 Consolidated Statements of Cash Flows HTML 170K
29: R9 Organization and Description of Business HTML 41K
30: R10 Basis of Presentation and Summary of Significant HTML 101K
Accounting Policies
31: R11 Acquisitions and Divestitures HTML 56K
32: R12 Certain Balance Sheet Information HTML 117K
33: R13 Asset Retirement Obligations HTML 48K
34: R14 Investments in Unconsolidated Affiliates HTML 140K
35: R15 Risk Management HTML 63K
36: R16 Fair Value Measurements HTML 117K
37: R17 Long-Term Debt HTML 67K
38: R18 Commitments and Contingencies HTML 55K
39: R19 Leases HTML 196K
40: R20 Partners' Capital and Non-Controlling Partner HTML 86K
41: R21 Equity Plans HTML 79K
42: R22 Earnings Per Limited Partner Unit HTML 70K
43: R23 Employee Benefit Plan HTML 36K
44: R24 Segments HTML 207K
45: R25 Revenues HTML 223K
46: R26 Income Taxes HTML 80K
47: R27 Related Party Transactions HTML 66K
48: R28 Subsequent Events HTML 38K
49: R29 Schedule I - Crestwood Equity Partners LP - Parent HTML 97K
Only
50: R30 Schedule II - Crestwood Equity Parnters LP - HTML 50K
Valuation and Qualifying Accounts
51: R31 Basis of Presentation and Summary of Significant HTML 125K
Accounting Policies (Policies)
52: R32 Basis of Presentation and Summary of Significant HTML 85K
Accounting Policies (Tables)
53: R33 Acquisition and Divestiture (Tables) HTML 53K
54: R34 Certain Balance Sheet Information (Tables) HTML 126K
55: R35 Asset Retirement Obligations (Tables) HTML 47K
56: R36 Investments in Unconsolidated Affiliates (Tables) HTML 138K
57: R37 Risk Management (Tables) HTML 62K
58: R38 Fair Value Measurements (Tables) HTML 113K
59: R39 Long-Term Debt (Tables) HTML 59K
60: R40 Commitments and Contingencies (Tables) HTML 127K
61: R41 Leases (Tables) HTML 137K
62: R42 Partners' Capital and Non-Controlling Partner HTML 75K
(Tables)
63: R43 Equity Plans (Tables) HTML 68K
64: R44 Earnings Per Limited Partner Unit (Tables) HTML 68K
65: R45 Segments (Tables) HTML 200K
66: R46 Revenues (Tables) HTML 222K
67: R47 Income Taxes (Tables) HTML 78K
68: R48 Related Party Transactions (Tables) HTML 61K
69: R49 Organization and Description of Business (Details) HTML 55K
70: R50 Basis of Presentation and Summary of Significant HTML 84K
Accounting Policies (Narrative) (Details)
71: R51 Basis of Presentation and Summary of Significant HTML 39K
Accounting Policies (Inventory) (Details)
72: R52 Basis of Presentation and Summary of Significant HTML 51K
Accounting Policies (Estimated Useful Lives Of
Property, Plant And Equipment) (Details)
73: R53 Basis of Presentation and Summary of Significant HTML 41K
Accounting Policies (Estimated Economic Lives Of
Intangible Assets) (Details)
74: R54 Basis of Presentation and Summary of Significant HTML 50K
Accounting Policies (Goodwill, by Reporting Unit)
(Details)
75: R55 Acquisitions and Divestitures (Schedules) HTML 75K
(Details)
76: R56 Acquisitions and Divestitures (Narrative) HTML 130K
(Details)
77: R57 Certain Balance Sheet Information (Property, Plant HTML 77K
And Equipment) (Details)
78: R58 Certain Balance Sheet Information (Intangible HTML 58K
Assets) (Details)
79: R59 Certain Balance Sheet Information (Amortization HTML 44K
and Interest Expense, Fiscal Year Maturity)
(Details)
80: R60 Certain Balance Sheet Information (Accrued HTML 63K
Expenses and Other Liabilities) (Details)
81: R61 Certain Balance Sheet Information (Other Long-Term HTML 46K
Liabilities) (Details)
82: R62 Asset Retirement Obligations (Details) HTML 48K
83: R63 Investments in Unconsolidated Affiliates HTML 167K
(Schedule) (Details)
84: R64 Investments in Unconsolidated Affiliates HTML 135K
(Narrative) (Details)
85: R65 Risk Management (Notional Amounts and Terms of HTML 68K
Company's Derivative Financial Instruments)
(Details)
86: R66 Risk Management (Narrative) (Details) HTML 39K
87: R67 Fair Value Measurements (Assets And Liabilities HTML 79K
Measured At Fair Value On Recurring Basis)
(Details)
88: R68 Fair Value Measurements (Schedule of Carrying HTML 51K
Values and Estimated Fair Values of Senior Notes)
(Details)
89: R69 Long-Term Debt (Components Of Long-Term Debt) HTML 65K
(Details)
90: R70 Long-Term Debt (Narrative) (Details) HTML 161K
91: R71 Long-Term Debt (Maturities of Long Term Debt) HTML 55K
(Details)
92: R72 Commitments and Contingencies (Narrative) HTML 68K
(Details)
93: R73 Commitments and Contingencies Leases (Details) HTML 157K
94: R74 Leases - Balance Sheet Information (Details) HTML 67K
95: R75 Leases - Narrative (Details) HTML 38K
96: R76 Leases - Weighted Average Remaining Lease Term and HTML 55K
Discount (Details)
97: R77 Leases - Sublease Income (Details) HTML 62K
98: R78 Leases - Supplemental Cash Flow Information HTML 47K
(Details)
99: R79 Leases - Future Minimum Lease Liabilities HTML 92K
(Details)
100: R80 Partners' Capital and Non-Controlling Partner HTML 35K
(Schedule of Issuance of Units) (Details)
101: R81 Partners' Capital and Non-Controlling Partner HTML 194K
(Narrative) (Details)
102: R82 Partners' Capital and Non-Controlling Partner HTML 58K
(Schedule of Partnership Distributions) (Details)
103: R83 Partners' Capital Net Income (Loss) Attributable HTML 39K
to NonControlling Partners (Details)
104: R84 Partners' Capital Rollforward of non-controlling HTML 51K
interest (Details)
105: R85 Equity Plans (Schedule of Phantom and Restricted HTML 67K
Unit Activity) (Details)
106: R86 Equity Plans (Narrative) (Details) HTML 79K
107: R87 Earnings Per Limited Partner Unit (Schedule of HTML 76K
Reconciliation of Earnings Per Share) (Details)
108: R88 Employee Benefit Plan (Details) HTML 45K
109: R89 Segments (Narrative) (Details) HTML 53K
110: R90 Segments (Reconciliation of Net Income (Loss) to HTML 63K
EBITDA) (Details)
111: R91 Segments (Summary Of Segment Information) HTML 147K
(Details)
112: R92 Revenues (Details) HTML 37K
113: R93 Revenues (Contract Assets and Liabilities) HTML 43K
(Details)
114: R94 Revenues (Remaining Performance Obligations) HTML 53K
(Details)
115: R95 Revenues (Disaggregation of Revenues) (Details) HTML 201K
116: R96 Income Taxes (Details) HTML 79K
117: R97 Related Party Transactions (Details) HTML 121K
118: R98 Subsequent Events (Details) HTML 55K
119: R99 Schedule I - Crestwood Equity Partners LP - Parent HTML 92K
Only - Balance Sheet (Details)
120: R100 Schedule I - Crestwood Equity Partners LP - Parent HTML 83K
Only - Statement of Operations (Details)
121: R101 Schedule I - Crestwood Equity Partners LP - Parent HTML 55K
Only - Statement of Comprehensive Income (Details)
122: R102 Schedule I - Crestwood Equity Partners LP - Parent HTML 61K
Only - Condensed Statement of Cash Flows (Details)
123: R103 Schedule I - Crestwood Equity Partners LP - Parent HTML 35K
Only - Distributions (Details)
124: R104 Schedule II - Crestwood Equity Partners LP - HTML 44K
Valuation and Qualifying Accounts (Details)
127: XML IDEA XML File -- Filing Summary XML 235K
125: XML XBRL Instance -- ceqp-20211231_htm XML 6.03M
126: EXCEL IDEA Workbook of Financial Reports XLSX 192K
17: EX-101.CAL XBRL Calculations -- ceqp-20211231_cal XML 295K
18: EX-101.DEF XBRL Definitions -- ceqp-20211231_def XML 1.81M
19: EX-101.LAB XBRL Labels -- ceqp-20211231_lab XML 2.64M
20: EX-101.PRE XBRL Presentations -- ceqp-20211231_pre XML 2.09M
16: EX-101.SCH XBRL Schema -- ceqp-20211231 XSD 279K
128: JSON XBRL Instance as JSON Data -- MetaLinks 615± 911K
129: ZIP XBRL Zipped Folder -- 0001136352-22-000003-xbrl Zip 795K
(Registrant’s telephone number, including area code)
___________________________________________
Securities
registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol
Name of each exchange on which registered
Crestwood Equity Partners LP
iCommon
Units representing limited partnership interests
iCEQP
iNew York Stock Exchange
Crestwood Equity Partners LP
iPreferred
Units representing limited partner interests
iCEQP-P
iNew York Stock Exchange
Crestwood Midstream Partners LP
None
None
None
Securities
registered pursuant to Section 12(g) of the Act:
Crestwood Equity Partners LP
None
Crestwood Midstream Partners LP
None
Indicate by check mark if registrant is a well-known seasoned issuer, as defined by Rule 405 of the Securities Act.
Crestwood
Equity Partners LP
iYes
☒
No
☐
Crestwood Midstream Partners LP
Yes
☐
iNo
☒
Indicate
by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.
Crestwood Equity Partners LP
Yes
☐
iNo
☒
Crestwood
Midstream Partners LP
Yes
☐
iNo
☒
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.
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
iYes
☒
No
☐
Crestwood
Midstream Partners LP
iYes
☒
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
iLarge
accelerated filer
☒
Accelerated filer
☐
Non-accelerated filer
☐
Smaller reporting company
i☐
Emerging
growth company
i☐
Crestwood Midstream Partners LP
Large accelerated filer
☐
Accelerated filer
☐
iNon-accelerated
filer
☒
Smaller reporting company
i☐
Emerging growth company
i☐
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
i☒
Crestwood
Midstream Partners LP
i☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).
Crestwood
Equity Partners LP
Yes
i☐
No
☒
Crestwood Midstream Partners LP
Yes
i☐
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
$i1.7
billion
Crestwood Midstream Partners LP
iNone
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).
Portions of the following documents are incorporated by reference into the indicated parts of this report:
Crestwood Equity Partners LP
Portions of Crestwood Equity Partners LP’s Proxy Statement for the 2022 Annual Meeting of Stockholders are incorporated by reference into Items 10, 11, 12, 13 and 14 of Part III of this Form 10-K
Crestwood
Midstream Partners LP
None
Crestwood Midstream Partners LP, as a wholly-owned subsidiary of a reporting company, meets the conditions set forth in General Instruction (I)(1)(a) and (b) of Form 10-K and is therefore filing this report with the reduced disclosure format as permitted by such instruction.
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.
The terms below are common to our industry and used throughout this report.
/d
per day
AOD
Area of dedication, which means the acreage dedicated to a company by an oil and/or natural gas producer under one or more contracts.
ASU
Accounting Standards Update
Barrels
(Bbls)
One barrel of petroleum products equal to 42 U.S. gallons.
Bcf
One billion cubic feet of natural gas. A standard volume measure of natural gas products.
Cycle
A complete withdrawal and injection of working gas. Cycling refers to the process of completing one cycle.
EPA
Environmental Protection Agency
FERC
Federal Energy Regulatory
Commission
GAAP
Generally Accepted Accounting Principles
HP
Horsepower
Hub
Geographic location of a storage facility and multiple pipeline interconnections
Hub services
With respect to our natural gas storage and transportation operations, the following services: (i) interruptible storage services, (ii) firm and interruptible park and loan services, (iii) interruptible wheeling services, and (iv) balancing services.
Injection rate
The
rate at which a customer is permitted to inject natural gas into a natural gas storage facility.
MBbls
One thousand barrels
MMBbls
One million barrels
MMcf
One million cubic feet of natural gas
Natural gas
A gaseous mixture of hydrocarbon compounds, primarily methane together with varying quantities of ethane, propane, butane
and other gases.
Natural Gas Act
Federal law enacted in 1938 that established the FERC’s authority to regulate interstate pipelines.
Natural gas liquids (NGLs)
Those hydrocarbons in natural gas that are separated from the natural gas as liquids through the process of absorption, condensation, adsorption or other methods in natural gas processing or cycling plants. NGLs include natural gas plant liquids (primarily ethane, propane, butane and isobutane) and lease condensate (primarily pentanes produced from natural gas at lease separators and field facilities).
NYSE
New York Stock Exchange
SEC
Securities
and Exchange Commission
Withdrawal rate
The rate at which a customer is permitted to withdraw gas from a natural gas storage facility.
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.
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.
•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.
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.
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
our storage and logistics segment was historically separated into a storage and transportation segment and a marketing, supply and logistics segment.
Gathering
and Processing North Segment
Our gathering and processing north operations provide natural gas, crude oil and produced water gathering, compression, treating, processing and disposal services to producers in the Williston Basin and Powder River Basin. Our gathering and processing north segment’s operating assets consist of: (i) natural gas facilities with approximately 0.4 Bcf/d of gathering capacity and approximately 0.5 Bcf/d of processing capacity; (ii) crude oil facilities with approximately 150,000 Bbls/d of gathering capacity and 266,000 Bbls of storage capacity; and (iii) produced water facilities with approximately 130,000 Bbls/d of gathering and disposal capacity.
Williston Basin
We own and operate an integrated crude oil, rich natural gas and produced water gathering
system, with a gas processing facility (Bear Den) and produced water disposal facilities, collectively the Arrow system, in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota, primarily located on the Fort Berthold Indian Reservation. The COLT Hub, a crude-by-rail facility located approximately 60 miles northwest of the Arrow system, connects to the Arrow system through the Tesoro High Plains Pipeline Company LLC’s, a subsidiary of Marathon Petroleum Corporation (Marathon), crude oil pipeline system allowing access to the Pacific Northwest markets. Crude oil gathered on the Arrow system can service Midwest refineries from Patoka, Illinois and the Gulf Coast via the Dakota Access Pipeline (DAPL) or the Guernsey, Wyoming markets through the Kinder Morgan Inc. (Kinder Morgan) Double H Pipeline and the True Pipeline system. In addition to the multiple pipeline take-away outlets, the Arrow system has 266,000 Bbls of crude oil working storage capacity.
The Bear Den facility and associated pipelines at the Arrow system fulfill nearly all of the processing requirements for producers on the Arrow system. Our operations are anchored by long-term gathering contracts that largely provide for fixed-fee gathering services with annual escalators for crude oil, natural gas and produced water gathering services.
Powder River Basin
We own and operate the Jackalope rich natural gas gathering system and Bucking Horse gas processing facility in Converse County, Wyoming, which connects to 157 well pads and is supported by a long-term gathering and processing agreement with Chesapeake Energy Corporation (Chesapeake) that has a remaining contract term of 15 years and provides minimum revenue guarantees for three years.
The table below
details certain information about our gathering and processing north segment as of December 31, 2021:
Basin
(State)
Counties
Pipeline
(Miles)
Gathering Capacity
2021 Average Gathering Volumes
Compression (HP)
Number of In-Service Processing Plants
Processing Capacity (MMcf/d)
Gross Acreage Dedication
Williston Basin
North Dakota
McKenzie and Dunn
709(1)
150 MMcf/d - natural gas 150 MBbls/d - crude oil 130 MBbls/d - produced water
139
MMcf/d - natural gas 88 MBbls/d - crude oil 86 MBbls/d - produced water
86,450
1
140
150,000
Powder River Basin
Wyoming
Converse
360
241 MMcf/d
101 MMcf/d
90,235
2
345
399,000
(1)Consists
of 267 miles of natural gas gathering pipeline, 223 miles of crude oil gathering pipeline, and 219 miles of produced water gathering pipeline.
(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
system with the Orla plant; and (iv) a produced water gathering and disposal
system capable of handling 75,000 Bbls/d of produced water in Culberson and Reeves Counties, Texas.
Crestwood Permian also owns an undivided interest in 80,000 Bbls/d of capacity in a segment of the Epic Y-Grade Pipeline, LP (EPIC) pipeline from Orla, Texas to Benedum, Texas, and includes an interconnection with Chevron Phillips Chemical Company, LP’s (Chevron Phillips) pipeline, and other delivery points near Benedum. This capacity is supported, in part, by a purchase and sale agreement with Chevron Phillips to sell a dedicated volume of barrels to be delivered off the EPIC pipeline to Chevron Phillips’ pipeline. Crestwood Permian’s ownership in the EPIC pipeline provides a competitive NGL takeaway solution to allow Crestwood Permian to grow its footprint in the Delaware Basin.
Crestwood Permian also owns a 50% equity interest in Crestwood Permian
Basin LLC (Crestwood Permian Basin) and Shell Midstream Partners L.P. (Shell Midstream), a subsidiary of Royal Dutch Shell plc, owns the remaining 50% equity interest. Crestwood Permian Basin owns the Nautilus natural gas gathering system which includes 166 miles of gathering pipelines, a 43-mile high pressure header system, 45,000 horsepower of compression, 109 receipt meters and seven high pressure delivery points. The Nautilus gathering system will be expanded over time as production increases to include additional gathering lines and centralized compression facilities which will ultimately provide over 250 MMcf/d of gas gathering capacity. Crestwood Permian Basin has a long-term fixed fee gathering agreement with Permian Delaware Enterprise Holdings LLC (Permian Delaware Enterprise), a subsidiary of ConocoPhillips Company (ConocoPhillips), under which Permian Delaware Enterprise has dedicated the gathering rights for its gas production across a large acreage position
in Loving, Reeves and Ward Counties, Texas to Crestwood Permian Basin, and under which Crestwood Permian Basin provides gathering and dehydration services to them.
The table below details certain information about our gathering and processing south segment (including our equity investment and its operations) as of December 31, 2021:
Basin
(State)
Counties
Pipeline
(Miles)
Gathering Capacity
2021 Average Gathering Volumes
Compression (HP)
Number of In-Service Processing Plants
Processing Capacity(4)
(MMcf/d)
Gross Acreage Dedication
Marcellus
West Virginia
Harrison and Doddridge
72
875 MMcf/d
227 MMcf/d
113,000
—
—
140,000
Barnett
Texas
Hood, Somervell, Tarrant, Johnson and Denton
388
925 MMcf/d
218 MMcf/d
153,465
1
425
140,000
Delaware Basin(1)
New Mexico/Texas
Eddy (New Mexico) Loving, Reeves, Ward and Culberson (Texas)
322(2)
650
MMcf/d - natural gas 75 MBbls/d - produced water
229 MMcf/d - natural gas 40 MBbls/d - produced water
85,455(3)
1
255
359,000
(1)Our
Delaware Basin assets in New Mexico and Texas are owned by Crestwood Permian, our 50% equity method investment, and its equity method investment, Crestwood Permian Basin.
(2)Consists of 308 miles of natural gas gathering pipeline and 14 miles of produced water gathering pipeline.
(3)Includes 45,000 HP that is owned and operated by a third party under a compression services agreement.
(4)Includes capacity of processing plants that are in service and not in service.
The table below summarizes certain contract information of our gathering and processing south segment (including our equity investment and its operations) as of December 31, 2021:
Basin
Type
of Contracts(1)
Weighted Average Remaining Contract Terms (in years)
Major Customers
Marcellus
Fixed-fee
10
Antero Resources Corporation
Barnett
Mixed
5
Diversified Energy Company plc, FDL Operating LLC
Delaware
Fixed-fee
13
Permian
Delaware Enterprise, Mewbourne Oil Company (Mewbourne)
Percentage-of-proceeds
6
Mewbourne, ConocoPhillips
(1)Fixed-fee contracts represent contracts in which our customers agree to pay a flat rate based on the amount of gas delivered. Mixed contracts include percentage-of-proceeds and fixed-fee arrangements.
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.
The table below summarizes certain contract information
about our COLT Hub operations and our Tres Holdings equity investment as of December 31, 2021:
Facility
Type of Contracts(1)
Weighted Average Remaining Contract Terms
Major Customers
COLT
Fixed-Fee,
Firm
Less than 1 year
BP Products North America, Inc. (BP), Flint Hills Resources
Tres Palacios
Firm(2)
2 years
Trafigura Trading LLC, Hartree Partners LP, BP
(1)Fixed-fee contracts represent contracts in which our customers agree to pay a flat rate based on the amount of crude oil transported or stored. Firm contracts represent contracts whereby our customers agree to pay for a specified amount of storage
or transportation capacity, whether or not the capacity is utilized.
(2)Tres Palacios has approximately 28.8 Bcf of firm storage contracts at December 31, 2021.
The cash flows from our COLT Hub operations are predominantly fee-based under contracts with terms ranging from six months to 1 year. Our current cash flows from crude-by-rail facilities are supported by contracts with refiners and marketers. The rates and durations of the contracts associated with our crude oil terminals have eroded as pipelines have come on-line that make crude-by-rail options less economical, which impacts our cash flows from operations. The cash flows from our Tres Palacios joint venture are predominantly fee-based under contracts with remaining terms ranging from 1 to 6 years. Cash flows from interruptible and
other hub services provided by our Tres Palacios joint venture tend to increase during the peak winter season. The cash flows from our other storage and logistics operations represent sales to creditworthy customers typically under contracts with durations of one year or less, and tend to be seasonal in nature due to customer profiles and their tendencies to purchase NGLs during peak winter periods.
Major Customers
For the years ended December 31, 2021 and 2020, no customer accounted for more than 10% of our total consolidated revenues. For the year ended December 31, 2019, BP and its affiliates accounted for approximately 10% of our total consolidated revenues.
Competition
Our gathering and processing operations compete for customers based on reputation, operating reliability and flexibility, price, creditworthiness, and service offerings, including interconnectivity to producer-desired takeaway options (i.e., processing facilities and pipelines). We face strong competition in acquiring new supplies in the production basins in which we operate, and competition customarily is impacted by the level of drilling activity in a particular geographic region and fluctuations in commodity prices. Our primary competitors include other midstream companies with gathering and processing operations and producer-owned systems, and certain competitors enjoy first-mover advantages over us and may offer producers greater gathering and processing efficiencies, lower operating costs and more flexible commercial terms.
Natural gas
storage and pipeline operators compete for customers primarily based on geographic location, which determines connectivity and proximity to supply sources and end-users, as well as price, operating reliability and flexibility, available capacity and service offerings. Our primary competitors in our natural gas storage market include other independent storage providers and major natural gas pipelines with storage capabilities embedded within their transmission systems. Our primary competitors in the natural gas transportation market include major natural gas pipelines and intrastate pipelines that can transport natural gas volumes between interstate systems. Long-haul pipelines often enjoy cost advantages over new pipeline projects with respect to options for delivering greater volumes to existing demand centers, and new projects and expansions proposed from time to time may serve the markets we serve and effectively displace the service we provide to customers.
Our
crude oil rail terminals primarily compete with crude oil pipelines and other midstream companies that own and operate rail terminals in the markets we serve. The crude oil logistics business is characterized by strong competition for supplies, and competition is based largely on customer service quality, pricing, and geographic proximity to customers and other market hubs.
Our NGL marketing and logistics business competes primarily with integrated major oil companies, refiners and processors, and other energy companies that own or control transportation and storage assets that can be optimized for supply, marketing and logistics services.
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.
•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
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
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
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.
The following is a summary of the more significant existing federal environmental laws and regulations, each as amended from time to time, to which our business operations and the operations of our equity investments are subject:
•The Comprehensive Environmental Response, Compensation and Liability Act, a remedial statute that imposes strict liability on generators, transporters, disposers and arrangers of hazardous substances at sites where hazardous substance releases have occurred or are threatening to occur;
•The Resource Conservation and Recovery Act, which governs the generation, treatment, storage and disposal of non-hazardous and hazardous wastes;
•The Clean Air Act, which restricts the emission
of air pollutants from many sources and imposes various pre-construction, monitoring and reporting requirements and that serves as a legal basis for the EPA to adopt climate change regulatory initiatives relating to greenhouse gas (GHG) emissions;
•The Water Pollution Control Act, also known as the federal Clean Water Act, which regulates discharges of pollutants from facilities to state and federal waters and establishes the extent to which waterways are subject to federal jurisdiction and rulemaking as protected waters of the United States;
•The Safe Drinking Water Act, which ensures the quality of the nation’s public drinking water through adoption of drinking water standards and controlling the injection of substances into below-ground formations that may adversely affect drinking water sources;
•The
National Environmental Policy Act, which requires federal agencies to evaluate major agency actions having the potential to significantly impact the environment and which may require the preparation of Environmental Assessments or detailed Environmental Impact Statements to be made available for public review and comment;
•The Endangered Species Act, which restricts activities that may affect federally identified endangered or threatened species, or their habitats through the implementation of operating restrictions or a temporary, seasonal or permanent ban in affected areas; and
•The Occupational Safety and Health Act, which establishes workplace standards for the protection of the health and safety of employees, including the implementation of hazard communications programs designed to inform employees about hazardous substances
in the workplace, potential harmful effects of these substances and appropriate control measures.
Certain of these federal environmental laws, as well as their state counterparts, impose strict, joint and several liability for costs required to clean up and restore properties where pollutants have been released regardless of whom may have caused the harm or whether the activity was performed in compliance with all applicable laws. States also adopt and implement their own environmental laws and regulations, which may be more stringent than federal requirements. In the course of our operations, generated materials or wastes may have been spilled or released from properties owned or leased by us or on or under other locations where these materials or wastes have been taken for recycling or disposal. In addition, many of the properties owned or leased by us were previously operated by third parties
whose management, disposal or release of materials and wastes was not under our control. Accordingly, we may be liable for the costs of cleaning up or remediating contamination arising out of our operations or as a result of activities by others who previously occupied or operated on properties now owned or leased by us. Private parties, including the owners of properties that we lease and facilities where our materials or wastes are taken for recycling or disposal, may also have the right to pursue legal actions to enforce compliance as well as to seek damages for non-compliance with environmental laws and regulations or for personal injury or property or natural resource damages. We may not be able to recover some or any of these additional costs from insurance.
During 2014, we experienced three releases on our Arrow produced water gathering system that resulted in approximately 28,000 barrels of produced
water being released on lands within the boundaries of the Fort Berthold Indian Reservation. In May 2015, we experienced another release of approximately 5,200 barrels of produced water, and during September 2019, we experienced two produced water releases totaling approximately 5,000 barrels. We are substantially complete with all remediation efforts related to these spills, have settled and paid all potential fines and penalties related to these water spills.
It is also possible that adoption of stricter environmental laws and regulations or more stringent interpretation of existing environmental laws and regulations in the future could result in additional costs or liabilities to us as well as the industry in general or otherwise adversely affect demand for our services. For example, in 2015, the EPA issued a final rule under the Clean Air Act, making the National Ambient Air Quality Standard (NAAQS)
for ground-level ozone more stringent. Since that time, the EPA has issued area designations with respect to ground-level ozone and final requirements that apply to state, local, and tribal air agencies for implementing the 2015 NAAQS for ground-level ozone and, in December 2020, published notice of a final action to retain the 2015 ozone NAAQS without revision on a going-forward basis. However, several groups have filed
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
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
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, Texas77002, 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,
Texas77002, 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, Texas77002, Attention: General Counsel. All such communications will be delivered to the director or directors to whom they are addressed.
Our business depends on hydrocarbon supply and demand fundamentals, which can be adversely affected by numerous factors outside of our control.
Our success depends on the supply and demand for natural gas, NGLs and crude oil, which has historically generated the need for new or expanded midstream infrastructure. The degree to which our business is impacted by changes in supply or demand varies. Our business can be negatively impacted by sustained downturns in supply and demand for one or more commodities, including reductions in our ability to renew contracts on favorable terms and to construct new infrastructure. For example, significantly lower commodity prices during the
past few years have resulted in an industry-wide reduction in capital expenditures by producers and a slowdown in drilling, completion and supply development efforts. Notwithstanding this market downturn, production volumes of crude oil, natural gas and NGLs have continued to grow (or decline at a slower rate than expected). Similarly, major factors that impact natural gas demand domestically include the effects of the COVID-19 pandemic, the realization of potential liquefied natural gas exports and demand growth within the power generation market. Factors that impact crude oil demand include production cuts and freezes implemented by OPEC members and other large oil producers such as Russia. For example, during the first half of 2020, the combined effect of OPEC and Russia’s failure to agree on a plan to cut production of oil and related commodities, the outbreak of the COVID-19 pandemic and the shortage in available storage for hydrocarbons in the United States contributed
to a sharp drop in prices for crude oil. While prices for oil have subsequently experienced more stability since then, we cannot predict what actions OPEC and other oil-producing countries will take in the future. In addition, the supply and demand for natural gas, NGLs and crude oil for our business will depend on many other factors outside of our control, some of which include:
•changes in general domestic and global economic and political conditions;
•disruptions of financial and credit markets, including inflation, which affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements;
•changes in domestic regulations that could impact the supply or demand for oil and gas;
•technological
advancements that may drive further increases in production and reduction in costs of developing shale plays;
•competition from imported supplies and alternate fuels;
•commodity price changes that could negatively impact the supply of, or the demand for these products;
•outbreak of illness, pandemic or any other public health crisis, including the COVID-19 pandemic;
•the availability of hydrocarbon storage;
•increased costs to explore for, develop, produce, gather, process or transport commodities;
•impact of interest rates on economic activity;
•shareholder
activism and activities by non-governmental organizations to limit sources of funding for the energy sector or restrict the exploration, development and production of oil and gas;
•operational hazards, including terrorism, cyber-attacks or domestic vandalism;
•adoption of various energy efficiency and conservation measures; and
•perceptions of customers on the availability and price volatility of our services, particularly customers’ perceptions on the volatility of commodity prices over the longer-term.
If volatility and seasonality in the oil and gas industry increase, because of increased production capacity, reduced demand for energy, or otherwise, the demand for our services and the fees that we will
be able to charge for those services may decline. In addition to volatility and seasonality, an extended period of low commodity prices could adversely impact storage and transportation values for some period of time until market conditions adjust. For example, in response to low commodity prices experienced during early 2020, some of our customers reduced capital expenditures and curtailed production, which adversely affected our gathering and processing north and south segments’ results. With West Texas Intermediate crude oil prices ranging from $47.47 to $84.64 per barrel in 2021, the sustainability of recent prices improvements and longer-term oil prices cannot be predicted. These commodity price impacts could have a negative impact on our business, financial condition and results of operations.
The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have
material adverse effects on our business, financial position, results of operations and/or cash flows.
During 2021 and 2020, the global and U.S. economy was negatively impacted by the COVID-19 pandemic, which disrupted global supply chains, reduced consumer activity, disrupted travel and created significant volatility and disruption of financial
and commodity markets. The effects of the COVID-19 pandemic resulted in a significant reduction in global demand for natural gas, NGLs and crude oil and a significant and persistent reduction in the market price of crude oil during 2020. As a result, many producers,
including some of our customers, curtailed some of their short-term drilling and production activity and reduced or slowed down their plans for future drilling and production activity. This decrease in activity decreased the demand that certain of these customers had for our services in 2020, and may continue to impact demand for our services in the future if our customers continue to or further curtail drilling and production activity in the future.
The COVID-19 pandemic has also caused federal and local governments to implement measures to quarantine individuals and limit gatherings, which has impacted our workforce and the way we have traditionally conducted our business. In response, we have implemented preventative measures to minimize unnecessary risk of exposure and prevent infection, while supporting our customers’ operations. We have continued to follow modified business practices (including reducing
non-essential business travel, implementing staggered work-from-home policies for employees who can execute their work remotely in order to reduce office density, and encouraging employees to adhere to local and regional social distancing recommendations) to support efforts to reduce the spread of COVID-19 and to conform to government restrictions and best practices encouraged by governmental and regulatory authorities. We also have promoted heightened awareness and vigilance, hygiene and more stringent cleaning protocols across our facilities and operations. We continue to evaluate and adjust these preventative measures, response plans and business practices with the evolving impacts of COVID-19. However, if COVID-19 were to impact a location where we have a high concentration of business and resources, our local workforce could be affected by such an occurrence or outbreak which could also significantly disrupt our operations and decrease our ability to provide gathering,
processing, storage and transportation services to our customers.
The extent of the impact of the COVID-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas (including the impact that reductions in travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations. There is uncertainty around the extent and duration of the disruption. The degree to which the COVID-19 pandemic or any other public health crisis adversely impacts our results will depend on future
developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Additionally, the actions taken to contain the COVID-19 pandemic include actions implemented by governmental authorities, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns, all of which affect the demand for oil, natural gas and NGLs. Due to these factors, we expect to see continued volatility in commodity prices for the foreseeable future. These potential impacts, while uncertain, could adversely affect our operating results.
Our
future growth may be limited if commodity prices decrease, resulting in a prolonged period of reduced midstream infrastructure development and service requirements to customers.
Our business strategy depends on our ability to provide increased services to our customers and develop growth projects that can be financed appropriately. We may be unable to complete successful, accretive growth projects for any of the following reasons, among others:
•we fail to identify (or we are outbid for) attractive expansion or development projects or acquisition candidates that satisfy our economic and other criteria;
•we fail to secure adequate customer commitments to use the facilities to be developed, expanded or acquired; or
•we
cannot obtain governmental approvals or other rights, licenses or consents needed to complete such projects or acquisitions on time or on budget, if at all.
The development and construction of gathering, processing, storage and transportation facilities involves numerous regulatory, environmental, safety, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. When we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular growth project. For instance, if we build a new gathering system, processing plant or transmission pipeline, the construction may occur over an extended period of time and we will not receive material increases in revenues until the project is placed in service. Accordingly, if we do pursue
growth projects, we can provide no assurances that our efforts will provide a platform for additional growth for our company.
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.
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
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.
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
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
would trigger the change of control provision. In certain
circumstances, the control of our general partner may be transferred to a third party without unitholder consent, and this may be considered a change in control under our revolving credit facility and senior notes. Please read “The control of our general partner may be transferred to a third party without unitholder consent.”
Our ability to make cash distributions may be diminished, and our financial leverage could increase, if we are not able to obtain needed capital or financing on satisfactory terms.
Historically, we have used cash flow from operations, borrowings under our revolving credit facilities and issuances of debt or equity to fund our capital programs, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our operations to fund
growth. If our cash flow from operations decreases or distributions from our equity investments decrease as a result of lower throughput volumes on their systems or otherwise, our ability to expend the capital necessary to expand our business or increase our future cash distributions may be limited. If our cash flow from operations and the distributions we receive from subsidiaries are insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition or general economic conditions at the time of any such financing or offering. Even if we are successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions
to our unitholders. Further, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the cash distribution rate which could materially decrease our ability to pay distributions. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis.
Increases in interest rates could adversely impact our unit price, ability to issue equity or incur debt for acquisitions or other purposes, and ability to make payments on our debt obligations.
Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could
be higher than current levels, causing our financing costs to increase accordingly. Therefore, changes in interest rates either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make payments on our debt obligations.
A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.
A downgrade of our credit ratings may increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our
subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:
•economic downturns;
•deteriorating capital market conditions;
•declining market prices for crude oil, natural gas, NGLs and other commodities;
•terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
•the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Credit rating agencies perform independent
analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.
The loss of key personnel could adversely affect our ability to operate.
Our success is dependent upon the efforts of our senior management team, as well as on our ability to attract and retain both executives and employees for our field operations.
Our senior executives have significant experience in the oil and gas industry and have developed strong relationships with a broad range of industry participants. The loss of these executives, or the loss of key field employees operating in competitive markets, could prevent us from implementing our business strategy and could have a material adverse effect on our customer relationships, results of operations and ability to make distributions.
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.
Our business involves many hazards and risks, some of which may not be fully covered by insurance.
Our operations are subject to many risks inherent in the energy midstream industry, such as:
•damage to pipelines and plants, related equipment and
surrounding properties caused by natural disasters and acts of terrorism or domestic vandalism;
•subsidence of the geological structures where we store NGLs, or storage cavern collapses;
•operator error;
•inadvertent damage from construction, farm and utility equipment;
•leaks, migrations or losses of natural gas, NGLs or crude oil;
•fires and explosions;
•cyber intrusions; and
•other hazards that could also result in personal injury, including loss of life, property and natural resources damage,
pollution of the environment or suspension of operations.
These risks could result in substantial losses due to breaches of contractual commitments, personal injury and/or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage. For example, we have experienced releases on our Arrow water gathering system on the Fort Berthold Indian Reservation in North Dakota, the remediation and repair costs of which we believe are covered by insurance, but nonetheless potential future water spills could subject us to substantial penalties, fines and damages from regulatory agencies and individual landowners. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in
our business. We are also not insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could result in a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities. Although we maintain insurance policies with insurers in such
amounts and with such coverages and deductibles as we believe are reasonable and prudent, our insurance may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities (particularly our gathering and processing facilities) have been constructed, which subjects us to the possibility of more onerous terms or increased costs to obtain and maintain valid easements and rights-of-way. Easements and rights-of-way exists for varying periods of time. We obtain standard easement rights to construct and operate pipelines on land owned by third parties, and our rights frequently revert back to the landowner
after we stop using the easement for its specified purpose. With regard to easements and rights-of-way on tribal lands, following a 2017 court decision issued by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land (that is, tribal land owned or at one time owned by an individual Indian landowner) bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted tribal lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannot guarantee that we will always be able to renew existing rights-of-way or obtain new rights-of-way without experiencing significant costs. Our loss of easement rights could have a material adverse effect on our ability to operate our business, thereby resulting in a material reduction in our results of operations and ability to make distributions.
Terrorist
attacks or “cyber security” events, or the threat of them, may adversely affect our business.
The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets for terrorist organizations or “cyber security” events. These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets or utilize our customer service systems. Also, destructive forms of protests and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural gas development and production or midstream processing or transportation activities could potentially result in damage or injury to persons, property or the environment or lead to extended interruptions of our or our customers’
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.
Our operations are subject to extensive regulation, and regulatory measures adopted by regulatory authorities could have a material adverse effect on our business, financial condition and results of operations.
Our operations,
including our joint ventures, are subject to extensive regulation by federal, state and local regulatory authorities. Federal regulation under the Natural Gas Act extends to such matters as:
•rates, operating terms and conditions of service;
•the form of tariffs governing service;
•the types of services we may offer to our customers;
•the certification and construction of new, or the expansion of existing facilities;
•the acquisition, extension, disposition or abandonment of facilities;
•contracts for service between storage and transportation providers and their
customers;
•creditworthiness and credit support requirements;
•the maintenance of accounts and records;
•relationships among affiliated companies involved in certain aspects of the natural gas business;
•the initiation and discontinuation of services; and
•various other matters.
The FERC issued a Notice of Inquiry (NOI) on April 19, 2018 (Certificate Policy Statement NOI), thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy
Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999, that is used to determine whether to grant certificates for new pipeline projects. Comments on the Certificate Policy Statement NOI were due on July 25, 2018. The FERC has not taken further action since the Certificate Policy Statement NOI was issued. We are unable to predict what, if any, changes may be proposed as a result of the NOI that will affect our natural gas pipeline business or when such proposals, if any, might become effective.
There can be no assurance that the FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. Failure to comply with applicable
regulations under the Natural Gas Act, the Natural Gas Policy Act of 1978, the NGPSA and certain other laws, and with implementing regulations associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to approximately $1.3 million per day, per violation.
A change in the jurisdictional characterization of our gathering assets may result in increased regulation, which could cause our revenues to decline and operating expenses to increase.
Our natural gas and crude oil gathering operations are generally exempt from the jurisdiction and regulation of the FERC, except for certain anti-market manipulation provisions. FERC regulation nonetheless affects our businesses and the markets for products derived from our gathering businesses. The FERC’s policies and practices across the range
of its oil and gas regulatory activities, including, for example, its policies on open access transportation, rate making, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we have no assurance that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has regularly been the subject of substantial, on-going litigation. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by the FERC, the courts or Congress. If our gathering operations become subject to FERC jurisdiction, the result may adversely
affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of certain gathering agreements.
State and municipal regulations also impact our business. Common purchaser statutes generally require gatherers to gather or provide services without undue discrimination as to source of supply or producer; as a result, these statutes restrict our right to decide whose production we gather or transport. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we currently operate have adopted complaint-based regulation of gathering activities, which allows oil and gas producers and shippers to file complaints with state regulators in an effort to resolve access and rate grievances. Other state and municipal regulations may not directly regulate our gathering business, but may nonetheless affect the availability
of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of its gathering lines.
Our operations are subject to compliance with environmental and operational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our
operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing worker health and safety aspects of our operations, the discharge of materials into the environment and otherwise relating to environmental protection. These requirements may take the form of laws, regulations, executive actions and various other legal initiatives. See Item 1. Business, “Regulation - Environmental and Occupational Safety and Health Matters” for a further discussion on these matters. Compliance with these regulations and other regulatory initiatives or any other new environmental laws and regulations could, among other things, require us or our customers to install new or modified emission controls on equipment or processes and incur significantly increased capital or operating expenditures and operating delays, restrictions or cancellations with respect to our operations, which costs may be significant.
Additionally, one or more of these developments that impact our customers involved in oil and natural gas exploration and production could reduce demand for our services. These developments could have a material adverse effect on our business, results of operations and financial condition.
Our and our customers’ operations are subject to various risks arising out of the threat of climate change, energy conservation measures, or initiatives that stimulate demand for alternative forms of energy that could result in increased costs, limit the areas in which oil and natural gas production may occur and reduced demand for our services.
Our and our customers’ operations are subject to a number of risks arising out of the threat of climate change, energy conservation measures, or initiatives that stimulate demand for alternative forms of
energy that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce the demand for the crude oil and natural gas. Risks arising out of the threat of climate change, fuel conservation measures, governmental requirements for renewable energy resources, increasing customer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices may create new competitive conditions that result in reduced demand for the crude oil and natural gas our customers produce and our services. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. See Part I, Item 1. Business,“Regulation - Environmental and Occupational Safety and Health Matters” for further discussion relating
to risks arising out of the threat of climate change and emission of GHGs, climate change activism, energy conservation measures or initiatives that stimulate demand for alternative forms of energy, and physical effects of climate change. One or more of these developments could have an adverse effect on our business, financial condition and results of operations.
We may incur higher costs as a result of pipeline integrity management program testing and additional safety legislation.
Pursuant to authority under the NGPSA and HLPSA, PHMSA has established rules requiring pipeline operators to develop and implement integrity management programs for certain natural gas and hazardous liquid pipelines located where a leak or rupture could harm HCAs, MCAs, Class 3 and 4 areas, as well as areas unusually sensitive to environmental damage and commercially
navigable waterways. Among other things, these regulations require operators of covered pipelines like us to:
•perform ongoing assessments of pipeline integrity;
•identify and characterize applicable threats to pipeline segments that could impact a HCA, MCA or Class 3 and 4 area;
•maintain processes for data collection, integration and analysis;
•repair and remediate pipelines as necessary; and
•implement preventive and mitigating actions.
Additionally, certain states where we conduct operations, including New Mexico, North Dakota, West Virginia
and Wyoming, have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas pipelines, and New Mexico, Texas and West Virginia have also adopted regulations similar to existing PHMSA regulations for certain intrastate hazardous liquid pipelines. We estimate that the total future costs to complete the testing required by existing PHMSA or any applicable state regulations will not have a material impact to our results. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program itself, which costs could be substantial. The results of this testing could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.
Moreover,
federal legislation or implementing regulations adopted in recent years may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur
increased capital costs, operational delays and costs of operations. See Item 1. Business, “Regulation - Environmental and Occupational Safety and Health Matters” for a further discussion on pipeline safety matters.
Risks Inherent in an Investment in Our Equity
We
may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay quarterly distributions to our common and preferred unitholders.
We may not have sufficient cash each quarter to pay quarterly distributions to our common unitholders or, alternatively, we may reallocate a portion of our available cash to debt repayments or capital investments. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, distributions received from our joint ventures, and payments of fees and expenses as well as decisions the board of directors makes regarding acceptable levels of debt or the desire to invest in new growth projects. Our board typically reviews these factors on a quarterly basis. Before we pay any cash distributions on our preferred
and common units, we will establish reserves and pay fees and expenses, including reimbursements to our general partner and its affiliates, for all expenses they incur and payments they make on our behalf. These costs will reduce the amount of cash available to pay distributions to our common unitholders and, to the extent we are unable to declare and pay fixed cash distributions on our preferred units, we cannot make cash distributions to our common unitholders until all payments accruing on the preferred units have been paid.
The amount of cash we have available to distribute on our preferred and common units will fluctuate from quarter to quarter based on, among other things:
•the rates charged for services and the amount of services customers purchase, which will be affected by, among other things, the overall
balance between the supply of and demand for commodities, governmental regulation of our rates and services and our ability to obtain permits for growth projects;
•force majeure events that damage our or third-party pipelines, facilities, related equipment and surrounding properties;
•prevailing economic and market conditions;
•governmental regulation, including changes in governmental regulation in our industry;
•changes in tax laws;
•the level of competition from other midstream companies;
•the level of our operations and maintenance and general and administrative
costs;
•the level of capital expenditures we make;
•our ability to make borrowings under our revolving credit facility;
•our ability to access the capital markets for additional investment capital; and
•acceptable levels of debt, liquidity and/or leverage.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including: the level and timing of capital expenditures we make; our debt service requirements and other liabilities; fluctuations in our working capital needs; our ability to borrow funds and access capital markets; restrictions
contained in our debt agreements; and the amount of cash reserves established by our general partner.
Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow given the current trends existing in the capital markets.
The significant decrease in commodity prices has negatively impacted the equity and debt markets resulting in limitations on our ability to access the capital markets for new growth capital at a reasonable cost of capital. Historically, we have distributed all of our available cash to our preferred and common unitholders on a quarterly basis and relied upon external financing sources, including commercial bank borrowings and the issuance of debt and equity securities, to fund our acquisitions and expansion capital expenditures. If the current capital market trends
persist, we may be unable to finance growth externally by accessing the capital markets, and may have to depend on a reallocation of our cash distributions to reduce debt and/or invest in new growth projects. In addition, we may dispose of assets to reduce debt and/or invest in new growth projects, which can impact the level of our cash distributions.
In the event we continue to distribute all of our available cash or decide to reallocate cash to debt reduction, our growth may not be as fast as that of businesses that reinvest their available cash to expand ongoing operations. To the extent we decide to reallocate cash to debt reduction or invest in new capital projects, we may be unable to maintain or increase our per unit distribution level. Subject to certain restrictions that apply if we are not able to pay cash distributions to our preferred unitholders, there are no limitations in our partnership
agreement on our ability to issue additional units, including units ranking
senior to the common units. The incurrence of additional commercial borrowings or other debt to finance our growth strategy would result in increased interest expense, which, in turn, may impact the available cash that we have to distribute to our unitholders.
We may issue additional common units without common unitholder approval, which would dilute existing common unitholder ownership interests.
Our partnership agreement does not limit the number of additional
limited partner interests we may issue at any time without the approval of our existing common unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:
•our existing common unitholders’ proportionate ownership interest in us will decrease;
•the amount of cash available for distribution on each common unit may decrease;
•the ratio of taxable income to distributions may increase;
•the relative voting strength of each previously outstanding common unit may be diminished; and
•the market price of the common units may decline.
The
market value of Crestwood’s common units could decline if large amounts of such units are sold following the merger with Oasis Midstream.
As of February 1, 2022, Oasis Petroleum owned approximately 21.6% of our common units. We cannot predict the effect that issuances and sales of our common units after the merger, including issuances and sales in connection with capital markets transactions, acquisition transactions or other transactions, may have on the market value of our common units. The issuance and sale of substantial amounts of our common units, including those owned by Oasis Petroleum and its affiliates, could adversely affect the market value of such units.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units and has other governance
differences from typical corporations.
Unitholders’ voting rights are restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence our management. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership due to the absence of a takeover premium in the trading price or other governance differences.
Common unitholders may have liability to repay
distributions and in certain circumstances may be personally liable for the obligations of the partnership.
Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the Delaware Act), we may not make a distribution to our common unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the
partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner; (ii) approve some amendments to our partnership agreement; or (iii) take other action under our partnership agreement constitutes “participation in the control” of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware
to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.
The amount of cash we have available for distribution to common unitholders depends primarily on our cash flow (including distributions from joint ventures) and not solely on profitability, which may prevent us from making cash distributions
during periods when we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings and cash distributions received from our joint ventures, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net income.
Our preferred units contain covenants that may limit our business flexibility.
Our preferred units contain covenants preventing us from taking certain actions without the approval of the holders of a majority or a super-majority of the preferred units,
depending on the action as described below. The need to obtain the approval of holders of the preferred units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of its unitholders. The affirmative vote of the then-applicable voting threshold of the outstanding preferred units, voting separately as a class with one vote per preferred unit, shall be necessary to amend our partnership agreement in any manner that (i) alters or changes the rights, powers, privileges or preferences or duties and obligations of the preferred units in any material respect; (ii) except as contemplated in the partnership agreement, increases or decreases the authorized number of preferred units; or (iii) otherwise adversely affects the preferred units, including without limitation the creation (by reclassification or otherwise) of any class of senior securities (or amending the provisions
of any existing class of partnership interests to make such class of partnership interests a class of senior securities). In addition, our partnership agreement provides certain rights to the preferred unitholders that could impair our ability to consummate (or increase the cost of consummating) a change-in-control transaction, which could result in less economic benefits accruing to our common unitholders.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. The new owner of our general partner would then be in a position, subject to obtaining any approvals or consents required under the applicable governing
documents, to replace the board of directors and officers of our general partner with its own choices and to control the decisions taken by our board of directors and officers. This effectively permits a “change of control” without the vote or consent of the common unitholders. In addition, such a change of control could result in our indebtedness becoming due. Please read risk factor “A change of control could result in us facing substantial repayment obligations under our revolving credit facility and senior notes.”
Our partnership agreement limits our general partner’s fiduciary duties to us and restricts the remedies available for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards
to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
•provides that our general partner is entitled to make decisions in “good faith” if it reasonably believes that the decisions are in our best interests;
•generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties
involved, including other transactions that may be particularly advantageous or beneficial to us; and
•provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of our outstanding units, our general partner will have the right, but not
the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be
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
taxpurposes. If the IRS were to treat us as a corporation forfederal income tax purposes, or we were to become subject to material additionalamounts of entity-level taxation for state tax purposes, then our cash available fordistribution 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.
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.
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
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.
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 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)
(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.
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.
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
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.
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.
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.
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.
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.
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.
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
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.
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.
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 (used in) investing activities
$
568.9
$
(273.3)
$
(943.7)
Net
cash provided by (used in) financing activities
$
(996.3)
$
(146.5)
$
531.8
Operating Activities
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.
The following table summarizes our capital expenditures for the year ended December 31, 2021 (in millions):
Growth capital
$
59.5
Maintenance
capital
19.3
Other(1)
4.4
Purchases of property, plant and equipment
$
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.
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)
(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.
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.
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:
Change in Fair Value of Commodity-Based Derivatives
(in millions)
Net Unbalanced Derivative Position
Inventory Position
Natural gas
$
2.4
6.3 Bcf
1.7 Bcf
NGLs
$
15.5
3.4
MMBbls
2.8 MMBbls
Crude oil
$
4.2
0.6 MMBbls
0.4 MMBbls
Credit Risk
Credit risk is the risk of loss from nonperformance by suppliers, customers or financial counterparties to a contract. We take an active role in managing and controlling credit
risk and have established control procedures, which are reviewed on an ongoing basis. We have diversified our credit risk through having long-term contracts with many investment grade customers and creditworthy producers. Additionally, we perform credit analyses of our customers on a regular basis pursuant to our corporate credit policy. We have not had any significant losses due to failures to perform by our counterparties.
Under a number of our customer contracts, there are provisions that provide for our right to request or demand credit assurances from our customers including the posting of letters of credit, surety bonds, cash margin or collateral held in escrow for varying levels of future revenues. We continue to closely monitor our producer customer base since a majority of our customers 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,
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 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:
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.
(a)Exhibits, Financial Statements and Financial Statement Schedules:
1.Financial Statements:
See Index Page for Financial Statements
2.Financial Statement Schedules:
Schedule I: Parent Only Condensed Financial Statements
Schedule II: Valuation and Qualifying Accounts
Other financial statement schedules have been omitted because they are either not required, are immaterial or are not applicable
or because equivalent information has been included in the financial statements, the notes thereto or elsewhere herein.
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
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.
As
described in Note 2 to the consolidated financial statements, the Partnership recognizes revenues for services and products under revenue contracts as obligations to perform services or deliver/sell products under the contracts are satisfied. For a significant customer contract 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.
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.
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.
Accounts
receivable, less allowance for doubtful accounts of $i0.6 million and $i0.9 million at December 31,
2021 and 2020
i378.0
i262.2
Inventory
i156.5
i89.1
Assets from price risk management activities
i42.1
i27.2
Prepaid
expenses and other current assets
i14.8
i13.4
Total
current assets
i604.7
i405.9
Property, plant and equipment
i3,771.5
i3,759.6
Less:
accumulated depreciation
i992.1
i842.5
Property,
plant and equipment, net
i2,779.4
i2,917.1
Intangible
assets
i1,126.1
i1,126.1
Less:
accumulated amortization
i393.2
i331.8
Intangible
assets, net
i732.9
i794.3
Goodwill
i138.6
i138.6
Operating
lease right-of-use assets, net
i27.4
i36.8
Investments
in unconsolidated affiliates
i155.8
i943.7
Other
non-current assets
i6.9
i7.3
Total assets
$
i4,445.7
$
i5,243.7
Liabilities
and capital
Current liabilities:
Accounts payable
$
i336.5
$
i160.3
Accrued
expenses and other liabilities
i147.1
i122.0
Liabilities
from price risk management activities
i114.6
i76.3
Contingent
consideration - current portion
i—
i19.0
Current
portion of long-term debt
i0.2
i0.2
Total current
liabilities
i598.4
i377.8
Long-term debt, less current portion
i2,052.1
i2,483.8
Contingent
consideration
i—
i38.0
Other
long-term liabilities
i258.7
i253.3
Deferred
income taxes
i2.3
i2.7
Total
liabilities
i2,911.5
i3,155.6
Commitments
and contingencies (Note 10)
i
i
Interest of non-controlling partner in subsidiary
i434.6
i432.7
Crestwood
Equity Partners LP partners' capital (ii62,991,511/
common units issued and outstanding at December 31, 2021 and ii73,970,208/
common and subordinated units issued and outstanding at December 31, 2020)
i487.6
i1,043.4
Preferred
units (iiii71,257,445///
units issued and outstanding at December 31, 2021 and 2020)
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.
As described in Note 2 to the consolidated financial statements, the Partnership recognizes revenues for services and products under revenue contracts as obligations to perform services or deliver/sell products under the contracts are satisfied. For a significant customer contract 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.
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.
Note 1 – iOrganization
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 i99.9% limited partnership interest in Crestwood Midstream and Crestwood Gas Services GP LLC (CGS GP), a wholly-owned subsidiary of Crestwood Equity, owns a i0.1%
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 $i268 million to (i) acquire approximately i11.5 million
CEQP common units, i0.4 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 i1%
of the limited partner interests in Crestwood Holdings LP) in March 2021; and (ii) acquire the general partner and the remaining i99% 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 – iBasis
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,
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
i
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.
i
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.
iCash
We consider all highly liquid investments with an original maturity of
less than three months to be cash.
iAccounts 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 $i0.7 million increase to our allowance for doubtful accounts and a $i0.7 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 i50% equity investment, also adopted the provisions of Topic 326 and we recorded a decrease of approximately $ii0.2/ 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.
iInventory
i
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):
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. iDepreciation
is computed using the straight-line method over the estimated useful lives of the assets, as follows:
Years
Gathering systems and pipelines
i15 - i20
Facilities
and equipment
i3 - i25
Buildings, rights-of-way and easements
i1
- i40
Office furniture and fixtures
i5- i10
Vehicles
ii5/
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 $i40.1 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 i12% discount rate, which are Level 3 fair value measurements. During 2020 and 2019, we recorded $i3.1 million
and $i4.3 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 $i19.9 million
(see Note 3 for a further discussion of the assets sale).
i
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.
Certain intangible assets are
amortized on a straight-line basis over their estimated economic lives, as follows:
Weighted-Average
Life
(years)
Customer accounts
i22
Revenue
contracts
i18
Trademarks
i10
/
i
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.
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 $i80.3 million
impairment of the goodwill attributed to that reporting unit during the year ended December 31, 2020.
iThe 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 $i1,736.8 million and $i1,479.6
million, respectively./
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.
iInvestments 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.
i
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.
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 isix years. Our net deferred financing costs are reflected as a reduction of long-term debt on our consolidated balance sheets.
/
i
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.
i
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.
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.
iCredit
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.
i
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 i90% 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
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.
iPrice 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.
iUnit-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 – iAcquisitions
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 $i162 million (NGL Asset Acquisition). The acquired assets include i7
MMBbls of NGL storage and iseven terminals, and resulted in an increase of approximately $i110 million
to our property, plant and equipment, $i50 million to our intangible assets and $i2 million
to our other assets and liabilities, net. The identifiable intangible assets primarily consist of customer accounts with a weighted-average remaining life of i20 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) i50% equity interest in
Jackalope Gas Gathering Services, L.L.C. (Jackalope) for approximately $i484.6 million (Jackalope Acquisition). The acquisition was funded through a combination of borrowings under the CMLP credit facility and the issuance of $i235
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 i50% 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 i100%
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
approximately $i2.8
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 i12%.
Those fair values are Level 3 fair value measurements and were developed by management with the assistance of a third-party valuation firm.
i
The following table summarizes the final valuation of the assets acquired and liabilities assumed at the acquisition date (in millions):
Cash
$
i22.5
Other
current assets
i30.9
Property, plant and equipment
i532.9
Intangible
assets
i306.0
Goodwill
i80.3
Current
liabilities
(i30.4)
Other long-term liabilities
(i21.5)
Estimated
fair value of 100% interest in Jackalope
i920.7
Less:
Elimination of equity investment in Jackalope
i226.7
Gain
on acquisition of Jackalope
i209.4
Total purchase price
$
i484.6
/
The
identifiable intangible assets primarily consists of a customer contract with a weighted-average remaining life of i17 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 i50%
equity interest in Jackalope (which was remeasured at fair value and derecognized) and, as a result, we recognized a gain of approximately $i209.4 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 $i70.1 million of revenues and $i20.9 million of net income related to Jackalope’s operations.
i
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.
On October 1, 2020, we sold our gathering systems in the Fayetteville Shale to a third party for approximately $i23 million, and during the year ended December 31, 2020, we recognized a loss on the sale of approximately $i19.9 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 $i44.4 million of property, plant and equipment, net and a decrease of approximately $i1.4 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 – iCertain Balance Sheet Information
Property,
Plant and Equipment
i
Property, plant and equipment consisted of the following (in millions):
Gathering systems and pipelines and related assets
$
i1,052.5
$
i1,035.2
$
i1,195.2
$
i1,178.0
Facilities
and equipment
i2,200.6
i2,193.5
i2,385.8
i2,378.6
Buildings,
land, rights-of-way, storage rights and easements
i391.8
i389.0
i395.5
i392.7
Vehicles
i17.0
i13.9
i14.5
i12.1
Construction
in process
i64.7
i83.6
i64.7
i83.6
Finance
leases
i12.3
i13.3
i12.3
i13.3
Office
furniture and fixtures
i32.6
i31.1
i32.8
i31.3
i3,771.5
i3,759.6
i4,100.8
i4,089.6
Less:
accumulated depreciation
i992.1
i842.5
i1,193.0
i1,028.3
Total
property, plant and equipment, net
$
i2,779.4
$
i2,917.1
$
i2,907.8
$
i3,061.3
/
Depreciation. CEQP’s
depreciation expense totaled $i180.9 million, $i174.8 million and $i139.5
million for the years ended December 31, 2021, 2020 and 2019. CMLP’s depreciation expense totaled $i195.1 million, $i188.9
million and $i153.5 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 $i0.4
million, $i2.7 million and $i14.4 million related to certain expansion projects.
Intangible Assets
Our
intangible assets consisted of the following (in millions):
(1)This
amount includes $i49.8 million related to customer accounts acquired in conjunction with the NGL Asset Acquisition which is further discussed in Note 3.
Amortization
expense related to our intangible assets for the years ended December 31, 2021, 2020 and 2019, was approximately $i61.4 million, $i60.7
million and $i54.6 million.
i
Estimated amortization of our
intangible assets for the next five years is as follows (in millions):
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.
i
The following table presents the changes in our net asset retirement obligations (in millions):
Net
asset retirement obligations at December 31(3)
$
i36.2
$
i35.1
(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 $i1.4 million and $i1.0
million of current ARO liabilities at December 31, 2021 and 2020.
/
Note 6 - iInvestments
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 $i1.195 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 $i15.4 million
related to the Second Closing.
In conjunction with the Initial Closing and Second Closing, we recorded a $i155.6 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 $i51.3 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 $i3.1 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.
i
Our net investments in and earnings (loss) from our unconsolidated affiliates are as follows (in millions, unless otherwise stated):
(1)On
April 9, 2019, Crestwood Niobrara acquired Williams’s i50% equity interest in Jackalope and, as a result, Crestwood Niobrara controls and owns i100%
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):
(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 $i21.4 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 $i5.5 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 $i8.2 million, and this excess amount is not subject to amortization.
(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 i50% 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 $iii1.3//
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 $i0.4 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 $i0.1 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.
(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 $i613.9 million as our proportionate share of the gross proceeds received from the sale. We utilized approximately $i3 million
of these proceeds to pay transaction costs related to the sale described above, $i40 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 $i8.5
million.
(2)In January 2022, we made cash contributions of approximately $i6.0 million and $i8.5
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 $i57 million
plus accrued interest of $i2.1 million to CEGP.
Note 7 – iRisk
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
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. iThe
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):
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
i
The notional amounts of our derivative financial instruments include the following:
Propane, ethane, butane, heating oil and crude oil (MMBbls)
i71.6
i75.8
i72.7
i76.5
Natural
gas (Bcf)
i31.9
i43.4
i22.6
i28.6
/
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 i37 months or less; however, i87%
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.
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)
$
i57.9
$
i38.5
Broker-related
net derivative asset position
$
i104.8
$
i35.9
Broker-related
cash collateral received
$
i76.8
$
i18.3
Cash
collateral received, net
$
i11.4
$
i12.4
(1) At
December 31, 2021 and 2020, we posted $i1.5 million and less than $i0.1
million of collateral associated with these derivatives.
/
Note 8 – iFair 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.
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):
(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.
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). iThe 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):
(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 ifive-year $i1.5
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 $i1.25 billion to $i1.5 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 $i350 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 $i25
million for same-day swing line advances and a sub-limit up to $i350 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 $i1.5
billion credit agreement. We recognized a loss on extinguishment of debt of approximately $i0.8 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,
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 i0.50%;
(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 i1% per annum; plus a margin varying from i0.50%
to i1.50% depending on Crestwood Midstream’s most recent consolidated total leverage ratio; or
•Adjusted Term SOFR plus a margin varying from i1.50%
to i2.50% 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 i0.30%
to i0.50% 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 i5.50
to 1.0, a consolidated EBITDA to consolidated interest expense ratio (as defined in its credit agreement) of not less than i2.50 to 1.0, and a senior secured leverage ratio (as defined in its credit agreement) of not more than i3.50 to
1.0. At December 31, 2021, the net debt to consolidated EBITDA was approximately i3.53 to 1.0, the consolidated EBITDA to consolidated interest expense was approximately i4.93
to 1.0, and the senior secured leverage ratio was i0.48 to 1.0.
At December 31, 2021, Crestwood Midstream had $i961.7
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 $i6.3 million and $i23.9
million. The interest rates on borrowings under the credit facility were between i1.90% and i4.00% at December 31, 2021 and i2.40%
and i4.50% at December 31, 2020. The weighted-average interest rates on outstanding borrowings as of December 31, 2021 and 2020 was i1.91%
and i2.45%.
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 i6.25% 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 $i687.2 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 $i6.7 million during the year ended December 31, 2021, and paid approximately $i8.6 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 $i12.6 million to repurchase and cancel approximately $i12.8 million
of the 2023 Senior Notes.
2025 Senior Notes. The i5.75% 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 $i600
million of i5.625% 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 $i591.1
million were used to fund the acquisition of the remaining i50% equity interest in Jackalope.
2029 Senior Notes. In January 2021, Crestwood Midstream issued $i700 million
of i6.00% 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 $i691.0 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 $i1,232.3
million as of December 31, 2021.
Maturities
i
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):
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 $i19.5 million to Linde related to this matter,
and Linde claims remaining unpaid invoices of approximately $i36 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 $i16.8 million and $i10.4
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 $i0.1 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.
At December 31, 2021 and 2020, our accrual of approximately $i1.0
million and $i1.3 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 $i1.0
million to $i1.9 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. iThe following table summarizes CEQP’s and CMLP’s self-insurance reserves (in millions):
(1)At
December 31, 2021, CEQP and CMLP classified approximately $i3.5 million and $i2.9
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 $i2,760.9
million, of which approximately $i2,493.6 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 $i15.6
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.
The
following table presents the weighted-average remaining lease term and the weighted-average discount rate associated with our operating and finance leases:
(1) Remaining
terms vary from ione year to i18 years as of December 31, 2021.
(2) Remaining terms vary from ione
year to ifive years as of December 31, 2021.
(3) As of December 31, 2021 and 2020, we utilized discount rates ranging from i1.5%
to i8.3% and i2.6% to i12.8%,
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 ione
year to i10 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.
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):
(1)Approximately
$i13.4 million, $i17.6 million and $i17.5 million
is included in costs of product/services sold, $i3.9 million, $i6.7 million and $i8.0 million
is included in operations and maintenance expense and $i2.7 million, $i2.9 million and $i2.8 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.
(2)Includes short-term and variable lease costs of approximately $i2.2 million, $i5.5 million
and $i3.7 million for the years ended December 31, 2021, 2020 and 2019.
(3)Included in service revenues on our consolidated statements of operations.
(4)Included in depreciation, amortization and accretion expense on our consolidated statements of operations.
(5)Included
in interest and debt expense, net on our consolidated statements of operations.
The following table presents supplemental cash flow information for our operating and finance leases (in millions):
Right-of-use
assets obtained in exchange for lease obligations
Operating leases
$
i—
$
i2.1
$
i4.2
Finance
leases
$
i1.5
$
i0.4
$
i1.8
ii
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):
Note 12 – iPartners’ 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 i11.5 million
CEQP common units and i0.4 million subordinated units of CEQP from Crestwood Holdings for approximately $i268 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 $i7.6 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 i45 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).
On
February 14, 2022, we paid a distribution of $i0.625 per limited partner unit to unitholders of record on iFebruary 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 $i0.2111 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 $i0.2567 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 i2.8125% per quarter.
During each of the years ended December 31, 2021, 2020 and 2019, we paid cash distributions to our preferred unitholders of approximately
$iii60.1// million.
On February 14, 2022, we made a cash distribution of approximately $i15.0 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 $i509.7 million, $i242.6
million and $i235.8 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 $i175
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 $i235 million in new Series A-3
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 i50% 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 i50%
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 $i100
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 $i100
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.
i
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):
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 $i40.2 million, $i37.1
million and $i25.0 million to Jackalope Holdings. In January 2022, Crestwood Niobrara paid a cash distribution of $i10.3 million
to Jackalope Holdings with respect to the fourth quarter of 2021.
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 $i33.2
million and $i29.7 million related to restricted, phantom, and performance units, which will be amortized during the next ithree
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 ione year. We recognized compensation expense of approximately $i39.5
million, $i35.1 million and $i45.1 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 $i4.4 million and $i1.4
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 i2,530,862 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 ithree-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 ithree 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 ithree-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 i50% and i200%, 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.
The
following table summarizes information regarding restricted, phantom and performance unit activity during the years ended December 31, 2021, 2020 and 2019.
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 i423,330,
i581,608 and i336,548 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 i10% of the employees’ eligible compensation,
not to exceed $i25,000 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 i10%
of participating employees’ payroll deductions to purchase additional Crestwood common units for participating employees. The board of directors of our general partner authorized i1,500,000 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, i9,932,
i29,784 and i6,341 common units were purchased under the plan.
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. iThe following table summarizes information regarding the weighted-average of common units excluded during the years ended December 31, 2021, 2020 and 2019(in millions):
(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):
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 i90%
of their salary, subject to statutory limits, which was $i19,500 in 2021, $i19,500
in 2020 and $i19,000 in 2019. We match i100% of participants’
basic contributions up to i6% of eligible compensation. Employees may participate in the plans immediately and certain employees are not eligible for matching contributions until after a i90-day
waiting period. During the years ended December 31, 2021, 2020 and 2019, aggregate matching contributions made by us were $i4.0 million, $i4.2
million and $i4.7 million.
Note 16 – iSegments
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 ithree 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.
i
Below is a reconciliation
of CEQP’s and CMLP’s net income (loss) to EBITDA (in millions):
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 $i187.4
million, $i42.9 million and $i42.1
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.
Total
Crestwood Midstream purchases of property, plant and equipment
$
i81.3
$
i168.3
$
i455.5
Crestwood
Equity
Corporate
i1.9
i—
i—
Total
Crestwood Equity purchases of property, plant and equipment
$
i83.2
$
i168.3
$
i455.5
Major
Customers
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
$i333.9 million
(reflected primarily in our storage and logistics segment) accounted for approximately 10% of our total consolidated revenues at CEQP and CMLP.
Note 17 - iRevenues
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 $i331.0 million and $i219.9
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 i15
years.
i
The following table summarizes our contract assets and contract liabilities (in millions):
(1)During
the year ended December 31, 2021, we recognized revenues of approximately $i14.0 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.
/
i
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
$
i72.7
2023
i52.6
2024
i31.7
2025
i0.1
Total
$
i157.1
/
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
iThe
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.
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.
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.
i
Components of our deferred income taxes at December 31, 2021 and 2020 are as follows (in millions).
(1)Relates
to the basis difference in the stock of a company.
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 – iRelated 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 $i0.6
million, $i3.5 million, and $i9.9 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.
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.
i
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):
Costs
of product/services sold at CEQP and CMLP(2)
$
i136.8
$
i21.0
$
i45.4
Operations
and maintenance expenses at CEQP and CMLP charged to our unconsolidated affiliates(3)
$
i22.2
$
i21.8
$
i25.9
General
and administrative expenses charged by CEQP to CMLP, net(4)
$
i35.5
$
i31.1
$
i41.4
General
and administrative expenses at CEQP charged to (from) Crestwood Holdings, net(5)
$
i4.8
$
i6.5
$
(i0.6)
(1)Includes
(i) $i26.2 million, $i27.8 million and $i1.0
million during the years ended December 31, 2021, 2020 and 2019 related to the sale of NGLs to a subsidiary of Crestwood Permian; (ii) $i1.0 million during the year ended December 31, 2021 related to a compressor lease with a subsidiary of Crestwood Permian (iii) $i1.2
million during the year ended December 31, 2019 related to the sale of natural gas to a subsidiary of Stagecoach Gas: and (iv) $i0.7 million during the year ended December 31, 2019 related to the sale of NGLs to our affiliate, Westlake Chemical Corporation.
(2)Includes (i) $i110.7
million, $i20.0 million and $i19.0 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) $i11.6 million and $i0.6
million during the years ended December 31, 2021 and 2020 related to purchases of natural gas from a subsidiary of Tres Holdings; (iii) $i14.5 million, $i0.4
million and $i23.9 million during the years ended December 31, 2021, 2020 and 2019 related to purchases of NGLs from Ascent Resources - Utica, LLC (Ascent); (iv) $i0.2
million during the year ended December 31, 2019 related to purchases of NGLs from Blue Racer Midstream, LLC (Blue Racer); and (v) $i2.3 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 $i3.4 million to Stagecoach Gas, $i4.9
million to Tres Holdings, and $i13.9 million to Crestwood Permian under these agreements. During the year ended December 31, 2020, we charged $i6.6
million to Stagecoach Gas, $i4.1 million to Tres Holdings and $i11.1
million to Crestwood Permian under these agreements. During the year ended December 31, 2019, we charged $i7.5 million to Stagecoach Gas, $i4.4
million to Tres Holdings, $i13.5 million to Crestwood Permian and $i0.5
million to Jackalope under these agreements.
(4)Includes $i39.5 million, $i35.1
million and $i45.1 million of unit-based compensation charges allocated from CEQP to CMLP during the years ended December 31, 2021, 2020 and 2019. In addition, includes $i4.0
million, $i4.0 million and $i3.7
million of CMLP’s general and administrative costs allocated to CEQP during the years ended December 31, 2021, 2020 and 2019.
(5)Includes a $i4.6 million and $i4.4
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 $i1.9 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 $i0.2 million, $i2.1
million and $i1.3 million of its general and administrative costs to Crestwood Holdings.
/
i
The
following table shows accounts receivable and accounts payable from our affiliates as of December 31, 2021 and 2020 (in millions):
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 $i1.8 billion. Pursuant to the merger agreement, Oasis Petroleum Inc. (Oasis Petroleum) received $i150 million
in cash plus approximately i21.0 million newly issued CEQP common units in exchange for its i33.8 million
common units held in Oasis Midstream. In addition, Oasis Midstream’s public unitholders received approximately i12.9 million newly issued CEQP common units in exchange for the approximately i14.8 million
Oasis Midstream common units held by them. Additionally, under the merger agreement Oasis Petroleum received a $i10 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 $i2.9 million of transaction costs related to the Merger, which are included in general and administrative expenses in our consolidated
statements of operations.
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.
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.
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 $i509.7 million, $i242.6
million and $i235.8 million.
