Table of hazardous liquids pipelines. The final rule imposes more stringent standards that determine how operators repair aging and high-risk infrastructure, increase the frequency of tests that assess pipeline conditions, and require operators to report more operating and safety data. Among other things, the final rule: (i) extends an operator’s reporting requirements to gravity and hazardous liquids gathering pipelines; (ii) requires operators to inspect pipelines in areas affected by extreme weather and similar events within a certain timeframe; (iii) impose new requirements to periodically “pig” transmission pipelines in areas outside of high consequence areas; (iv) broadens the requirement for the use of leak detection systems; and (v) increases the use of inline inspection tools. However, the date of implementation of this final rule by publication in the Federal Registrar remains uncertain following the January 2017 change in Presidential administrations.Contents

We are evaluating PHMSA’s new rules, and we cannot predict the precise impact that compliance with the new rules will have on our business. The new rules may, among other things, require us or our joint ventures to install new or modified safety controls, undertake additional capital projects or conduct maintenance programs on an expedited basis. The costs of complying with the new PHMSA rules, as well as other rules under consideration by PHMSA or other agencies, could have a material adverse effect on our cash flows and results of operations.

~~Our business involves many hazards and risks, some of which may not be fully covered by insurance.~~

~~Our operations are subject to many risks inherent in gathering, processing, storage and transportation segments of the energy midstream industry, such as:~~

~~damage to pipelines and plants, related equipment and surrounding properties caused by natural disasters and acts of terrorism;~~

~~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 environmental 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 potentially subjects us to substantial penalties, fines and damages from regulatory agencies and individual landowners. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. For example, we do not have any property insurance on any of our underground pipeline systems that would cover damage to the pipelines. We are also not insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could result in a material adverse effect on our business, financial condition, results of operations and ability to make distributions.

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

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

We do not own all of the land on which our pipelines and facilities (particularly our G&P facilities) have been constructed, which subjects us to the possibility of more onerous terms or increased costs to obtain and maintain valid easements and rights-of-way. We obtain standard easement rights to construct and operate pipelines on land owned by third parties, and our rights frequently revert back to the landowner after we stop using the easement for its specified purpose.

Therefore, these easements exist for varying periods of time. Our loss of easement rights could have a material adverse effect on our ability to operate our business, thereby resulting in a material reduction in our revenue, earnings 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 of 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, our operations could be disrupted and/or customer information could be stolen. The occurrence of one of these events could cause a substantial decrease in revenues, increased costs to respond or other financial loss, damage to reputation, increased regulation or litigation 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.

Risks Inherent in an Investment in UsOur Equity

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay quarterly distributions to our common and preferred unitholders.

We may not have sufficient cash each quarter to pay quarterly distributions to our common unitholders or, alternatively, we may reallocate a portion of our available cash to debt ~~repayment~~repayments or capital ~~investment.~~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 ~~repaid.~~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 ~~operating~~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 our capital ~~expenditures we make;~~expenditures; 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.

~~Since 2014, the dramatic decrease~~Decreases in commodity prices ~~has~~can negatively ~~impacted~~impact 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 ~~unit holders.~~unitholders.

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We may issue additional common units without common unitholder approval, which would dilute existing common ~~unit holder~~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.

~~Unitholders have less ability to elect or remove management than holders of common stock in a corporation.~~

~~Unlike~~Our partnership agreement restricts the ~~holders of common stock in a corporation, unitholders have only limited~~ voting rights on matters affecting our business, and therefore limited ability to influence management’s decisions regarding our business. Unitholders did not elect, and do not have the right to elect, our general partnerof unitholders owning 20% or ~~its board of directors on an annual or other continuing basis. The board of directors~~more of our ~~general partner is effectively chosen by Crestwood Holdings, the general partner~~common units and ~~only voting member of Holdings LP, the sole member of our general partner. Although our general partner~~ has a fiduciary duty to manage our partnership in a manner beneficial to us and our unitholders, the directors of our general partner also have a fiduciary duty to manage our general partner in a manner beneficial to its sole member, Holdings LP.other governance differences from typical corporations.

If unitholders are dissatisfied with the performance of our general partner, they will have little ability to remove our general partner. Our general partner generally may not be removed except upon the vote of the holders of 66⅔% of the outstanding units voting together as a single class.

~~Our unitholders’~~Unitholders’ voting rights are ~~further~~ restricted by a provision in our partnership agreement ~~providing~~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 partnership agreement restricts the voting rights~~

Table of ~~unitholders owning 20% or more of our common units.~~Contents

Our partnership agreement restricts unitholders’ voting rights by providing that any units held by a person or group that owns 20% or more of any class of units then outstanding, other than our general partner and its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter.

Crestwood Holdings and its affiliates may sell its common units in the public or private markets, and such sales could have an adverse impact on the trading price of the common units. Additionally, Crestwood Holdings may pledge or hypothecate its common units or is interest in Crestwood Holdings LP.

As of December 31, 2017, Crestwood Holdings and its affiliates beneficially held an aggregate of 17,908,700 limited partner units. The sale of any or all of these units in the public or private markets could have an adverse impact on the price of the common units or on any trading market on which the common units are traded. Additionally, Crestwood Holdings may pledge or hypothecate its common units or its interest in Crestwood Holdings LP (Holdings LP), the sole member of our general partner, or its subsidiaries. Such pledge or hypothecation may include terms and conditions that might result in an adverse impact on the trading price of our common units.

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

Our preferred units contain covenants preventing us from taking certain actions without the approval of the holders of a majority or a super-majority of the preferred units, depending on the action as described below. The need to obtain the approval of holders of the preferred units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of its ~~unit holders.~~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 ~~unit holders~~unitholders that could impair our ability to consummate (or increase the cost of consummating) a change-in-control transaction, which could result in less economic benefits accruing to our common ~~unit holders.~~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. Furthermore, there is no restriction in our partnership agreement on the ability of the owner of our general partner, Holdings LP, from transferring its ownership interest in our general partner to a third party. Additionally, Holdings LP’s general partner interest in our general partner is pledged as collateral under a Credit Agreement between Crestwood Holdings and various lenders (Holdings Credit Agreement). In the event of a default by Crestwood Holdings under the Holdings Credit Agreement, the lenders may foreclose on the pledged general partner interest and take or transfer control of our general partner without unitholder consent. The new owner of our general partner would then be in a position, 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.”

Potential conflicts of interest may arise among our general partner, its affiliates and us. Our general partner and its affiliates have limited fiduciary duties to us, which may permit them to favor their own interests to the detriment of us.

Conflicts of interest may arise among our general partner and its affiliates, on the one hand, and us, on the other hand. As a result of these conflicts, our general partner may favor its own interests and the interests of its affiliates over our interests. These conflicts include, among others, the following:

~~Our general partner is allowed to take into account the interests of parties other than us in resolving conflicts of interest, which has the effect of limiting its fiduciary duties to us.~~

Our general partner has limited its liability and reduced its fiduciary duties under the terms of our partnership agreement, while also restricting the remedies available for actions that, without these limitations, might constitute breaches of fiduciary duty. As a result of purchasing our units, unitholders consent to various actions and conflicts of interest that might otherwise constitute a breach of fiduciary or other duties under applicable state law.

Our general partner determines the amount and timing of our investment transactions, borrowings, issuances of additional partnership securities and reserves, each of which can affect the amount of cash that is available for distribution.

~~Our general partner determines which costs it and its affiliates have incurred are reimbursable by us.~~

Our partnership agreement does not restrict our general partner from causing us to pay it or its affiliates for any services rendered, or from entering into additional contractual arrangements with any of these entities on our behalf, so long as the terms of any such payments or additional contractual arrangements are fair and reasonable to us.

~~Our general partner controls the enforcement of obligations owed to us by it and its affiliates.~~

~~Our general partner decides whether to retain separate counsel, accountants or others to perform services for us.~~

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

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

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

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

•provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.

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

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

Table of ~~December 31, 2017, the directors and executive officers of~~Contents

Risks Related to our ~~general partner owned approximately 6% of our common units.~~Tax Matters

~~Tax Risks to Common Unitholders~~

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 ~~common~~ 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 ~~common~~ unitholders, likely causing a substantial reduction in the value of our ~~common~~ 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 ~~common~~ 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 ~~common~~ units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. ~~From time to time, members~~Members of Congress ~~propose~~have frequently proposed and ~~consider~~considered substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. ~~Although there is no current legislative proposal, a prior legislative proposal would~~Recent proposals have ~~eliminated~~provided for the expansion of the qualifying income exception tofor publicly traded partnerships in certain circumstances and other proposals have provided for the ~~treatment~~total elimination of ~~all publicly-traded partnerships as corporations~~the qualifying income exception upon which we rely for our ~~treatment as a~~ partnership ~~for~~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 ~~purposes.~~

~~In addition, in January 2017, final regulations regarding which activities give rise to~~laws or the Treasury Department’s interpretation of the qualifying income ~~within the meaning of Section 7704 of the Internal Revenue Code were published~~rules in ~~the Federal Registrar. The final regulations are effective as of January 19, 2017, and apply to taxable years beginning on or after January 19, 2017. We do not believe the final regulations affect~~a manner that could impair our ability to ~~be treated~~qualify as a publicly traded partnership ~~for U.S. federal income tax purposes.~~

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 ~~of these~~ changes or other proposals will ultimately be enacted. Any ~~such~~future legislative changes could negatively impact the value of an investment in our ~~common~~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 ~~common~~ 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 ~~common~~ units and the price at which they trade. In addition, the costs of

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any contest with the IRS will be borne indirectly by ~~you~~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 ~~adjustment~~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~~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 ~~adjustment~~adjustments directly from us. To the extent possible under ~~the new~~these 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 ~~adjustment~~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~~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 ~~common~~ units could be more or less than expected.

If ~~you~~our unitholders sell ~~your common~~their units, ~~you~~they will recognize a gain or loss equal to the difference between ~~your~~the amount realized and ~~your~~the tax basis in those ~~common~~ units. Because distributions in excess of ~~your~~our unitholders’ allocable share of our total net taxable income result in a reduction in ~~your~~their tax basis in ~~your common~~their units, the amount, if any, of such prior excess distributions with respect to the units ~~you~~they sell will, in effect, become taxable income to ~~you~~them if ~~you~~they sell such units at a price greater than ~~your~~their tax basis in those ~~common~~ units, even if the price ~~you~~they receive is less than ~~your~~their original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if ~~you~~they sell ~~your~~their units ~~you~~they may incur a tax liability in excess of the amount of cash ~~you receive~~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, ~~you~~our unitholders may recognize both ordinary income and capital loss from the sale of ~~your~~their units if the amount realized on a sale of ~~your~~their units is less than ~~your~~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 ~~you~~our unitholders sell ~~your~~their units, ~~you~~they may recognize ordinary income from our allocations of income and gain to ~~you~~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 ~~30%~~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~~income. If our business interest is subject to limitation under

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these rules, our unitholders will be limited in ~~the case~~their ability to deduct their share of ~~taxable years beginning before January 1, 2022,~~ any ~~deduction allowable for depreciation, amortization, or depletion.~~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 ~~our~~ owning ~~common~~our units that may result in adverse tax consequences to them.

Investment in our ~~common~~ 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. ~~Further, with respect to taxable years beginning after December 31, 2017,~~Additionally, all or part of any gain recognized by such tax-exempt organization upon a ~~tax-exempt entity with more than one unrelated trade~~sale or ~~business (including by attribution from investment in a partnership such as ours that is engaged in one or more unrelated trade or business) is required to compute the~~other disposition of our units may be unrelated business taxable income ~~of such tax-exempt entity separately with respect~~and may be taxable to each such trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax-exempt entities to utilize losses from an investment in our partnership to offset unrelated business taxable income from another unrelated trade or business and vice versa.them. Tax-exempt entities should consult a tax advisor before investing in our ~~common~~ 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 (“effectively connected income”).~~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.~~non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a ~~Non-U.S.~~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.

~~The Tax Cut and Jobs Act imposes~~ In addition to the withholding tax imposed on distributions of effectively connected income, distributions to a non-U.S. unitholder will also be subject to a 10% withholding ~~obligation~~tax on the amount of ~~10%~~any distribution in excess of our cumulative net income.As we do not compute our cumulative net income for such purposes due to the complexity of the ~~amount realized upon~~calculation and lack of clarity in how it would apply to us, we intend to treat all of our distributions as being in excess of our cumulative net income for such purposes and subject to such 10% withholding tax.Accordingly, distributions to a ~~Non-U.S. unitholder’s sale or exchange~~non-U.S. unitholder will be subject to a combined withholding tax rate equal to the sum of the highest applicable effective tax rate and 10%.

Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or ~~business. However, due~~business is generally required to ~~challenges~~withhold 10% of ~~administering~~the amount realized by the transferor unless the transferor certifies that it is not a ~~withholding obligation applicable to open market trading and other complications,~~non-U.S. person. While the ~~IRS has temporarily suspended~~determination of a partner’s amount realized generally includes any decrease of a partner’s share of the ~~application~~partnership’s liabilities, the Treasury regulations provide that the amount realized on a transfer of ~~this withholding rule to open market transfers of~~an interest in a publicly traded ~~partnerships pending promulgation~~partnership, such as our units, will generally be the amount of ~~regulations or other guidance that resolves~~gross proceeds paid to the ~~challenges. It is not clear if or when such regulations or other guidance~~broker effecting the applicable transfer on behalf of the transferor and thus will be ~~issued. Non-U.S.~~determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. For a transfer of interests in a publicly traded partnership that is effected through a broker on or after January 1, 2023, the obligation to withhold is imposed on the transferor’s broker. Current and prospective non-U.S. unitholders should consult atheir tax ~~advisor before investing~~advisors regarding the impact of these rules on an investment in our ~~common~~ units.

We will treat each purchaser of our ~~common~~ units as having the same tax benefits without regard to the specific ~~common~~ units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our ~~common~~ units.

Because we cannot match transferors and transferees of ~~common~~ units and because of other reasons, we ~~will adopt~~have adopted certain methods for allocating depreciation and amortization ~~positions~~deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to ~~those positions~~the use of these methods could adversely affect the amount of tax benefits available to ~~you.~~our unitholders. It also could affect the timing of these tax benefits or the amount of gain from ~~the~~any sale of our ~~common~~ units and could have a negative impact on the value of our ~~common~~ units or result in audit adjustments to ~~your~~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.

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A unitholder whose ~~common~~ units are the subject of a securities loan (i.e., a loan to a “short seller” to cover a short sale of ~~common~~ units) may be considered as having disposed of those ~~common~~ units. If so, he would no longer be treated for tax purposes as a partner with respect to those ~~common~~ 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 ~~common~~ units are the subject of a securities loan may be considered ~~as having~~to have disposed of the loaned units. In that case, hethey may no longer be treated for tax purposes as a partner with respect to those ~~common~~ 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 ~~common~~ units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those ~~common~~ 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 ~~loan~~tax advisor to ~~a short seller should~~determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their ~~common~~ 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 ~~common~~ units.

In addition to federal income taxes, our unitholders ~~will likely~~may be subject to other taxes, including state and local taxes, unincorporated business taxes, estate, inheritance or intangible taxes and ~~foreign~~non-U.S. taxes that are imposed by the various jurisdictions in which we doconduct business or own property ~~and~~now or in ~~which~~the future, even if they do not ~~reside. We own property and conduct business~~live in ~~various parts~~any of ~~the United States. Unitholders may~~those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in ~~many~~some or all of ~~the jurisdictions in which we do business or own property.~~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.~~U.S. federal, state, local and ~~foreign~~non-U.S. tax ~~returns.~~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, the 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.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

A description of our properties is included in Item 1. Business, and is incorporated herein by reference. We also lease office space for our corporate offices in Houston, Texas and Kansas City, Missouri.

We own or lease the property rights necessary to conduct our operations and we also lease and rely upon our customers’ property rights to conduct a substantial part of our ~~operations, and we own or lease the property rights necessary to conduct our storage and transportation~~ 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

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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 ~~15,~~10, and is incorporated herein by reference.

Item 4. Mine Safety Disclosures

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities

~~Crestwood Equity~~. Crestwood Equity’s common units representing limited partner interests are traded on the NYSE under the symbol “CEQP.” ~~The following table sets forth~~

At the ~~range~~close of ~~high and low sales prices of the common units, as reported by the NYSE, as well as the amount of cash distributions declared per common unit for the periods indicated.~~

Quarters Ended: Low High
Cash
Distribution
Per Unit
2017
December 31, 2017 $ 22.15
$ 26.10
$ 0.600
September 30, 2017 22.30
26.65
0.600
June 30, 2017 20.00
27.35
0.600
March 31, 2017 24.35
28.30
0.600
2016
December 31, 2016 $ 18.51
$ 25.70
$ 0.600
September 30, 2016 18.67
22.22
0.600
June 30, 2016 10.40
23.59
0.600
March 31, 2016 7.90
21.56
0.600

~~The last reported sale price of Crestwood Equity’s common units on the NYSE~~business on February ~~12, 2018, was $26.95. As of that date,~~17, 2023, Crestwood Equity had ~~71,231,599~~105,356,560 common units issued and outstanding, which were held by ~~259~~227 unitholders of record.

~~Distribution Policy~~

~~Preferred Units~~. We are required to make quarterly distributions to our preferred unitholders. The holders of the Preferred Units are entitled to receive fixed quarterly distributions of $0.2111 per unit. Through the quarter ending September 30, 2017 (the Initial Distribution Period), distributions on the Preferred Units could be made in additional Preferred Units, cash, or a combination thereof, at our election. Through and for the quarter ended June 30, 2017, we paid distributions on our Preferred Units through the issuance of additional Preferred Units. The number of units distributed was calculated as the fixed quarterly distribution of $0.2111 per unit divided by the cash purchase price of $9.13 per unit. We accrued the fair value of such distribution at the end of the quarterly period and adjusted the fair value of the distribution on the date the additional Preferred Units were distributed. Distributions on the Preferred Units following the Initial Distribution Period will be paid in 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 Unit holders. If we fail to pay the full amount payable to our Preferred Unit holders in cash following the Initial Distribution Period, then (x) the fixed quarterly distribution on the Preferred Units will increase to $0.2567 per unit, and (y) we will not be permitted to declare or make any distributions to our common unitholders until such time as all accrued and unpaid distributions on the Preferred Units have been paid in full in cash. In addition, if we fail to pay in full any Preferred Distribution (as defined in our partnership agreement), the amount of such unpaid distribution will accrue and accumulate from the last day of the quarter for which such distribution is due until paid in full, and any accrued and unpaid distributions will be increased at a rate of 2.8125% per quarter.

~~Common Units~~. Crestwood Equity makes quarterly distributions to its partners within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to our available cash for such quarter. Available cash generally means, with respect to each fiscal 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 our business, including but not limited to, debt repayments, unit buybacks or capital investment;~~

~~comply with applicable law, any of our 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 subsequent to the end of the quarter. Working capital borrowings are generally borrowings that are made under our revolving credit facility and in all cases are used solely for working capital purposes or to pay distributions to its partners.

~~On February 14, 2018, Crestwood Equity paid a distribution of~~ ~~$0.60~~ ~~per limited partner unit ($2.40 per limited partner unit on an annualized basis) to its unitholders of record on February 7, 2018.~~

Issuer Purchases of Equity Securities

~~For~~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 expired on December 31, 2022. No units were purchased under the ~~year~~program during the years ended December 31, ~~2017, we relinquished 206,600 common units to cover payroll taxes upon the vesting of restricted units.~~ 2022 and 2021.

Equity Compensation Plan Information

~~The following table sets forth in tabular format, a summary of the Crestwood Equity~~For information on our equity compensation ~~plan information as of December 31, 2017:~~plans, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13.



~~Plan category~~	~~Number of~~ ~~securities to be~~ ~~issued upon~~ ~~exercise of~~ ~~outstanding~~ ~~options, warrants~~ ~~and rights~~	~~Weighted-~~ ~~average~~ ~~exercise~~ ~~price of~~ ~~outstanding~~ ~~options,~~ ~~warrants~~ ~~and rights~~		~~Number of securities~~ ~~remaining available for~~ ~~future issuance under~~ ~~equity compensation~~ ~~plans (excluding~~ ~~securities reflected in~~ ~~column (a))~~
	~~(a)~~	~~(b)~~		~~(c)~~
~~Equity compensation plans approved by security holders~~	—	$	—	—
~~Equity compensation plans not approved by security holders~~	—	$	—	~~4,157,742~~
~~Total~~	—	$	—	~~4,157,742~~

Item 6. Selected Financial Data

~~Crestwood Midstream~~. This information has been omitted from this report pursuant to the ~~reduced disclosure format permitted by General Instruction I to Form 10-K.~~final SEC rules in Release No. 34-90459 which permits the elimination of Item 301 of Regulation S-K.

~~Crestwood Equity.~~ Crestwood Equity’s consolidated financial statements were originally the financial statements of Legacy Crestwood GP prior to being acquired by us on June 19, 2013. Our acquisition of Legacy Crestwood GP was accounted for as a reverse acquisition under the purchase method of accounting in accordance with the accounting standards for business combinations. The accounting for a reverse acquisition results in the legal acquiree (Legacy Crestwood GP) being the acquirer for accounting purposes. Although Legacy Crestwood GP was the acquirer for accounting purposes, we were the acquirer for legal purposes; consequently, we changed our name from Crestwood Gas Services GP, LLC to Crestwood Equity Partners LP.

The income statement and cash flow data for each of the three years ended December 31, 2017 and balance sheet data as of December 31, 2017 and 2016 were derived from our audited financial statements. We derived the income statement and cash flow data for each of the two years ended December 31, 2014 and the balance sheet data as of December 31, 2015, 2014 and 2013 from our accounting records. The selected financial data is not necessarily indicative of results to be expected in future periods and should be read together with Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and Part IV, Item 15. Exhibits and Financial Statement Schedules included elsewhere in this report.

~~EBITDA and Adjusted EBITDA~~ - We believe that EBITDA and Adjusted EBITDA are widely accepted financial indicators of a company’s operational performance and its ability to incur and service debt, fund capital expenditures and make distributions. We believe that EBITDA and Adjusted EBITDA are useful to our investors because it allows them to use the same performance measure analyzed internally by our management to evaluate the performance of our businesses and investments without regard to the manner in which they are financed or our capital structure. EBITDA is defined as income before income taxes, plus debt-related costs (interest and debt expense, net, and gain (loss) on modification/extinguishment of debt) and depreciation, amortization and accretion expense. Adjusted EBITDA considers the adjusted earnings impact of our unconsolidated affiliates by adjusting our equity earnings or losses from our unconsolidated affiliates to reflect our proportionate share (based on the distribution percentage) of their EBITDA, excluding impairments. Adjusted EBITDA also considers the impact of certain significant items, such as unit-based compensation charges, gains and losses on long-lived assets, impairments of long-lived assets and goodwill, gains and losses on acquisition-related contingencies, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, certain costs related to our historical cost saving initiatives, the change in fair value of commodity inventory-related derivative contracts, costs associated with our 2017 realignment of our Marketing, Supply and Logistics operations and related consolidation and relocation of our corporate offices, 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.

Crestwood Equity Partners LP
Year Ended December 31,
2017 2016 2015 2014
2013 ⁽¹⁾

(in million, except per unit data)
Statement of Income Data:
Revenues $ 3,880.9
$ 2,520.5
$ 2,632.8
$ 3,931.3
$ 1,426.7

Operating income (loss) (79.4 ) (108.7 ) (2,084.8 ) 117.9
28.2

Loss before income taxes (167.4 ) (191.8 ) (2,305.1 ) (9.3 ) (49.6 )
Net loss (166.6 ) (192.1 ) (2,303.7 ) (10.4 ) (50.6 )
Net income (loss) attributable to Crestwood Equity Partners LP (191.9 ) (216.3 ) (1,666.9 ) 56.4
6.7

Performance Measures:
Diluted net income (loss) per limited partner unit: ⁽²⁾
$ (3.64 ) $ (3.55 ) $ (54.00 ) $ 3.30
$ 0.59

Distributions declared per limited partner unit⁽³⁾
$ 2.40
$ 3.175
$ 5.50
$ 5.50
$ 6.925

Other Financial Data:
EBITDA (unaudited)
$ 161.4
$ 152.9
$ (1,844.9 ) $ 403.1
$ 196.2

Adjusted EBITDA (unaudited)
395.4
455.6
527.4
495.9
297.7

Net cash provided by operating activities 255.9
346.1
440.7
283.0
188.3

Net cash provided by (used in) investing activities 38.7
867.2
(212.7 ) (483.0 ) (1,042.9 )
Net cash provided by (used in) financing activities (294.9 ) (1,212.2 ) (236.3 ) 203.6
859.7

Balance Sheet Data:
Property, plant and equipment, net $ 1,820.8
$ 2,097.6
$ 3,310.8
$ 3,893.8
$ 3,905.3

Total assets 4,284.9
4,448.9
5,762.8
8,421.7
8,476.0

Total debt, including current portion 1,492.2
1,523.7
2,502.9
2,356.8
2,218.8

Other long-term liabilities⁽⁴⁾
104.7
44.6
47.5
47.2
140.4

Partners’ capital 2,180.5
2,539.0
2,946.9
5,584.5
5,508.6

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Crestwood Equity Partners LP
Year Ended December 31,
2017 2016 2015 2014
2013 ⁽¹⁾

(in millions)
Reconciliation of Net Income to EBITDA and Adjusted EBITDA:
Net loss $ (166.6 ) $ (192.1 ) $ (2,303.7 ) $ (10.4 ) $ (50.6 )
Depreciation, amortization and accretion 191.7
229.6
300.1
285.3
167.9

Interest and debt expense, net 99.4
125.1
140.1
127.1
77.9

(Gain) loss on modification/extinguishment of debt 37.7
(10.0 ) 20.0
—
—

Provision (benefit) for income taxes (0.8 ) 0.3
(1.4 ) 1.1
1.0

EBITDA 161.4

152.9
(1,844.9 ) 403.1

196.2

Unit-based compensation charges 25.5
19.2
19.7
21.3
17.4

(Gain) loss on long-lived assets, net⁽⁵⁾
65.6
65.6
821.2
1.9
(5.3 )
Goodwill impairment⁽⁶⁾
38.8
162.6
1,406.3
48.8
4.1

Loss on contingent consideration⁽⁷⁾
57.0
—
—
8.6
31.4

(Earnings) loss from unconsolidated affiliates, net⁽⁸⁾
(47.8 ) (31.5 ) 60.8
0.7
0.1

Adjusted EBITDA from unconsolidated affiliates, net 80.3
61.1
25.3
6.9
2.5

Change in fair value of commodity inventory-related derivative contracts 2.2
14.1
5.4
(10.3 ) 10.7

Significant transaction and environmental-related costs and other items⁽⁹⁾
12.4
11.6
33.6
14.9
40.6

Adjusted EBITDA $ 395.4
$ 455.6
$ 527.4
$ 495.9
$ 297.7

Crestwood Equity Partners LP
Year Ended December 31,
2017 2016 2015 2014
2013 ⁽¹⁾

(in millions)
Reconciliation of Net Cash Provided by Operating Activities to EBITDA and Adjusted EBITDA:
Net cash provided by operating activities $ 255.9
$ 346.1
$ 440.7
$ 283.0
$ 188.3

Net changes in operating assets and liabilities (0.3 ) (57.9 ) (98.0 ) 73.8
(19.6 )
Amortization of debt-related deferred costs, discounts and premiums (7.2 ) (6.9 ) (8.9 ) (8.5 ) (9.2 )
Interest and debt expense, net 99.4
125.1
140.1
127.1
77.9

Market adjustment on interest rate swaps —
—
0.5
2.7
1.7

Unit-based compensation charges (25.5 ) (19.2 ) (19.7 ) (21.3 ) (17.4 )
Gain (loss) on long-lived assets, net⁽⁵⁾
(65.6 ) (65.6 ) (821.2 ) (1.9 ) 5.3

Goodwill impairment⁽⁶⁾
(38.8 ) (162.6 ) (1,406.3 ) (48.8 ) (4.1 )
Loss on contingent consideration⁽⁷⁾
(57.0 ) —
—
(8.6 ) (31.4 )
Earnings (loss) from unconsolidated affiliates, net, adjusted for cash distributions received 0.1
(7.6 ) (73.6 ) (0.7 ) (0.1 )
Deferred income taxes 2.1
3.1
3.6
5.2
2.8

Provision (benefit) for income taxes (0.8 ) 0.3
(1.4 ) 1.1
1.0

Other non-cash income (expense) (0.9 ) (1.9 ) (0.7 ) —
1.0

EBITDA 161.4

152.9
(1,844.9 ) 403.1

196.2

Unit-based compensation charges 25.5
19.2
19.7
21.3
17.4

(Gain) loss on long-lived assets, net⁽⁵⁾
65.6
65.6
821.2
1.9
(5.3 )
Goodwill impairment⁽⁶⁾
38.8
162.6
1,406.3
48.8
4.1

Loss on contingent consideration⁽⁷⁾
57.0
—
—
8.6
31.4

(Earnings) loss from unconsolidated affiliates, net⁽⁸⁾
(47.8 ) (31.5 ) 60.8
0.7
0.1

Adjusted EBITDA from unconsolidated affiliates, net 80.3
61.1
25.3
6.9
2.5

Change in fair value of commodity inventory-related derivative contracts 2.2
14.1
5.4
(10.3 ) 10.7

Significant transaction and environmental-related costs and other items⁽⁹⁾
12.4
11.6
33.6
14.9
40.6

Adjusted EBITDA $ 395.4
$ 455.6
$ 527.4
$ 495.9
$ 297.7


~~(1)~~	Financial data presented for periods prior to June 19, 2013, solely reflect the operations of Legacy Crestwood GP. Financial data for periods subsequent to June 19, 2013, represent the consolidated operations of Crestwood Equity.

~~(2)~~

The weighted average number of units outstanding is calculated based on the presumption that the common and subordinated units issued to acquire Legacy Crestwood GP (the accounting predecessor) were outstanding for the entire period prior to the June 19, 2013 acquisition. On the date of the acquisition, all of our limited partner units were considered outstanding. In addition, on November 23, 2015, CEQP completed a 1-for-10 reverse split of its common units. The accounting standards related to earnings per share requires an entity to restate earnings per share when a stock dividend or stock split occurs, and as such, the earnings per unit for the years ended December 31, 2014 and 2013, were restated to reflect the 1-for-10 reverse split.


~~(3)~~	~~Reported amounts include the fourth quarter distributions, which are paid in the first quarter of the subsequent year.~~


~~(4)~~	Other long-term liabilities primarily include our capital leases, asset retirement obligations, loss on contingent consideration, net and the fair value of unfavorable contracts recorded in purchase accounting.

~~(5)~~

During 2017, we recognized a gain of approximately $33.6 million from the sale of US Salt. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3. During 2016, we recorded a loss of approximately $32.4 million on the deconsolidation of our NE S&T assets. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 2 and 6. During 2014, we recorded a gain of approximately $30.6 million on the sale of our investment in Tres Palacios. In addition, during 2017, 2015 and 2014, we recorded property, plant and equipment impairments of approximately $81.4 million, $501.7 million and $13.2 million. During 2017, 2016, 2015 and 2014, we recorded intangible asset impairments of approximately $0.8 million, $31.4 million, $316.6 million and $21.3 million. For a further discussion, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Estimates” and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.


~~(6)~~	For a further discussion of our goodwill impairments recorded during 2017, 2016, 2015 and 2014, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Estimates” and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

~~(7)~~

During 2017, the loss on contingent consideration related to our obligation to CEGP due to our expectation of certain criteria on growth capital projects not being met by Stagecoach Gas. For a further discussion, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6. During 2014 and 2013, we recorded a loss on contingent consideration which reflects the fair value of an earn-out premium associated with the original acquisition of our Marcellus G&P assets from Antero in 2012.


~~(8)~~	During 2015, we recorded impairments of our PRBIC and Jackalope equity investments of approximately $23.4 million and $51.4 million. For a further discussion of these impairments, see Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - “Critical Accounting Estimates” and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.


~~(9)~~	Significant transaction and environmental-related costs and other items primarily include costs incurred related to the Simplification Merger and other merger, acquisition and joint venture transactions, as well as costs associated with our historical cost savings initiatives and the realignment of our MS&L operations and related consolidation and relocation of our corporate offices.

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.~~

This report, including information included or incorporated by reference herein, contains forward-looking statements concerning the financial condition, results of operations, plans, objectives, future performancefootnotes, 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;~~

~~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;~~

~~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.~~

~~We have described under~~ Part I, Item ~~1A. Risk Factors, additional factors that could cause actual~~1. Business.

A comparative discussion of our 2021 operating results to our 2020 operating results can be ~~materially different from those described~~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 ~~forward-looking statements. Other factors that we have not identified in this report could also have this effect.~~year ended December 31, 2021 filed with the SEC on February 25, 2022.

Overview

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

Our Company

We provide broad-ranging services to customers across the crude oil, natural gas and NGL ~~sector~~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 ~~own or control:~~

~~natural gas facilities with approximately 2.4 Bcf/d of gathering capacity and 0.5 Bcf/d of processing capacity;~~

NGL facilities with approximately 20,000 Bbls/d of fractionation capacity and 3.1 MMBbls of storage capacity, as well as our portfolio of transportation assets (consisting of truck and rail terminals, truck/trailer units and rail cars) capable of transporting approximately 195,000 Bbls/d of NGLs; and

~~crude oil facilities with approximately 125,000 Bbls/d of gathering capacity, 1.5 MMBbls of storage capacity, 20,000 Bbls/d of transportation capacity, and 160,000 Bbls/d of rail loading capacity.~~

~~In addition, through our equity investments in joint ventures, we have ownership interests in:~~

natural gas facilities with approximately 0.3 Bcf/d of gathering capacity, 0.2 Bcf/d of processing capacity, 75.8 Bcf of certificated working storage capacity, and 1.5 Bcf/d of transportation capacity; and

~~crude oil facilities with approximately 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of working storage capacity.~~

Our financial statements reflect three operating and reporting segments: (i) gathering and processing, which includes our natural gas, crude oil and produced water G&P operations; (ii) storage and transportation, which includes our natural gas and crude oil storage and transportation operations; and (iii) marketing, supply and logistics, which includes our NGL supply and logistics business, crude oil storage and rail loading facilities and fleet.

~~Gathering and Processing~~

Our G&P operations and investments provide gathering, compression, treating, and processing services to producers in multiple unconventional resource plays across the United States and we have established footprints in “core of the core” areas of many of the largest shale plays. We believe that our strategy of focusing on prolific, low-cost shale plays positions us well to ~~(i)~~ generate greater returns in varying commodity price environments ~~(ii)~~and capture greater upside economics when development activity ~~occurs,~~occurs.

Our financial statements reflect three operating and reporting segments: (i) gathering and processing north operations (includes our Williston Basin and Powder River Basin operations); (ii) gathering and processing south operations (includes our Delaware Basin operations and our Crestwood Permian Basin equity method investment); and (iii) ~~in general, better manage through commodity price cycles~~storage and ~~production changes associated therewith.~~

~~Our G&P operations primarily include:~~

~~Bakken. We own and operate an integrated~~logistics (includes our crude oil, NGL and natural gas storage and logistics operations and our Tres Holdings and PRBIC equity method investments).

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 gathering, compression, treating and processing services, crude oil gathering and storage services and produced water gathering ~~system~~and disposal services to producers in the Williston Basin and Powder River Basin.

•Gathering and Processing South. Our gathering and processing facility (the Arrow system) in the core of the Bakken Shale in McKenzie and Dunn Counties, North Dakota, some of which is located on Fort Berthold Indian Reservation. The Arrow system consists of 640 miles of low-pressure gathering pipeline capable of gathering 100 MMcf/d of natural gas, 125 MBbls/d of crude oil, 40 MBbls/d of produced water, and the Bear Den processing plant includes approximately 30 MMcf/d of natural gas processing capacity. We also have approximately 266,000 Bbls of crude oil working storage capacity at the Arrow central delivery point;

~~Marcellus. We own and operate~~south operations provide natural gas gathering, compression, treating and ~~compression systems in Harrison, Doddridge~~processing services, crude oil gathering services and ~~Barbour Counties, West Virginia. These systems have a total~~produced water gathering ~~capacity of 875 MMcf/d~~ and ~~131,380 horsepower of compression;~~

~~Barnett.~~ We own and operate (i) a low-pressure natural gas gathering system with a gathering capacity of approximately 425 MMcf/d of rich gas produced by our customers in Hood and Somervell Counties, Texas, which delivers the rich gasdisposal services to our processing plant where NGLs are extracted from the natural gas stream; and (ii) low-pressure gathering systems with a gathering capacity of 500 MMcf/d of dry natural gas produced by our customers in Tarrant and Denton Counties, Texas;

~~Fayetteville~~. We own and operate five low-pressure gas gathering systems with a gathering capacity of approximately 510 MMcf/d of dry natural gas produced by our customers in Conway, Faulkner, Van Buren, and White Counties, Arkansas;

~~Granite Wash.~~ We own and operate a low-pressure natural gas gathering system with a gathering capacity of approximately 36 MMcf/d of rich gas produced by our customers in Roberts County, Texas, and a processing plant that extracts NGLs from the natural gas stream;

~~Delaware Permian. We own a 50% equity interest~~producers in the ~~Crestwood Permian joint venture with an affiliate of First Reserve. We operate the joint venture, which owns low-pressure dry gas~~Delaware Basin.

•Storage and rich natural gas gathering systems with a primary focus on the Willow Lake system, which includes approximately 75 MMcf/d of processing capacity that serves our customers in Eddy County, New Mexico. The joint venture also owns a 50% equity interest in Crestwood Permian Basin. In October 2017, Shell Midstream purchased a 50% equity interest in Crestwood Permian Basin. Crestwood Permian Basin ownsLogistics. Our storage and operates the Nautilus gathering system for SWEPI’s gas production in an area of dedication (approximately 100,000 acres) in Loving, Reeves and Ward Counties, Texas. The initial build-out of the Nautilus gathering system was completed on June 6, 2017, and includes 20 receipt point meters, 60 miles of pipeline, a 24-mile high pressure header system, 10,800 horsepower of compression and a high pressure delivery point. The Nautilus gathering system is supported by a 20-year fixed-fee gathering agreement with SWEPI; and

~~Powder River Basin.~~ We own a 50% equity interest in the Jackalope joint venture with Williams. The joint venture, operated by Williams, owns the Jackalope gas gathering system and Bucking Horse processing plant. The Jackalope system is supported by a 10-year gathering and processing agreement with Chesapeake under an area of dedication of approximately 358,000 gross acres in the core of the Powder River Basin;

~~Although the cash flows from our G&P~~logistics operations are predominantly fee-based under contracts with original terms ranging from 5-20 years, the results of our G&P operations are significantly influenced by the volumes gathered and processed through our systems. For example, due to market conditions that ultimately resulted in 2015 bankruptcy filings of two of our G&P customers (Quicksilver and Sabine), we gathered significantly lower volumes for those customers during 2015 and 2016 as they continued to shut-in wells during their respective bankruptcy proceedings. In April 2016, BlueStone bought Quicksilver’s assets out of bankruptcy and thereafter returned to production wells that were previously shut-in by Quicksilver. We entered into new 10-year agreements with BlueStone to gather and process its production under fixed-fee and percent-of-proceeds fee structures, and pursuant to the agreements, BlueStone will not shut-in or choke back production for economic purposes through the end of 2018. As a result, the volumes we are now gathering and processing have returned to levels consistent with those preceding Quicksilver’s bankruptcy filing. In March 2017, the Sabine bankruptcy proceedings were settled by the district court for the Southern District of New York, and the outcome was not material to our G&P segment’s results of operations.

The cash flows from our G&P operations can also be impacted in the short term by changing commodity prices, seasonality and weather fluctuations. We gather, process, treat, compress, transport and sellprovide NGLs, crude oil and natural gas ~~pursuant to a variety of contracts. These contracts include:~~

~~Fixed-fee contracts~~. Under these contracts, we do not take title to the underlying crude, natural gas or NGLs but charge our customers a fixed-fee per volume gathered, processed, treated, compressed and/or transported. Certain of these agreements can contain commitments for a minimum level of volumes or revenues;

~~Percentage-of-proceeds service contracts~~. Under these contracts, we effectively take title to crude, 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 effectively take title to crude, natural gas or NGLs before the commodity enters our gathering and processing facilities. We market and sell those commodities to third parties and we will remit a portion of the sales proceeds to our producers; and

~~Purchase and sale contracts. Under these contracts, we purchase crude, natural gas or NGLs before the commodity enters our gathering and processing facilities, and we market and sell those commodities to third parties.~~

~~Our election to enter primarily into fixed-fee contracts minimizes our G&P segment’s commodity price exposure and provides us more stable operating performance and cash flows.~~

~~Storage and Transportation~~

~~Our S&T operations and investments consist of our crude oil terminals in the Bakken and Powder River Basin and our natural gas~~ storage, terminal, marketing and transportation ~~assets in the Northeast~~(including rail, truck and ~~Texas Gulf Coast, including:~~

~~Bakken~~. We own and operate the COLT Hub, which is one of the largest crude oil rail terminals in the Bakken Shale based on actual throughput. Located approximately 60 miles from Arrow’s central delivery point, the COLT Hub interconnects with the Arrow system through the Hiland and Andeavor pipeline systems. The COLT Hub, which can receive approximately 350,000 Bbls/d from interconnected gathering systems, is capable of loading up to 160,000 Bbls/d and storing approximately 1.2 MMBbls of crude oil. Moreover, because the COLT Hub and our Arrow system each interconnect with the DAPL interstate system, our Bakken crude oil assets are integrated and offer customers multiple service options since the DAPL interstate pipeline system was placed in service in 2017;

~~Powder River Basin.~~ PRBIC, our 50% equity method investment, owns an integrated crude oil loading, storage and pipeline terminal, located in Douglas County, Wyoming, which provides a market for crude oil production from the Powder River Basin. The joint venture, which is operated by our joint venture partner, Twin Eagle, sources crude oil production from Chesapeake and other Powder River Basin producers. PRBIC includes 20,000 Bbls/d of rail loading capacity and 380,000 Bbls of crude oil working storage capacity. The terminal connects to Kinder Morgan’s Double H Pipeline system and Plains All American Pipeline’s Rocky Mountain Pipeline system;

~~Marcellus~~. Stagecoach Gas, our 50% equity method investment, owns four natural gas storage facilities (Stagecoach, Thomas Corners, Steuben and Seneca Lake) and three transportation pipelines (North/South Facilities, MARC I and the East Pipeline) located in or near the dry portion of the Marcellus Shale. The natural gas storage facilities provide 40.9 Bcf of certificated firm storage capacity and 1.5 Bcf/d of firm transportation capacity to producers, utilities, marketers and other customers. The location of these assets relative to New York City and other premium demand markets along the East Coast, together with the formation of our joint venture with a subsidiary of Consolidated Edison, helps to insulate our operations from production and commodity price changes that can impact storage and transportation operators in other geographic regions; and

~~Texas Gulf Coast~~. Tres Holdings, our 50.01% equity method investment owns a FERC-certificated 34.9 Bcf multi-cycle, salt dome natural gas storage facility. The Tres Palacios storage facility’s 63-mile, dual 24-inch diameter header system (including a 52-mile north pipeline lateral and an approximate 11-mile south pipeline lateral) interconnects with 11 pipeline systems and can receive residue gas from the tailgate of Kinder Morgan Inc.’s Houston central processing plant.

The cash flows from our S&T operations are predominantly fee-based under contracts with an original term ranging from 1-10 years. Our current cash flows from crude-by-rail facilities are supported by take-or-pay contracts with refiners and marketers. The rates and durations of the contracts associated with our crude oil terminals have eroded as pipelines come on-line that make crude-by-rail options less economical, which impacts our cash flows from operations. Cash flows from interruptible and other hub services provided by the natural gas storage facilities and pipelines owned by our joint ventures tends to increase during the peak winter season.

~~Marketing, Supply and Logistics~~

Our MS&L segment consists of our supply and logistics business, our storage and terminals business, our West Coast operations, and our crude oil, NGL and produced water trucking business. We utilize our over-the-road and rail fleet, processing and storage facilities, and contracted storage and pipeline capacity on a portfolio basis to provide integrated supply and logistics solutions to producers, refiners and other customers. In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP for net proceeds of approximately $223.6 million. As part of the US Salt divestiture, we retained all surface and sub-surface rights necessary to place the Watkins Glen NGL storage development project into service once we receive all required regulatory approvals.

~~Our MS&L operations primarily include:~~

~~Supply and Logistics~~. Our Supply and Logistics operations are supported by i) our fleet of rail and rolling stock with 75,000 Bbls/d of NGL transportation capacity, which also includes our rail-to-truck terminals located in Florida, New Jersey, New York, Rhode Island and North Carolina; and ii) NGL pipeline and storage capacity leased from third

~~parties, including more than 500,000 Bbls of NGL working storage capacity at major hubs in Mt. Belvieu, Texas and Conway, Kansas;~~

~~Storage and Terminals.~~ ~~Our NGL Storage and Terminals operations include our Seymour and Bath storage facilities, which are supported by third-party pipelines and/or rail and truck terminal facilities;~~

~~West Coast.~~ ~~Our West Coast NGL operations provide processing, fractionation, storage, transportation and marketing~~pipeline) services to producers, refiners, marketers, utilities and other customers. We separate NGLs from natural gas, deliver to local natural gas pipelines, retain NGLs for further processing at our fractionation facility, provide butane isomerization and refrigerated storage services, as well as provide to Western US refineries for motor fuel production. Our operations also consists of wholesale propane assets primarily including three rail-to-truck terminals located in Hazen, Nevada, Carlin, Nevada, and Shoshoni, Wyoming and a truck terminal located in Salt Lake City, Utah. These terminals are used to provide supply, transportation and storage services to wholesale customers in the western and north central regions of the United States; and

~~Trucking~~. Our Trucking operations consist of a fleet of owned and leased trucks with 20,000 Bbls/d of crude oil and produced water transportation capacity and 120,000 Bbls/d of NGL transportation capacity. We provide hauling services to customers in North Dakota, Montana, Wyoming, Texas, New Mexico, Indiana, Mississippi, New Jersey, Ohio, Utah and California.

The cash flows from our marketing, supply and logistics business represent sales to creditworthy customers typically under contracts with durations of one year or less, and tend to be seasonal in nature due to customer profiles and their tendencies to purchase NGLs during peak winter periods.

Outlook and Trends

Our business objective is to create long-term value for our unitholders. We expect to create ~~long-term~~ value for our investors by ~~consistently~~ generating stable operating margins and ~~improved~~improving cash flows from our diversified midstream operations by prudently financing investments in our ~~investments,~~assets and expansions of our portfolio, maximizing throughput and optimizing services on our assets, and effectively controlling our capital expenditures, operating and administrative costs. Our business strategy depends, in part, on our ability to provide increased services to our customers at competitive fees, including opportunities to expand our services resulting from expansions, organic growth projects and acquisitions that can be financed appropriately.

~~Through the challenging market environment from 2014 through 2017,~~Throughout 2022, we have taken a number of strategic steps to better position the Company asto increase cash flows and our operating scale in our core basins to create a stronger, better capitalized company that can ~~over time~~ accretively grow cash flows and ~~sustainably resume growing~~volumes, while being a high-quality midstream operator and an industry leader in ESG efforts.

In 2022, we successfully executed on our ~~distributions. Those strategic steps included (i) simplifying~~long-term growth strategy through disciplined capital investments utilizing our ~~corporate structure~~current financial flexibility. On February 1, 2022, we acquired Oasis Midstream in an equity and cash transaction valued at

Table of Contents

approximately $1.8 billion. Pursuant to ~~eliminate our incentive distribution rights (IDRs) and create better alignment~~the merger agreement, Chord received $150 million in cash plus 20.9 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, Chord received a $10 million cash payment for its ownership of ~~interests with our unitholders; (ii) divesting assets to reduce approximately $1 billion~~the general partner of long-term debt to ensure long-term balance sheet strength; (iii) realigning our operating structure to significantly reduce operating and administrative expenses; (iv) forming strategic joint ventures to enhance ourOasis Midstream. This transaction further solidifies Crestwood’s competitive position ~~around certain operating assets; and (v) focusing our growth capital expenditures on our highest return organic projects around our core growth assets~~ in the ~~Bakken Shale~~Williston Basin and Delaware Permian. We will remain focused on efficiently allocating capital expenditures by investing in accretive, organic growth projects, maintaining low-cost operations (through increased operating efficiencies and cost discipline) and maintaining our balance sheet strength through continued financial discipline. We expect to focus on expansion and greenfield opportunitiesexpands the Company’s relationship with Chord. Additionally, the Rough Rider system acquired in the ~~Bakken Shale and Delaware Permian in the near term, while closely monitoring longer-term expansion opportunities in the Powder River Basin and northeast Marcellus. As a result, the Company~~merger with Oasis Midstream is ~~well positioned to execute its business plan and capitalize on the improving market conditions around many of our core assets.~~

While market conditions remain challenging around some of our assets, the Company continues to be positioned to generate consistent results in a low commodity price environment without sacrificing revenue upside as market conditions improve. For example, many of our more mature G&P assets are supported by long-term, core acreage dedications in shale plays that are economic to varying degrees based upon natural gas, NGL and crude oil prices, the availability of infrastructure to flow production to market, and the operational and financial condition of our diverse customer base. In addition, a substantial portion of our midstream investments are based on fixed-fee, take-or-pay or minimum volume commitment agreements that ensure a minimum level of cash flow regardless of actual commodity prices or volumetric throughput. Over time, we expect cash flows from our more mature, non-core, assets to stabilize and potentially increasecomplementary with the improving commodity price environment, while the growth from our core assets in the Bakken Shale, Delaware Permian, Powder River Basin and northeast Marcellus drive significant growth to the Company.

Below is a discussion of events that highlight our core business and financing activities. Through continued execution of our plan, we have materially improved the strategic and financial position of the Company and expect to capitalize on increasing opportunities in an improving but competitive market environment, which will position us to achieve our chief business objective to create long-term value for our unitholders.

~~Gathering and Processing~~

~~Bakken.~~ ~~In the Bakken, we are expanding and upgrading~~ our Arrow system, ~~water handling facilities~~which has provided and ~~increasing natural gas capacity on the system, which should allow for substantial growth in volumetric throughput across all~~continues to provide opportunities to drive cost savings and commercial synergies and better utilization of ~~our crude oil, produced water and natural gas gathering systems. We are completing construction of a 30 MMcf/d natural~~available gas processing ~~facility and associated pipelines that began receiving gas in late 2017. In addition,~~capacity.

During 2022, we ~~are constructing~~also completed a ~~120 MMcf/d cryogenic plant that is designed to fulfill 100%~~series of strategic transactions including (i) the ~~processing requirements~~acquisition of Sendero for ~~producers on~~approximately $631 million, (ii) the ~~Arrow system upon expiration~~acquisition of third-party processing contracts in the third quarter 2019. We expect to invest approximately $195 million on the expansion with a targeted in-service date in the second quarter 2019. Upon completion of the expansion, we expect to have a combined 150 MMcf/d of gas processing capacity in the Bakken. We believe the installation of a gas processing solution on the Arrow system will, among other things, spur greater development activity around the Arrow system, allow us to provide greater flow assurance to our producer customers and reduce flaring of natural gas, and reduce the downstream constraints currently experienced by producers on the Fort Berthold Indian Reservation.

~~Delaware Permian.~~ In the Delaware Permian, we have identified gathering and processing and transportation opportunities in and around our existing assets, including our joint ventures. Through our Crestwood Permian joint venture, we are expanding our gathering and processing capacity in the region, which includes the construction of a 200 MMcf/d natural gas processing facility in Orla, Texas, and associated pipelines, as well as our interconnection capacity to accommodate greater takeaway options for residue gas and NGLs. The initial cost of the expansion project is expected to cost approximately $170 million with an in-service date in the second half of 2018. We are also evaluating expansion opportunities to provide midstream services for crude oil and produced water, including crude gathering, crude oil and condensate storage and terminalling, condensate stabilization, truck loading/unloading options and connections to third party pipelines and produced water gathering, disposal and recycling.

~~On June 21, 2017, we contributed to Crestwood Permian 100% of the~~equity interest of Crestwood New Mexico, our wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New Mexico. This contribution was treated as a transaction between entities under common control, and accordingly we deconsolidated Crestwood New Mexico and our investment in Crestwood Permian was increased by the historical book value of these assets of approximately $69.4 million. In conjunction with this contribution, First Reserve has agreed to contribute to Crestwood Permian the first $151 million of capital costs required to fund the expansion of the Delaware Basin assets, which includes the Orla processing plant and associated pipelines. In October 2017, CPB Subsidiary Holdings LLC, a wholly-subsidiary of Crestwood Permian, entered into a credit agreement with certain lenders. The five year term credit agreement allows for revolving loans, letters of credit and swingline loans in an aggregate principal amount of up to $150 million. Borrowings under the credit agreement will be used to fund expansion projects and for general corporate purposes.

Crestwood Permian Basin has a long-term agreement with SWEPI to construct, own and operate a natural gas gathering system in SWEPI's operated position in the Delaware Permian. SWEPI has dedicated to Crestwood Permian Basin approximately 100,000 acres and gathering rights for SWEPI's gas production across a large acreage position in Loving, Reeves, Ward and Culberson Counties, Texas. The Nautilus gathering system will be constructed to ultimately include 194 miles of low pressure gathering lines, 36 miles of high pressure trunklines and centralized compression facilities which are expandable over time as production increases, producing gas gathering capacity of approximately 250 MMcf/d. In addition, the Orla processing plant described above, will be further expanded and integrated to connect the Nautilus gas gathering system to the Orla plant. The initial build-out of the Nautilus gathering system was completed on June 6, 2017, and includes 20 receipt point meters, 60 miles of pipeline, a 24-mile high pressure header system, 10,800 horsepower of compression and a high pressure delivery point. Crestwood Permian Basin provides gathering, dehydration, compression and liquids handling services to SWEPI under a 20-year fixed-fee gathering agreement. In October 2017, Shell Midstream purchased aReserve’s 50% equity interest in Crestwood Permian ~~Basin~~in exchange for approximately ~~$37.9~~$6 million in ~~cash.~~

~~Marketing, Supply~~cash and ~~Logistics~~

~~Our MS&L operations own NGL storage~~approximately 11.3 million newly issued CEQP common units, and ~~terminalling~~(iii) the divestitures of our Barnett and Marcellus Shale assets for approximately $290 million and $206 million, respectively. The acquisitions of Sendero and First Reserve’s 50% equity interest in the ~~Northeast U.S. and our West Coast processing facility. During 2017, we experienced NGL market headwinds~~Crestwood Permian joint venture have significantly increased the Company’s position in the ~~Northeast,~~Delaware Basin.

The divestitures of our Barnett and Marcellus natural gas assets represents a full exit of our gathering and processing operations in the Barnett and Marcellus Shales. These divestitures allow the Company to focus on building and optimizing its gathering and processing positions in the Williston, Delaware and Powder River Basins, which we believe will best position the Company to deliver long-term value to its unitholders.

On February 20, 2023, we and Brookfield entered into an agreement with a third party to sell each of our respective interests in Tres Palacios Holdings LLC (Tres Holdings) for total consideration of approximately $335 million. The transaction is expected to close in the second quarter of 2023, subject to customary closing conditions.

Following the strategic transactions discussed above, we are focusing our near-term strategy on optimizing and integrating the acquired assets into our legacy gathering and processing operations. To accomplish this strategy, we have also taken steps to (i) minimize capital expenditures to better align with development activity by our gathering and processing customers; (ii) realign our organization to reduce operating and administrative expenses; (iii) engage with our ~~NGL exports~~customers to maintain volumes across our asset portfolio; (iv) optimize our storage, transportation and ~~other market dynamics causing~~marketing assets to take advantage of regional commodity price ~~differentials~~volatility; and (v) evaluate our debt and equity structure to ~~narrow between purchasing NGLs in the summer (which are stored in~~preserve liquidity and ensure balance sheet strength. Given our ~~NGL facilities) and~~

selling NGLs in the winter. These dynamics also caused the rates that we were able to charge for storing NGLs in our facilities to decline from their historical levels. Also during 2017, our West Coast customers also experienced headwinds, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S. This caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016.

In December 2017, we sold 100% of our equity interests in US Salt, a solution-mining and salt production company located on the shores of Seneca Lake near Watkins Glen in Schuyler County, New York, to an affiliate of Kissner Group Holdings LP for net proceeds of approximately $223.6 million.

~~Regulatory Matters~~

~~Many aspects of the energy midstream sector, such as crude-by-rail activities and pipeline integrity, have experienced increased regulatory oversight~~efforts over the past few ~~years. However, under~~years to improve the ~~current Presidential Administration, we anticipate changes in policy that could lessen the degree of regulatory scrutiny we face~~Partnership’s competitive position in the ~~near term.~~businesses we operate, manage costs and improve margins and create a stronger balance sheet, we believe we are well positioned to execute our business plan.

Other 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 2023. We expect DAPL will remain in operation while the environmental impact statement is being completed.

The Rough Rider gathering system connects to the Arrow crude oil system and is capable of transporting all of its crude oil volumes to the Arrow system. The Arrow 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 and Rough Rider customers. Additionally, we can transport Arrow and Rough Rider 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 ~~December 2017,~~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 ~~Tax Cuts~~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

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sourced gas standards for the midstream sector; (vi) investing in technology to better inventory and ~~Jobs Act (the Tax Act) was passed by~~calculate emissions data and integrating the ~~U.S. Congress, which modified~~technology into our operations; and (vii) participating in and providing leadership to trade associations focused on climate-related risks. We have made progress on several ~~aspects~~ of the ~~U.S. income tax code beginning~~key objectives of our CMP in ~~2018.~~2022, including installing methane detection devices at 13% of our facilities during 2022. With respect to our approach to acquisitions and divestitures, we also published a carbon protocol that incorporates the evaluation of GHG emissions during the due diligence process and related onsite inspections prior to close of any such transactions.

Our emissions-related metrics are included in our executives’ and employees’ short-term incentive compensation program. During 2022, our methane intensity target (which includes of the operations acquired during 2022) was 0.046% (measured as metric tons per Mscf of throughput on our assets), compared to our actual 2021 methane intensity statistic of 0.036%. We ~~are~~have included a methane intensity target of 0.040% in our executives’ and employees’ short-term incentive compensation program for 2023.

We currently ~~evaluating how many of these modifications~~believe that our carbon management efforts will ~~impact master limited partnerships such as CEQP and its unitholders. In particular, we are evaluating~~help to mitigate the potential impact that ~~the Tax Act will~~emissions may have on our ~~unitholders’ ability to deduct business interest from their taxable income, since the Tax Act requires that the business interest deduction be limited to the sum~~capital expenditures or results of business interest income and 30% of adjusted taxable income. For the purposes of this limitation, adjusted taxable income will be computed without regard to any business interest expense or business interest income, andoperations in the ~~case of taxable years beginning before January 1, 2022, any deduction allowable for depreciation, amortization, or depletion.~~future.

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 U.S. GAAP requires management to select appropriate accounting estimates and to make estimates and assumptions that affect the reported amount of assets, liabilities, revenues and expenses and the disclosures of contingent assets and liabilities. We consider our critical accounting estimates to be those that require difficult, complex or subjective judgment necessary in accounting for inherently uncertain matters and those that could significantly influence our financial results based on changes in those judgments. Changes in facts and circumstances may result in revised estimates and actual results may differ materially from those estimates. We have discussed the development and selection of the following critical accounting estimates and related disclosures with the Audit Committee of the board of directors of our general partner.

~~Goodwill Impairment~~For a complete discussion of our significant accounting policies, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.

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. ~~We also compare the total fair value of our reporting units to our overall enterprise value, which considers the market value for our common and preferred units.~~ 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.

~~We acquired substantially all of our reporting units in 2013, 2012 and 2011, which~~Upon acquisition, we are required us to record the assets, liabilities and goodwill of ~~each of those~~a reporting ~~units~~unit at its fair value on the date ~~they were acquired.~~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.

Current commodity prices are significantly lower compared to commodity prices during 2014, and that decrease has adversely impacted forecasted cash flows, discount rates and stock/unit prices for most companies in the midstream industry, including us. In lightAt December 31, 2022, our goodwill consisted of ~~these circumstances, we evaluated the carrying value of our reporting units and determined it was more likely than not that the goodwill~~approximately $94.7 million associated with ~~several of~~ our gathering and processing north Williston reporting ~~units was impaired~~unit, $35.6 million associated with our gathering and ~~as a result, we recorded goodwill impairments on several of~~processing south Permian reporting unit and $92.7 million associated with our ~~reporting units during 2017, 2016 and 2015 as shown in the table below (in millions). During 2017, we adopted the provision of ASU 2017-04,~~ ~~Intangibles - Goodwill and Other (Topic 350): Simplifying the Test for Goodwill Impairment, which allows companies to apply a single test to determine if goodwill is impaired and the amount of any impairment, which is reflected in our 2017 goodwill impairments.~~

Goodwill Impairments during the Year Ended December 31, 2015 Goodwill Impairments during the Year Ended December 31, 2016 Goodwill Impairments during the Year Ended December 31, 2017 Goodwill at December 31, 2017
G&P
Fayetteville $ 72.5
$ —
$ —
$ —
Marcellus —
8.6
—
—
Arrow —
—
—
45.9
S&T
COLT 623.4
44.9
—
—
MS&L
West Coast 85.9
—
2.4
—
Supply and Logistics 99.0
65.5
—
101.7
Storage and Terminals 53.7
14.1
36.4
—
Trucking 148.4
29.5
—
—
Watkins Glen 66.2
—
—
—
Total Crestwood Midstream $ 1,149.1
$ 162.6
$ 38.8
$ 147.6
Barnett (G&P) 257.2
—
—
—
Total Crestwood Equity $ 1,406.3
$ 162.6
$ 38.8
$ 147.6

The goodwill impairments recorded during 2017 related to our MS&L West Coast and Storage and Terminals operations. The goodwill impairment related to our MS&L West Coast operations resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for gathering, processingstorage and logistics services from our West Coast operations to remain relatively flat over the past several years. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013,NGL Marketing and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. The goodwill impairment related to our MS&L Storage and Terminals operations resulted from decreasing forecasted cash flows to be generated by those operations. During 2017, we experienced NGL market headwinds in the Northeast with NGL exports and other market dynamics causing price differentials to narrow between purchasing NGLs in the summer (which are then stored in our NGL facilities) and selling NGLs in the winter. These dynamics also caused the rates that we are able to charge for storing NGLs in our facilities to decline from their historical levels. Although our MS&L Storage and Terminals operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the decrease that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future. We utilized the income approach to determine the fair value of ourLogistics reporting units given the limited availability of comparable market-based transactions during 2017, and we utilized discount rates ranging from 10% to 12% in applying the income approach to determine the fair value of our reporting units with goodwill as of December 31, 2017, which is a Level 3 fair value measurement.

~~As a result of these analyses and impairments, we only have two reporting units with goodwill associated with them at December 31, 2017 (Arrow and Supply and Logistics).~~unit. We continue to monitor

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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. ~~In particular, a~~A 5% decrease in the forecasted cash flows or a 1% increase in the discount rates utilized to determine the fair value of each of our ~~business~~reporting units would not have resulted in a goodwill ~~impairments~~impairment at ~~our two remaining reporting units with goodwill associated with them.~~December 31, 2022.

Long-Lived Assets

Our long-lived assets consist of property, plant and equipment and intangible assets that have been obtained through multiple ~~historical~~ 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.~~acquired (including an analysis of discounted cash flows which can involve assumptions on discount rates and projected cash flows of the assets acquired). Management reviews this information to determine its reasonableness in comparison to the assumptions utilized in determining the purchase price of the assets in addition to other market-based information that was received through the purchase process and other sources. These projections also include projections on potential and contractual obligations assumed in these acquisitions. Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can, and often do, differ from our estimates.

We utilize assumptions related to the useful lives and related salvage value of our property, plant and equipment in order to determine depreciation and amortization expense each period. Due to the imprecise nature of the projections and assumptions utilized in determining useful lives, actual results can, and often do, differ from our estimates.

To estimate the useful life of our finite lived intangible assets we utilize assumptions of the period over which the assets are expected to contribute directly or indirectly to our future cash flows. Generally this requires us to amortize our intangible assets based on the expected future cash flows (to the extent they are readily determinable) or on a straight-line basis (if they are not readily determinable) of the acquired contracts or customer relationships. Due to the imprecise nature of the projections and assumptions utilized in determining future cash flows, actual results can, and often do, differ from our estimates.

We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value of our assets based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. This differs from our evaluation of goodwill, for which we perform an assessment of the recoverability of goodwill utilizing fair value estimates that primarily utilize discounted cash flows in the estimation process (as described above), and accordingly a reporting unit that has experienced a goodwill impairment may not experience a similar impairment of the underlying long-lived assets included in that reporting unit. ~~During 2017, 2016 and 2015, we recorded the following impairments of our intangible assets and property, plant and equipment:~~

During 2017, we incurred $82.2 million of impairments of our property, plant and equipment and intangible assets related to our MS&L West Coast operations, which resulted from decreasing forecasted cash flows to be generated by those operations. Our West Coast customers experienced headwinds during 2017, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S., which caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Although our West Coast operations’ results have been relatively consistent over the past several years, these operations have not experienced growth as fast or to the degree that we expected when we merged with Inergy, LP in 2013, and during 2017, we revised our forecasted cash flows to reflect current market dynamics, which we believe will continue for the foreseeable future.

During 2016, we incurred a $31.4 million impairment of intangible assets related to our MS&L Trucking operations, which resulted from the impact of increased competition on our Trucking business and the loss of several key customer relationships that were acquired in 2013 to which the intangible assets related.

During 2015, we incurred $8.5 million of impairments of our property, plant and equipment related to our Granite Wash gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our major customer of those assets has declared bankruptcy and has ceased any substantial drilling in the

~~Granite Wash in the near future given current and future anticipated market conditions related to natural gas and NGLs.~~

During 2015, we incurred $593.3 million of impairments of our intangible assets and property, plant and equipment related to our Barnett gathering and processing operations, which resulted from the recent actions of our primary customer in the Barnett Shale, Quicksilver, related to its filing for protection under Chapter 11 of the U.S. Bankruptcy Code in 2015.

During 2015, we incurred $184.5 million of impairments of our intangible assets and property, plant and equipment related to our Fayetteville and Haynesville gathering and processing operations, which resulted from decreases in forecasted cash flows for those operations given that our customers for those assets have ceased any substantial drilling in the Fayetteville and Haynesville Shales in the near future given current and future anticipated market conditions related to natural gas.

During 2015, we incurred $31.2 million of impairments of our property, plant and equipment related to our Watkins Glen marketing, supply and logistics segment development project, which resulted from continued delays and uncertainties in the permitting of our proposed NGL storage facility.

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 2022, 2021 and 2020, we recorded losses and impairments related to our property, plant and equipment as described below. For a further discussion of these matters, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2, Note 3 and Note 11.

•During 2022, we recorded a loss on long-lived assets of approximately $250 million related to the sale of our Marcellus Shale assets. In addition, during 2022, Crestwood Midstream recorded a loss on long-lived assets of approximately $53 million related to the sale of the Barnett Shale assets. We also recorded a loss on long-lived assets of approximately $7 million related to the anticipated sale of parts inventory related to our legacy Granite Wash operations and a loss on long-lived assets of approximately $4 million due to a buyout of leases related to our exiting the crude oil railcar business during 2022.

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•During 2021, we recorded approximately $40 million of impairments of our property, plant and equipment related to our gathering and processing south segment’s compressor stations in our Marcellus operations based on the actual or anticipated dismantlement and redeployment of those assets to other areas.

•During 2020, we sold our Fayetteville assets and recorded a loss on long-lived assets of approximately $20 million. In addition, during 2020, we recorded approximately $3 million of impairments of our property, plant and equipment primarily related to the removal and retirement of certain of our water gathering facilities in our Arrow operations.

We continue to monitor our long-lived assets, and we could experience additional impairments of the remaining carrying value of these long-lived assets in the future if we receive ~~additional~~ negative information about market conditions or the intent of our long-lived assets’ customers, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value of those investments.

Equity Method Investments

We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, we adjust the carrying values of the ~~asset~~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.

Because our Jackalope and PRBIC equity method investments were acquired in 2013, any level of decrease in the forecasted cash flows of these investments or increases in the discount rates utilized to value those investments from their respective acquisition dates would likely result in the fair value of the equity method investment falling below their carrying value, and could result in an assessment of whether that investment is impaired.

During 2015, we recorded a $51.4 million and $23.4 million impairment of our Jackalope and PRBIC equity method investments, respectively, as a result of decreasing forecasted cash flows and increasing the discount rate utilized in determining the fair value of the equity method investment considering the continued decrease in commodity prices and its impact on the midstream industry and our equity method investments’ customers.

We continue to monitor our equity method investments, and ~~we could experience additional impairments of the remaining carrying value of these investments in the future~~ if we receive ~~additional~~ negative information about market conditions or the intent of our equity method investments’ customers ~~which could~~to curtail production in the future that negatively ~~impact~~impacts the forecasted cash flows or discount rates utilized to determine the fair value of those ~~investments.~~

~~Variable Interest Entities~~

~~We evaluate all legal entities in which~~investments, we ~~hold an ownership interest~~could experience impairments to ~~determine if~~ the entity is a variable interest entity (VIE). Our interests in a VIE are referred to as variable interests. Variable interests can be contractual, ownership or other interests in an entity that change with changes in the faircarrying value of ~~the VIE’s assets. When~~these investments.

Our equity method investments have long-lived assets 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 ~~conclude that~~do. During 2021, we ~~hold an interest in~~recorded a ~~VIE we must determine if we are the entity’s primary beneficiary. A primary beneficiary is deemed~~$158.7 million reduction to ~~have a controlling financial interest in a VIE.~~

We consolidate any VIE when we determine that we are the primary beneficiary. We must disclose the nature of any interests in a VIE that is not consolidated. Significant judgment is exercised in determining that a legal entity is a VIE and in evaluating our interest in a VIE. We use primarily a qualitative analysis to determine if an entity is a VIE. We evaluate the entity’s need for continuing financial support; the equity ~~holder’s lack of a controlling financial interest; and/or if an~~earnings from our Stagecoach Gas equity holder’s voting interests are disproportionate to its obligation to absorb expected losses or receive residual returns. We evaluate our interests in a VIE to determine whether we are the primary beneficiary. We usemethod investment primarily ~~a qualitative analysis to determine if we are deemed to have a controlling financial interest in the VIE, either on a standalone basis or~~ as part of a related party group. We continually monitor our interests in legal entities for changes in the design or activities of an entity and changes in our interests, including our status as the primary beneficiary to determine if the changes require us to revise our previous conclusions. As a result of ~~this analysis, we concluded that our investment in Crestwood Permian is~~the sale (through a ~~VIE that we are not the primary beneficiary~~series of ~~and as~~transactions) of Stagecoach Gas to a ~~result, we account for our investment in Crestwood Permian as an equity method investment.~~

~~Our other equity investments are not considered to be VIEs. However, any future changes in the design or nature~~subsidiary of Kinder Morgan. For a further discussion of the activities of these entities may require us to reconsider our conclusions associated with these entities. Such reconsideration would require the identification of the variable interests in the entity and a determination on which party is the entity’s primary beneficiary. If an equity investment were considered a VIE and we were determined to be the primary beneficiary, the change could cause us to consolidate the entity. The consolidation of an entity that is currently accounted for under the equity method could have a significant impact on our financial statements. SeeStagecoach Gas divestiture, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 66. 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.

Revenue Recognition

We recognize revenues for ~~more information~~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 this deferred revenue as contract liabilities on our ~~equity method investments.~~consolidated balance sheets. At December 31, 2022 and 2021, we had deferred revenues of approximately $224.0 million and $197.8 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.

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•Contracts with Increasing (Decreasing) Rates per Unit. Certain of our contracts have fixed rates per volume that increase and/or decrease over the life of the contract once certain time periods or thresholds are met. We record revenues on these contracts ratably per unit over the life of the contract based on the remaining performance obligations to be performed, which can result in the deferral of revenue for the difference between the consideration received and the ratable revenue recognized.

The evaluation of when performance obligations have been satisfied and the transaction price that is allocated to our performance obligations requires significant judgments and assumptions, including our evaluation of the timing of when control of the underlying good or service has transferred to our customers, estimating the revenue to be generated per unit over the life of the contracts, and determining the relative standalone selling price of goods and services provided to customers under contracts with multiple performance obligations. Actual results can significantly vary from those judgments and assumptions.

How We Evaluate Our Operations

We evaluate our overall business performance based primarily on EBITDA and Adjusted EBITDA. We do not utilize depreciation, amortization and accretion expense in our key measures because we focus our performance management on cash flow generation and our assets have long useful lives.

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 ~~losses~~impairments on long-lived assets, impairments of ~~long-lived assets and~~ goodwill, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, ~~certain costs related to our historical cost saving initiatives,~~ the change in fair value of commodity inventory-related derivative contracts, costs associated with ~~our 2017~~the realignment and restructuring of our ~~Marketing, Supply and Logistics~~ operations and ~~related consolidation and relocation of our~~ corporate ~~offices,~~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 isare 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 U.S. 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 U.S. GAAP. EBITDA and Adjusted EBITDA calculations may vary among entities, so our computation may not be comparable to measures used by other companies.

See our reconciliation of net income to EBITDA and Adjusted EBITDA in “Results of Operations” below.

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Results of Operations

The following table summarizes our results of operations (in millions).


	Crestwood Equity						Crestwood Midstream
	Year Ended December 31,						Year Ended December 31,
	2022		2021		2020		2022		2021
Revenues	$	6,000.7	$	4,569.0	$	2,254.3	$	6,000.7	$	4,569.0
Costs of product/services sold	4,997.1		3,843.9		1,600.5		4,997.1		3,843.9
Operations and maintenance expense	196.1		121.0		131.8		196.1		121.0
General and administrative expense	130.4		97.6		91.5		124.4		90.2
Depreciation, amortization and accretion	328.9		244.2		237.4		334.6		258.4
Loss on long-lived assets, net	187.7		39.6		26.0		312.7		39.4
Goodwill impairment	—		—		80.3		—		—
Gain on acquisition	(75.3)		—		—		(75.3)		—

Operating income	235.8		222.7		86.8		111.1		216.1
Earnings (loss) from unconsolidated affiliates, net	15.7		(120.4)		32.5		15.7		(120.4)
Interest and debt expense, net	(177.4)		(132.1)		(133.6)		(177.4)		(132.1)
Gain (loss) on modification/extinguishment of debt	—		(7.5)		0.1		—		(7.5)
Other income (expense), net	0.3		0.1		(0.7)		0.1		—
Provision for income taxes	(1.9)		(0.2)		(0.4)		(1.7)		(0.1)
Net income (loss)	72.5		(37.4)		(15.3)		(52.2)		(44.0)
Add:
Interest and debt expense, net	177.4		132.1		133.6		177.4		132.1
(Gain) loss on modification/extinguishment of debt	—		7.5		(0.1)		—		7.5
Provision for income taxes	1.9		0.2		0.4		1.7		0.1
Depreciation, amortization and accretion	328.9		244.2		237.4		334.6		258.4
EBITDA	580.7		346.6		356.0		461.5		354.1
Unit-based compensation charges	37.2		34.9		30.7		37.2		34.9
Loss on long-lived assets, net	187.7		39.6		26.0		312.7		39.4
Goodwill impairment	—		—		80.3		—		—
Gain on acquisition	(75.3)		—		—		(75.3)		—

(Earnings) loss from unconsolidated affiliates, net	(15.7)		120.4		(32.5)		(15.7)		120.4
Adjusted EBITDA from unconsolidated affiliates, net	30.0		67.0		75.4		30.0		67.0
Change in fair value of commodity inventory-related derivative contracts	(14.4)		(13.5)		33.6		(14.4)		(13.5)
Significant transaction and environmental related costs and other items	31.9		5.1		10.8		31.9		2.5
Adjusted EBITDA	$	762.1	$	600.1	$	580.3	$	767.9	$	604.8

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Crestwood Equity Crestwood Midstream
Year Ended December 31, Year Ended December 31,
2017 2016 2015 2017 2016
Revenues $ 3,880.9
$ 2,520.5
$ 2,632.8
$ 3,880.9
$ 2,520.5
Costs of product/services sold 3,374.7
1,925.1
1,883.5
3,374.7
1,925.1
Operations and maintenance 136.0
158.1
190.2
136.0
155.0
General and administrative 96.5
88.2
116.3
93.1
85.6
Depreciation, amortization and accretion 191.7
229.6
300.1
202.7
240.5
Loss on long-lived assets, net (65.6 ) (65.6 ) (821.2 ) (65.6 ) (65.6 )
Goodwill impairment (38.8 ) (162.6 ) (1,406.3 ) (38.8 ) (162.6 )
Loss on contingent consideration (57.0 ) —
—
(57.0 ) —
Operating loss (79.4 ) (108.7 ) (2,084.8 ) (87.0 ) (113.9 )
Earnings (loss) from unconsolidated affiliates, net 47.8
31.5
(60.8 ) 47.8
31.5
Interest and debt expense, net (99.4 ) (125.1 ) (140.1 ) (99.4 ) (125.1 )
Gain (loss) on modification/extinguishment of debt (37.7 ) 10.0
(20.0 ) (37.7 ) 10.0
Other income, net 1.3
0.5
0.6
0.8
—
(Provision) benefit for income taxes 0.8
(0.3 ) 1.4
—
—
Net loss (166.6 ) (192.1 ) (2,303.7 ) (175.5 ) (197.5 )
Add:
Interest and debt expense, net 99.4
125.1
140.1
99.4
125.1
(Gain) loss on modification/extinguishment of debt 37.7
(10.0 ) 20.0
37.7
(10.0 )
Provision (benefit) for income taxes (0.8 ) 0.3
(1.4 ) —
—
Depreciation, amortization and accretion 191.7
229.6
300.1
202.7
240.5
EBITDA 161.4
152.9
(1,844.9 ) 164.3
158.1
Unit-based compensation charges 25.5
19.2
19.7
25.5
19.2
Loss on long-lived assets, net 65.6
65.6
821.2
65.6
65.6
Goodwill impairment 38.8
162.6
1,406.3
38.8
162.6
Loss on contingent consideration 57.0
—
—
57.0
—
(Earnings) loss from unconsolidated affiliates, net (47.8 ) (31.5 ) 60.8
(47.8 ) (31.5 )
Adjusted EBITDA from unconsolidated affiliates, net 80.3
61.1
25.3
80.3
61.1
Change in fair value of commodity inventory-related derivative contracts 2.2
14.1
5.4
2.2
14.1
Significant transaction and environmental-related costs and other items⁽¹⁾
12.4
11.6
33.6
12.4
11.6
Adjusted EBITDA $ 395.4
$ 455.6
$ 527.4
$ 398.3
$ 460.8


	Crestwood Equity						Crestwood Midstream
	Year Ended December 31,						Year Ended December 31,
	2022		2021		2020		2022		2021
Net cash provided by operating activities	$	439.2	$	426.7	$	408.1	$	445.2	$	434.4
Net changes in operating assets and liabilities	114.3		6.7		(36.1)		114.4		6.8
Amortization of debt-related deferred costs	(2.2)		(6.7)		(6.5)		(2.2)		(6.7)
Interest and debt expense, net	177.4		132.1		133.6		177.4		132.1
Unit-based compensation charges	(37.2)		(34.9)		(30.7)		(37.2)		(34.9)
Loss on long-lived assets, net	(187.7)		(39.6)		(26.0)		(312.7)		(39.4)
Goodwill impairment	—		—		(80.3)		—		—
Gain on acquisition	75.3		—		—		75.3		—

Earnings (loss) from unconsolidated affiliates, net, adjusted for cash distributions received	0.7		(138.0)		(6.5)		0.7		(138.0)
Deferred income taxes	(1.1)		0.4		(0.1)		(1.2)		—
Provision for income taxes	1.9		0.2		0.4		1.7		0.1
Other non-cash income (expense)	0.1		(0.3)		0.1		0.1		(0.3)
EBITDA	580.7		346.6		356.0		461.5		354.1
Unit-based compensation charges	37.2		34.9		30.7		37.2		34.9
Loss on long-lived assets, net	187.7		39.6		26.0		312.7		39.4
Goodwill impairment	—		—		80.3		—		—
Gain on acquisition	(75.3)		—		—		(75.3)		—

(Earnings) loss from unconsolidated affiliates, net	(15.7)		120.4		(32.5)		(15.7)		120.4
Adjusted EBITDA from unconsolidated affiliates, net	30.0		67.0		75.4		30.0		67.0
Change in fair value of commodity inventory-related derivative contracts	(14.4)		(13.5)		33.6		(14.4)		(13.5)
Significant transaction and environmental related costs and other items	31.9		5.1		10.8		31.9		2.5
Adjusted EBITDA	$	762.1	$	600.1	$	580.3	$	767.9	$	604.8

Crestwood Equity Crestwood Midstream
Year Ended December 31, Year Ended December 31,
2017 2016 2015 2017 2016
EBITDA:
Net cash provided by operating activities $ 255.9
$ 346.1
$ 440.7
$ 262.2
$ 353.8
Net changes in operating assets and liabilities (0.3 ) (57.9 ) (98.0 ) (2.4 ) (56.8 )
Amortization of debt-related deferred costs, discounts and premiums (7.2 ) (6.9 ) (8.9 ) (7.2 ) (6.9 )
Interest and debt expense, net 99.4
125.1
140.1
99.4
125.1
Market adjustment on interest rate swaps —
—
0.5
—
—
Unit-based compensation charges (25.5 ) (19.2 ) (19.7 ) (25.5 ) (19.2 )
Loss on long-lived assets, net (65.6 ) (65.6 ) (821.2 ) (65.6 ) (65.6 )
Goodwill impairment (38.8 ) (162.6 ) (1,406.3 ) (38.8 ) (162.6 )
Loss on contingent consideration (57.0 ) —
—
(57.0 ) —
Earnings (loss) from unconsolidated affiliates, net, adjusted for cash distributions received 0.1
(7.6 ) (73.6 ) 0.1
(7.6 )
Deferred income taxes 2.1
3.1
3.6
—
(0.2 )
Provision (benefit) for income taxes (0.8 ) 0.3
(1.4 ) —
—
Other non-cash expense (0.9 ) (1.9 ) (0.7 ) (0.9 ) (1.9 )
EBITDA 161.4
152.9
(1,844.9 ) 164.3
158.1
Unit-based compensation charges 25.5
19.2
19.7
25.5
19.2
Loss on long-lived assets, net 65.6
65.6
821.2
65.6
65.6
Goodwill impairment 38.8
162.6
1,406.3
38.8
162.6
Loss on contingent consideration 57.0
—
—
57.0
—
(Earnings) loss from unconsolidated affiliates, net (47.8 ) (31.5 ) 60.8
(47.8 ) (31.5 )
Adjusted EBITDA from unconsolidated affiliates, net 80.3
61.1
25.3
80.3
61.1
Change in fair value of commodity inventory-related derivative contracts 2.2
14.1
5.4
2.2
14.1
Significant transaction and environmental-related costs and other items⁽¹⁾
12.4
11.6
33.6
12.4
11.6
Adjusted EBITDA $ 395.4
$ 455.6
$ 527.4
$ 398.3
$ 460.8

(1) Significant transaction and environmental-related costs and other items for the years ended December 31, 2017, 2016 and 2015, primarily include costs incurred related to the Simplification Merger and other merger, acquisition and joint venture transactions, as well as costs associated with our historical cost savings initiatives and the realignmentTable of ~~our MS&L operations and related consolidation and relocation of our corporate offices.~~Contents

Segment Results

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


	Gathering and Processing North		Gathering and Processing South		Storage and Logistics
Revenues	$	1,010.7	$	381.4	$	4,608.6
Intersegment revenues	527.2		207.5		(734.7)
Costs of product/services sold	848.6		399.5		3,749.0
Operations and maintenance expense	105.3		43.0		47.8
Loss on long-lived assets, net	—		(308.9)		(4.1)

Gain on acquisition	—		75.3		—
Earnings from unconsolidated affiliates, net	—		11.1		4.6
Crestwood Midstream EBITDA for the year ended December 31, 2022	$	584.0	$	(76.1)	$	77.6
Gain on long-lived assets(1)	—		125.0		—
Crestwood Equity EBITDA for the year ended December 31, 2022	$	584.0	$	48.9	$	77.6

Revenues	$	574.7	$	105.9	$	3,888.4
Intersegment revenues	459.3		—		(459.3)
Costs of product/services sold	553.2		0.9		3,289.8
Operations and maintenance expense	51.1		22.9		47.0
Gain (loss) on long-lived assets, net	0.4		(40.6)		0.7

Earnings (loss) from unconsolidated affiliates, net	—		9.6		(130.0)
EBITDA for the year ended December 31, 2021	$	430.1	$	51.1	$	(37.0)

Revenues	$	510.4	$	121.0	$	1,622.9
Intersegment revenues	160.5		(0.7)		(159.8)
Costs of product/services sold	261.0		0.5		1,339.0
Operations and maintenance expense	55.7		29.2		46.9
Loss on long-lived assets, net	(3.8)		(20.0)		(2.4)
Goodwill impairment	(80.3)		—		—
Earnings (loss) from unconsolidated affiliates, net	—		(1.0)		33.5
EBITDA for the year ended December 31, 2020	$	270.1	$	69.6	$	108.3

Crestwood Equity

Gathering and Processing
Storage and Transportation Marketing, Supply and Logistics
Revenues $ 1,688.2
$ 37.2
$ 2,155.5
Intersegment revenues 134.5
6.7
(141.2 )
Costs of product/services sold 1,480.8
0.3
1,893.6
Operations and maintenance expenses 68.4
4.2
63.4
Loss on long-lived assets, net (14.4 ) —
(48.2 )
Goodwill impairments —
—
(38.8 )
Loss on contingent consideration —
(57.0 ) —
Earnings from unconsolidated affiliates, net 18.9
28.9
—
Other income, net 0.8
—
—
EBITDA for the year ended December 31, 2017 $ 278.8
$ 11.3
$ (29.7 )

Revenues $ 1,118.8
$ 165.3
$ 1,236.4
Intersegment revenues 108.6
4.2
(112.8 )
Costs of product/services sold 917.0
5.1
1,003.0
Operations and maintenance expenses 77.0
21.4
59.7
Loss on long-lived assets, net (2.0 ) (32.2 ) (31.4 )
Goodwill impairments (8.6 ) (44.9 ) (109.1 )
Earnings from unconsolidated affiliates, net 20.3
11.2
—
EBITDA for the year ended December 31, 2016 $ 243.1
$ 77.1
$ (79.6 )

Revenues $ 1,381.0
$ 266.3
$ 985.5
Intersegment revenues 66.7
—
(66.7 )
Costs of product/services sold 1,103.9
20.1
759.5
Operations and maintenance expenses 89.0
31.7
69.5
Loss on long-lived assets, net (787.3 ) (1.6 ) (32.3 )
Goodwill impairments (329.7 ) (623.4 ) (453.2 )
Loss from unconsolidated affiliates, net (43.4 ) (17.4 ) —
EBITDA for the year ended December 31, 2015 $ (905.6 ) $ (427.9 ) $ (395.7 )
(1)Represents the elimination of the loss on long-lived assets of approximately $53 million recorded by CMLP and the gain on long-lived assets of approximately $72 million recorded by CEQP related to the sale of our assets in the Barnett Shale. For a further discussion of the sale of our assets in the Barnett Shale, see Note 3.

Crestwood Midstream
Revenues $ 1,688.2
$ 37.2
$ 2,155.5
Intersegment revenues 134.5
6.7
(141.2 )
Costs of product/services sold 1,480.8
0.3
1,893.6
Operations and maintenance expenses 68.4
4.2
63.4
Loss on long-lived assets net (14.4 ) —
(48.2 )
Goodwill impairments —
—
(38.8 )
Loss on contingent consideration —
(57.0 ) —
Earnings from unconsolidated affiliates, net 18.9
28.9
—
Other income, net 0.8
—
—
EBITDA for the year ended December 31, 2017 $ 278.8
$ 11.3
$ (29.7 )

Revenues $ 1,118.8
$ 165.3
$ 1,236.4
Intersegment revenues 108.6
4.2
(112.8 )
Costs of product/services sold 917.0
5.1
1,003.0
Operations and maintenance expenses 77.0
18.3
59.7
Loss on long-lived assets, net (2.0 ) (32.2 ) (31.4 )
Goodwill impairments (8.6 ) (44.9 ) (109.1 )
Earnings from unconsolidated affiliates, net 20.3
11.2
—
EBITDA for the year ended December 31, 2016 $ 243.1
$ 80.2
$ (79.6 )

~~Segment Results~~

Below is a discussion of the factors that impacted EBITDA by segment for the ~~years~~year ended December 31, ~~2017~~, ~~2016~~ ~~and~~ ~~2015~~.2022 compared to the year ended December 31, 2021.

Gathering and Processing North

~~Year Ended~~EBITDA for our gathering and processing north segment increased by approximately $153.9 million during the year ended December 31, ~~2017 Compared~~2022 compared to ~~Year Ended~~2021. On February 1, 2022, we completed the merger with Oasis Midstream, and as a result, we began reflecting the financial results of the Williston Basin operations acquired in the Oasis Merger in our gathering and processing north segment. For a further discussion of this merger, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.

Our gathering and processing north segment’s revenues increased by approximately $503.9 million during the year ended December 31, ~~2016~~2022 compared to 2021, while our costs of product/services sold increased by approximately $295.4 million during 2022 compared to 2021. During the year ended December 31, 2022, we recognized revenues of approximately $348.6 million and product costs of approximately $105.2 million, related to the Williston Basin operations acquired in the Oasis Merger. The remaining increases in our gathering and processing north segment’s revenues and costs of product/services sold were primarily driven by our Arrow operations which experienced higher average commodity prices on its agreements under

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which it purchases and sells crude oil and natural gas. Arrow’s realized prices on its commodity sales increased by more than 50% during 2022 compared to 2021. Arrow’s costs of product/services sold increased more than its revenues as a result of a decrease in its natural gas gathering and processing volumes and crude oil gathering volumes, which decreased by 14%, 13% and 31%, respectively, during 2022 compared to 2021. These volume decreases primarily resulted from lower activity by our producer customers due to natural production declines and the impact that supply chain and other operational issues had on our customers during 2022, and unusual winter weather conditions experienced during 2022 that unfavorably impacted our operations and our customers’ operations.

Our gathering and processing north segment’s operations and maintenance expenses increased by approximately $54.2 million during the year ended December 31, 2022 compared to 2021, primarily due to the Williston Basin operations acquired in the Oasis Merger.

Gathering and Processing South

EBITDA for CMLP’s gathering and processing south segment decreased by approximately $127.2 million during the year ended December 31, 2022 compared to 2021. CMLP’s gathering and processing south segment’s EBITDA was impacted by the Delaware Basin operations acquired in the Oasis Merger, the Sendero Acquisition and the CPJV Acquisition as well as the divestitures of our operations in the Barnett and Marcellus Shales during 2022. For a further discussion of these strategic transactions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.

Our gathering and processing south segment’s revenues, costs of product/services sold and operations and maintenance expenses increased by approximately $483.0 million, $398.6 million, and $20.1 million, respectively, during the year ended December 31, 2022 compared to 2021.

The Sendero Acquisition and CPJV Acquisition on July 11, 2022 increased our gathering and processing south segment’s revenues, cost of product/services sold and operations and maintenance expenses by approximately $519.3 million, $419.6 million and $23.4 million, respectively, during the year ended December 31, 2022 compared to 2021. In addition, we recognized a gain of approximately $75.3 million during 2022 related to the CPJV Acquisition.

In addition to the contributions from the acquisitions described above, the Delaware Basin operations acquired in the Oasis Merger on February 1, 2022 also increased our gathering and processing south segment’s revenues, cost of product/services sold and operations and maintenance expenses by approximately $19.6 million, $0.8 million and $5.0 million, respectively, during the year ended December 31, 2022.

Partially offsetting the increases described above were the divestitures of our Barnett and Marcellus operations during 2022, which decreased our gathering and processing south segment’s revenues, costs of product/services sold and operations and maintenance expenses by approximately $34.8 million, $1.4 million and $7.7 million, respectively, during the year ended December 31, 2022 compared to 2021. During the year ended December 31, 2022, CMLP recognized a loss on long-lived assets related to the Barnett and Marcellus divestitures of approximately $53 million and $250 million, respectively.

Also impacting our gathering and processing south segment’s EBITDA during the year ended December 31, 2022 was a loss on long-lived assets of approximately $7.0 million related to the anticipated sale of parts inventory related to our legacy Granite Wash operations. In addition, during the year ended December 31, 2021, we recorded an impairment of approximately $40.1 million of our property, plant and equipment related to the compressor stations in our Marcellus operations based on the actual or anticipated dismantlement and redeployment of those assets to other areas.

Our gathering and processing south segment’s EBITDA was also impacted by a net increase in earnings from unconsolidated affiliates of approximately $1.5 million during the year ended December 31, 2022 compared to 2021, due to an increase in equity earnings of approximately $2.4 million related to the Crestwood Permian Basin equity investment acquired in conjunction with the CPJV Acquisition, partially offset by a decrease in equity earnings of approximately $0.9 million due to the consolidation of our Crestwood Permian equity investment as a result of the acquisition of the remaining 50% equity interest in July 2022.

EBITDA for CEQP’s ~~and CMLP’s~~ gathering and processing south segment decreased by approximately $2.2 million during the year ended December 31, 2022 compared to 2021. The change in CEQP’s gathering and processing south segment’s EBITDA year over year was due to all of the factors discussed above for CMLP. However, CEQP did not record a loss on long-lived assets during 2022 related to the divestiture of the Barnett operations due to historical impairments previously recorded by CEQP on Barnett’s long-lived assets. During 2022, CEQP recorded a gain on the Barnett divestiture of approximately $72 million.

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Storage and Logistics

EBITDA for our storage and logistics segment increased by approximately ~~$35.7~~$114.6 million during the year ended December, 2022 compared to 2021. Our storage and logistics segment’s EBITDA for the year ended December 31, ~~2017 compared~~2021 was impacted by a reduction to ~~2016. During~~the equity earnings from our Stagecoach Gas Services LLC (Stagecoach Gas) equity method investment as a result of recording our proportionate share of a loss on long-lived assets (including goodwill) recorded by the equity method investee as further discussed below.

Our storage and logistics segment’s revenues increased by approximately $444.8 million during the year ended December 31, ~~2017,~~2022 compared to 2021, and our ~~gathering and processing segment’s revenues~~costs of product/services sold increased by approximately ~~$595.3~~$459.2 million during 2022 compared to ~~2017, partially offset by~~2021.

Our NGL marketing and logistics operations experienced an increase in revenues of approximately $151.8 million and an increase in costs of product/services sold of approximately ~~$563.8~~$160.1 million ~~during 2017 compared to 2016.~~

~~The increases in revenues and costs~~ during the year ended December 31, ~~2017~~2022 compared to 2021. These increases were primarily driven by higher NGL prices as a result of overall increases in commodity prices during 2022 compared to 2021. In addition, our ~~Arrow~~NGL marketing and logistics operations were impacted by lower demand for its storage, terminalling and marketing services during 2022 compared to 2021 as a result of warmer weather primarily in the East Coast, which ~~experienced a $611.0 million increase in revenues and a $578.5 million increase~~resulted in costs of product/services ~~compared to 2016. The increase in Arrow’s~~sold increasing more than revenues and costs was primarily driven by higher average prices on Arrow’s agreements under which it purchases and sells crude oil. In addition, crude, gas and water volumes gathered by our Arrow system increased by 30%, 10% and 27%, respectively, during the year ended December 31, ~~2017~~2022 compared to ~~2016, due to~~2021. Our NGL marketing and logistics operations’ costs of product/services sold was also impacted by the ~~connection~~effect of ~~97 wells~~increasing commodity prices on our ~~Arrow system during 2017 compared to 48 wells during 2016.~~

~~Partially offsetting the increase~~assets and liabilities from price risk management activities that manage our company-wide crude oil, natural gas and NGL commodity price exposures. Included in our ~~gathering and processing segment’s revenues and~~ costs ~~from our Arrow operations~~of product/services sold was a gain of $9.4 million during the year ended December 31, ~~2017~~2022 and a loss of $44.5 million during the year ended December 31, 2021 related to our price risk management activities.

Our crude oil and natural gas marketing operations experienced an increase in revenues of approximately $300.0 million during the year ended December 31, 2022 compared to ~~2016, were lower revenues~~2021, and an increase in product costs of approximately ~~$16.4~~$298.3 million during 2022 compared to 2021. These increases were primarily driven by higher crude oil purchases and ~~$10.6 million, respectively, from our Permian operations~~sales as a result of increases in commodity prices during 2022 compared to 2021, as well as an increase in marketing activity surrounding our natural gas-related operations driven by higher natural gas prices.

During the ~~deconsolidation~~year ended December 31, 2022, our COLT Hub operations experienced a 68% decrease in its crude oil rail loading volumes compared to 2021 due to lower demand for its rail loading services as a result of ~~Crestwood New Mexico~~lower basis differentials in ~~June 2017.~~the Bakken, which resulted in a decrease in revenues of approximately $7 million compared to 2021.

Our storage and logistics segment’s EBITDA was impacted by a loss on long-lived assets of approximately $4.1 million during the year ended December 31, 2022, primarily due to the buyout of leases related to our exiting the crude oil railcar leasing business. For a further discussion of this matter, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 11.

Our storage and logistics segment’s EBITDA was also impacted by a net increase in earnings from unconsolidated affiliates of approximately $134.6 million during the year ended December 31, 2022 compared to 2021. During 2021, our results included a loss from unconsolidated affiliates of approximately $139.2 million from our Stagecoach Gas equity investment that was sold in 2021 to a subsidiary of Kinder Morgan through a series of transactions. This loss primarily related to a $158.7 million reduction to the equity earnings from our Stagecoach Gas equity investment during the year ended December 31, 2021 primarily as a result of recording our proportionate share of a loss on long-lived assets (including goodwill) recorded by the equity method investee. For a further discussion of this transaction, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6.

~~Our gathering and processing segment’s operations and maintenance expenses~~5. During the year ended December 31, 2022, earnings from our Tres Holdings equity investment decreased by ~~approximately $8.6~~$4.1 million compared to 2021, primarily due to the unusual cold weather experienced in early 2021 which resulted in higher revenues from natural gas inventory sales and an increase in demand for its storage and transportation services during the year ended December 31, ~~2017 compared to 2016, due to continued cost-reduction efforts undertaken in our operations~~2021.

Other Items Affecting EBITDA Results

General and ~~the deconsolidation of Crestwood New Mexico.~~

~~Our gathering and processing segment’s EBITDA for~~Administrative Expenses. During the year ended December 31, ~~2017 includes a loss on long-lived assets of approximately $14.4 million,~~2022, our general and administrative expenses increased compared to 2021, primarily ~~related~~due to ~~the retirement and/or disposition of certain of~~transaction costs incurred in connection with our ~~Marcellus and Arrow gathering and processing assets.~~

~~The comparability of our G&P segment’s EBITDA was impacted by an $8.6 million impairment recorded~~strategic transactions executed during ~~the year ended December 31, 2016 related to our Marcellus operations. For a~~2022 as further ~~discussion of these impairments, see~~ ~~“Critical Accounting Estimates and Policies”~~ ~~above and~~discussed in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.3.

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~~Our gathering~~

Items not affecting EBITDA include the following:

Depreciation, Amortization and processing segment’s EBITDA was also impacted by a decrease in earnings from unconsolidated affiliates of approximately $1.4 million during the year ended December 31, 2017 compared to 2016. The decrease was primarily driven by a $10.3 million decrease in equity earnings from Jackalope resulting from a reduction in revenues at the equity investment as a result of the restructuring of its contracts with Chesapeake effective January 1, 2017. Jackalope and Chesapeake replaced the cost-of-service based contract with a fixed-fee gathering and processing contract that includes minimum revenue guarantees for a five to seven year period. Partially offsetting the decrease in equity earnings from Jackalope was an increase in equity earnings from our Crestwood Permian equity investment of approximately $8.9 million during the year ended December 31, 2017 compared 2016, primarily due to the contribution of Crestwood New Mexico to Crestwood Permian in June 2017, and the Nautilus system coming online in June 2017.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~

EBITDA for CEQP’s G&P segment increased by approximately $1,148.7 million for the year ended December 31, 2016 compared to 2015. The comparability of our G&P’s segment results year-over-year was significantly impacted by property, plant and equipment, intangible asset and goodwill impairments recorded during 2016 and 2015, which are further described below.

Accretion Expense. During the year ended December 31, ~~2016,~~2022, our ~~G&P segment’s revenues were lower by approximately $220.3 million~~depreciation, amortization and accretion expense increased compared to ~~2015,~~2021, primarily due to our acquisitions during 2022, partially offset by ~~lower costs of product/services sold of approximately $186.9 million. These decreases were primarily driven by our Arrow operations, which experienced a $193.9 million reduction in revenues during~~ the ~~year ended December 31, 2016 compared to 2015, offset by a $194.0 million decrease in costs of product/services sold. These~~

decreases in Arrow’s revenues and costs were driven by lower market prices on crude oil, which caused average prices on Arrow’s agreements under which it purchases and sells crude to decrease. Gathering volumes on the Arrow system were relatively flat in 2016 compared to 2015.

Also contributing to the decrease in our G&P segment’s revenues were lower service revenues from our Marcellus and Barnett operations of approximately $20.7 million and $14.8 million, respectively, during the year ended December 31, 2016 compared to 2015. During the year ended December 31, 2016, we experienced a decrease in our gathering and compression volumes on our Marcellus system due to lack of drilling from our primary customer, Antero, as a result of the decline in commodity prices. Our gathering and compression volumes were 0.4 Bcf/d and 0.5 Bcf/d, respectively during the year ended December 31, 2016 compared to 0.5 Bcf/d and 0.6 Bcf/d during 2015. Our Barnett operations experienced a decrease in service revenues during 2016 compared to 2015 as a resultdivestitures of our ~~primary customer, Quicksilver, ceasing drilling~~operations in the Barnett and ~~shutting in production~~Marcellus Shales during the first quarter of 2016 as a result of its filing for bankruptcy protection under Chapter 11 of the U.S. Bankruptcy Code. In April 2016, BlueStone bought Quicksilver’s assets out of bankruptcy and thereafter returned to production wells that were previously shut-in by Quicksilver. We entered into new 10-year gathering and processing agreements with BlueStone and pursuant to those agreements, BlueStone will not shut-in or choke back production for economic purposes through the end of 2018. As a result, gathering and processing volumes on our Barnett system have returned to levels relatively consistent with those preceding Quicksilver’s bankruptcy filing.

Partially offsetting the decreases from our Arrow, Marcellus and Barnett operations discussed above, were lower operations and maintenance expenses of $12.0 million during the year ended December 31, 2016 compared to 2015, primarily as a result of our cost reduction initiatives implemented in 2015.

Our G&P segment’s EBITDA was also impacted by a goodwill impairment of $8.6 million recorded during 2016 related to our Marcellus operations compared to property, plant and equipment, intangible asset and goodwill impairments of approximately $1,116.0 million recorded during 2015 related to our Barnett, Fayetteville, Granite Wash, and Haynesville operations.2022. For a further discussion of these ~~impairments, see~~ ~~“Critical Accounting Estimates and Policies”~~ ~~above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.~~

Our G&P segment’s EBITDA was impacted by an increase in net earnings from unconsolidated affiliates of approximately $63.7 million. During the year ended December 31, 2016, earnings from our Jackalope equity investment increased by $64.2 million primarily due to a $51.4 million impairment recorded on the investment in 2015 and higher gathering and processing volumes at the facility resulting from Jackalope placing the Bucking Horse processing plant into service in 2015.

~~Storage and Transportation~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~

EBITDA for CMLP’s storage and transportation segment decreased by approximately $68.9 million during the year ended December 31, 2017 compared to 2016. During the year ended December 31, 2017, our storage and transportation segment’s revenues were lower due to a reduction in revenues of approximately $51.1 million from our COLT Hub operations compared to 2016. The decrease was primarily due to a reduction in our rail throughput revenues from the expiration of two rail loading contracts in late 2016, a 58% decrease in rail loading volumes and lower margins resulting from higher average crude oil prices in the Bakken compared to other basins, which has decreased the demand and rates for our rail loading services in 2017 compared to 2016. Also impacting our storage and transportation segment’s EBITDA was $44.9 million of goodwill impairments recorded during the year ended December 31, 2016 related to our COLT Hub operations. For a further discussion of these impairments, see ~~“Critical Accounting Estimates and Policies”~~ ~~above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.~~

The comparability of our storage and transportation segment’s EBITDA was also impacted by a $57 million loss on contingent consideration recorded during the year ended December 31, 2017 related to our Stagecoach Gas joint venture. Pursuant to the Stagecoach Gas limited liability company agreement, we may be required to make payments of up to $57 million to CEGP after December 31, 2020 if certain criteria are not met by Stagecoach Gas by December 31, 2020, including achieving certain performance targets on growth capital projects. These growth capital projects depend on the construction of other third-party expansion projects, and during 2017, those third-party projects experienced regulatory and other delays that caused Stagecoach Gas to delay its growth capital projects. Although Stagecoach Gas anticipates that these growth capital projects will be constructed in the future, it does not expect that these projects will produce meaningful operating results prior to December 31, 2020.

Our storage and transportation segment’s results was impacted by a $32.4 million loss recognized on the deconsolidation of our Northeast storage and transportation assets as a result of the contribution of these assets to the Stagecoach Gas joint venture in June 2016. The deconsolidation of the Northeast storage and transportation assets resulted in lower revenues and costs of product/services sold of approximately $74.5 million and $4.6 million, respectively, during the year ended December 31, 2017 compared to 2016. We also experienced lower operations and maintenance expenses of approximately $14.1 million during the year ended December 31, 2017 compared to 2016, primarily as a result of the deconsolidation of the Northeast storage and transportation assets. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 2 and 6 for a further discussion of the deconsolidation of our NE S&T assets.

Our storage and transportation segment’s EBITDA was impacted by an increase in earnings from our unconsolidated affiliates. As discussed above, in June 2016, we deconsolidated our Northeast storage and transportation assets as a result of the Stagecoach Gas transaction and began accounting for our 50% equity interest in Stagecoach Gas under the equity method of accounting. We recognized equity earnings from Stagecoach Gas of approximately $25.3 million and $15.9 million during the years ended December 31, 2017 and 2016. Earnings from our Tres Holdings equity investment increased by approximately $2.5 million during the year ended December 31, 2017 compared to 2016, primarily due to property tax accruals recorded by Tres Holdings during 2016.

EBITDA for CEQP’s storage and transportation segment decreased by approximately $65.8 million during the year ended December 31, 2017 compared to 2016. The change in CEQP’s storage and transportation segment’s EBITDA year-over-year was due to all the factors discussed above for CMLP. In addition, in June 2016, the Matagorda County court issued a final judgment related to Tres Palacios’ 2012 and 2013 property tax years which resulted in CEQP recording additional net property taxes (including interest and penalties) of approximately $2.9 million during the year ended December 31, 2016.

~~Year Ended December 31, 2016 Compared to Year Ended December 31, 2015~~

EBITDA for CEQP’s storage and transportation segment increased by approximately $505.0 million during the year ended December 31, 2016 compared to 2015. The comparability of our storage and transportation segment’s results year-over-year is primarily impacted by goodwill impairments recorded during 2016 and 2015, which are further described below. In addition, on June 3, 2016, we deconsolidated our NE S&T assets as a result of the contribution of the assets to Stagecoach Gas and we recognized a loss of $32.4 million. The deconsolidation of the NE S&T assets also resulted in lower revenues of approximately $102.3 million during the year ended December 31, 2016 compared to the 2015, partially offset by lower costs of product/services sold of approximately $8.7 million year-over-year. We also experienced lower operations and maintenance expense of approximately $11.9 million during the year ended December 31, 2016 compared to 2015, primarily as a result of the deconsolidation of the NE S&T assets. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Notes 2 and 6 for a further discussion of the deconsolidation of our NE S&T assets.

Our COLT Hub operations experienced an increase in revenues of approximately $5.4 million during the year ended December 31, 2016 compared to 2015, primarily due to the recognition in income of previously deferred revenues related to two rail loading contracts that expired in late 2016, which was partially offset by a related reduction in our actual rail throughput revenues resulting from lower rail loading volumes primarily under those contracts. Our lower rail loading volumes were a result of narrowed crude oil locational differences in the Bakken, and were partially offset by a related decrease in costs of product/services sold of $6.3 million during the year ended December 31, 2016 compared to 2015.

Our storage and transportation segment’s EBITDA was also impacted by goodwill impairments related to our COLT Hub operations of approximately $44.9 million and $623.4 million during the years ended December 31, 2016 and 2015. For a further discussion of our goodwill impairments recorded during 2016 and 2015, see ~~“Critical Accounting Estimates and Policies”~~ ~~above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.~~

In June 2016, the Matagorda County court issued a final judgment related to Tres Palacios’ 2012 and 2013 property tax years which resulted in Crestwood Equity recording additional net property taxes (including interest and penalties) of approximately $2.9 million during the year ended December 31, 2016.

Our storage and transportation segment’s EBITDA was impacted by a $28.6 million increase in earnings from unconsolidated affiliates. As discussed above, effective June 3, 2016, we deconsolidated the NE S&T assets as a result of the Stagecoach Gas transaction and began accounting for our 50% equity interest in Stagecoach Gas under the equity method of accounting. We recognized equity earnings from Stagecoach Gas of approximately $15.9 million during the year ended December 31, 2016. Our equity earnings from Tres Holdings were lower by approximately $2.8 million during the year ended December 31, 2016 compared to the same period in 2015, primarily due to an increase in property tax accruals at the equity investment. Our equity earnings from our PRBIC equity investment increased by $15.5 million, primarily due to an impairment of $23.4 million of the

investment recorded in 2015, partially offset by a $4.4 million loss from the investment in 2016 driven by an impairment recorded at the equity investee level due to declining actual and forecasted revenues from its major customer, Chesapeake.

~~Marketing, Supply and Logistics~~

~~Year Ended December 31, 2017 Compared to Year Ended December 31, 2016~~

EBITDA for our marketing, supply and logistics segment increased by approximately $49.9 million for the year ended December 31, 2017 compared to 2016. The comparability of our marketing, supply and logistics segment’s results was significantly impacted by goodwill, intangible assets and property, plant and equipment impairments of $121.0 million recorded during 2017 and goodwill and intangible asset impairments of $140.5 million recorded during 2016. For a further discussion of our impairments recorded during 2017 and 2016, see ~~“Critical Accounting Estimates and Policies”~~ ~~above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.~~

Our supply and logistics operations experienced an increase in revenues and costs of product/services sold of $465.0 million and $457.9 million, respectively, during the year ended December 31, 2017 compared to 2016. During 2016, we experienced unseasonably warm weather which resulted in lower demand for NGLs compared to increased demand experienced during 2017. The costs of product/services sold increase includes losses of $31.2 million and a loss of $7.8 million during the years ended December 31, 2017 and 2016 related to our commodity-based derivative contracts. These changes in the fair value of our derivative contracts resulted from higher average NGL prices compared to 2016, which resulted in an increase in our liabilities from price risk management activities associated with contracts that provide fixed prices on future sales of our NGL inventory.

During the year ended December 31, 2017, our storage and terminals operations (including our West Coast operations) experienced a $173.6 million and $174.4 million increase in revenues and costs of product/services sold, respectively, compared to 2016. These increases were primarily driven by increases in NGL prices during the year ended December 31, 2017. Although our net operating results were relatively consistent during the year ended December 31, 2017 compared to 2016, we experienced NGL market headwinds in the Northeast during 2017, with NGL exports and other market dynamics causing price differentials to narrow between purchasing NGLs in the summer (which are then stored in our NGL facilities) and selling NGLs in the winter. These dynamics also caused the rates that we are able to charge for storing NGLs in our facilities to decline from their historical levels. Also during 2017, our West Coast customers also experienced headwinds, with both producers and refineries located in the Western U.S. experiencing regulatory challenges and an inflow of NGLs from the Eastern U.S. This caused demand for the gathering, processing and logistics services from our West Coast operations to remain relatively flat in 2017 compared to 2016. Considering the fact that the net operating results of our storage and terminals operations (including West Coast) have been relatively consistent over the past several years, we do not anticipate that these operations will grow as fast or to the degree that we expected when we merged with Inergy, LP in 2013 given current market dynamics, which we believe will continue for the foreseeable future.

Revenues and costs of product/services sold from our crude and natural gas marketing operations increased by approximately $261.9 million and $260.5 million, respectively, during the year ended December 31, 2017 compared to 2016. These increases were primarily driven by higher crude marketing volumes due to increased marketing activity surrounding our crude-related operations.

Our NGL and crude trucking operations continued to experience lower operating results in 2017 compared to 2016, with a $12.4 million and $5.7 million decrease in revenues and costs of product/services sold during the year ended December 31, 2017 compared to 2016. This decrease was primarily a result of the realignment of our trucking operations in 2017 to reduce the size of our trucking fleet in response to the continued decline in demand for trucking services due to the continued lower commodity price environment.

Our marketing, supply and logistic segment’s operations and maintenance expenses increased by approximately $3.7 million during the year ended December 31, 2017 compared to 2016. In 2016, we received a $3.1 million property tax refund related to our West Coast operations.

In December 2017, we sold 100% of our equity interests in US Salt to an affiliate of Kissner Group Holdings LP for net proceeds of approximately $223.6 million, and we recognized a gain of approximately $33.6 million from the sale. For a further discussion of this sale,transactions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.

~~Year Ended~~Interest and Debt Expense, Net. During the year ended December 31, ~~2016 Compared~~2022, our interest and debt expense, net increased primarily due to ~~Year Ended December 31, 2015~~

~~EBITDA for~~the senior notes acquired in conjunction with the merger with Oasis Midstream and the Crestwood Permian credit facility acquired in conjunction with the acquisition of the 50% equity interest in Crestwood Permian. In addition, our ~~marketing, supply~~interest and ~~logistics segment~~debt expense increased ~~by approximately $316.1 million~~due to (i) additional borrowings under the Crestwood Midstream credit facility to fund the cash consideration in conjunction with our acquisitions during 2022; (ii) borrowings to fund the repayment of the Oasis Midstream credit facility acquired in conjunction with the Oasis Merger; and (iii) higher interest rates during the year ended December 31, ~~2016~~2022 compared to ~~2015. The comparability~~2021. These increases in borrowings were partially offset by the proceeds received from the sale of our ~~marketing, supply~~Barnett and ~~logistics segment’s results year over year is impacted by goodwill impairments recorded~~Marcellus assets during ~~2016 and 2015, which are further described below.~~

Our NGL and crude trucking operations experienced a continued decrease in the demand for their services due to lower volumes, increased competition, excess trucking capacity in the market place and the low commodity price environment during the year ended December 31, 2016, resulting in a 18% and 65% decrease in NGL and crude volumes transported, respectively, compared to 2015. This resulted in a $34.6 million decrease in revenues during the year ended December 31, 2016 compared to 2015, and a $21.8 million decrease in costs of services sold from these operations during the same period.

During the year ended December 31, 2016, our storage and terminals operations (including our West Coast operations) experienced a $147.7 million increase in revenues compared to 2015, in addition to an increase in costs of product/services sold of approximately $167.6 million. Although these operations experienced an increase in demand for its propane-related services year-over-year, it experienced lower demand for its butane-related services (which tend to generate higher per unit margins than its propane services). The lower butane demand was driven by lower NGL commodity prices and tightening of basis differentials on these operations in 2016 compared to 2015.

Our supply and logistics operations experienced a decrease in revenues of approximately $58.0 million and a decrease in costs of product/services sold of $51.0 million during the year ended December 31, 2016 compared to 2015. These decreases were due to the low commodity price environment coupled with warmer weather during 2016 compared to 2015, which resulted in lower demand for the butane-related services provided by these operations. These revenues and costs of services decreases include a loss of $7.8 million on our commodity-based derivative contracts of during the year ended December 31, 2016 and a gain of $18.9 million during the year ended December 31, 2015.

During the year ended December 31, 2016, revenues from our crude marketing operations increased by approximately $146.8 million compared to 2015, in addition to an increase of approximately $147.6 million in our costs of product/services sold year-over-year, both of which were driven by higher crude marketing volumes due to increased marketing activity surrounding our crude-related operations during 2016.

Our marketing, supply and logistics segment’s operations and maintenance expense decreased by $9.8 million during the year ended December 31, 2016 compared to 2015, primarily due to our cost-savings initiative implemented in 2015.

Our marketing, supply and logistics segment’s EBITDA for the year ended December 31, 2016 was also impacted by intangible asset and goodwill impairments of approximately $140.5 million related to our supply and logistics, storage and terminals and trucking operations compared to property, plant and equipment and goodwill impairments of $484.4 million related to our West Coast, supply and logistics, storage and terminals, trucking and Watkins Glen operations in 2015.2022. For a further discussion of the long-term debt assumed in conjunction with our ~~impairments recorded~~acquisitions during ~~2016 and 2015, see~~ ~~“Critical Accounting Estimates”~~ ~~above and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.~~

~~Other EBITDA Results~~

~~General and Administrative Expenses.~~

During the year ended December 31, 2017, our general and administrative expenses increased compared to 2016, primarily due to an increase in unit-based compensation charges based on higher average awards outstanding in 2017 compared to 2016, and the impact of performance units granted during 2017 under the Crestwood Equity Long Term Incentive Plan (Crestwood LTIP). For a further discussion of Crestwood LTIP,2022, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 13. In addition, we incurred additional expense during the year ended December 31, 2017, related to the consolidation and relocation of our three corporate offices into two offices located in Houston and Kansas City.9.

During 2015, we completed a number of cost-reduction efforts, including the Simplification Merger (see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2 for a discussion of the Simplification Merger), and as a result we decreased our ongoing operations and maintenance expense and general and administrative expense. During the year ended December 31, 2016 compared to 2015, we experienced a decrease of approximately $28.1 million in Crestwood Equity’s general and administrative expenses primarily as a result of our cost-savings initiatives.

~~Items not affecting EBITDA include the following:~~

~~Depreciation, Amortization and Accretion Expense.~~ During the year ended December 31, 2017, our depreciation, amortization and accretion expense decreased compared to 2016 and 2015, primarily due to the deconsolidation of our Crestwood New Mexico operations in June 2017, the deconsolidation of our NE S&T assets in June 2016, and a reduction in the carrying value of certain of our assets as a result of impairments on our property, plant and equipment and intangible assets recorded during 2015.

~~Interest and Debt Expense, Net.~~ During the year ended December 31, 2017, interest and debt expense, net decreased compared to 2016 and 2015, primarily due to the repayments of Crestwood Midstream’s 2020 Senior Notes and 2022 Senior Notes. For a discussion of our long-term debt and related transactions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 9.

The following table provides a summary of our interest and debt expense, net (in millions).:


	CEQP						CMLP
	Year Ended December 31,						Year Ended December 31,							Year Ended December 31,
	2017		2016		2015		2017		2016		2015			2022		2021		2020
Credit facilities	$	18.6	$	18.7	$	25.2	$	18.6	$	18.7	$	17.2	Credit facilities	$	40.2	$	14.4	$	23.3
Senior notes	76.4		99.9		108.4		76.4		99.9		107.8		Senior notes	137.5		109.1		106.1
Other debt-related costs	7.3		7.2		9.0		7.3		7.2		8.0

Other, net													Other, net	2.7		9.0		6.9
Gross interest and debt expense	102.3		125.8		142.6		102.3		125.8		133.0		Gross interest and debt expense	180.4		132.5		136.3
Less: capitalized interest	2.9		0.7		2.5		2.9		0.7		2.5		Less: capitalized interest	3.0		0.4		2.7
Interest and debt expense, net	$	99.4	$	125.1	$	140.1	$	99.4	$	125.1	$	130.5	Interest and debt expense, net	$	177.4	$	132.1	$	133.6

Table of ~~certain of our Marcellus and Arrow gathering and processing assets.~~

~~Intangible Assets~~

~~Intangible assets consisted of the following at~~ ~~December 31, 2017~~ ~~and~~ ~~2016~~ (~~in millions~~):

Contents

CEQP CMLP
December 31, December 31,
2017 2016 2017 2016
Customer accounts $ 438.9
$ 541.9
$ 438.9
$ 541.9
Covenants not to compete —
1.0
—
1.0
Gas gathering, compression and processing contracts 325.2
325.2
325.2
325.2
Trademarks 24.7
30.5
9.2
15.0
788.8
898.6
773.3
883.1
Less: accumulated amortization 191.6
241.2
177.6
230.2
Total intangible assets, net $ 597.2
$ 657.4
$ 595.7
$ 652.9

The following table summarizes total accumulated amortization of our intangible assets at (in millions):


	December 31,
	2022		2021
Customer relationships(1)	$	230.2	$	183.2
Revenue contracts(1)	64.6		204.6
Trademarks	5.9		5.4
Total accumulated amortization	$	300.7	$	393.2

(1)The change in our intangible assets’ accumulated amortization during the year ended December 31, ~~2017~~2022 primarily relates to our acquisitions and ~~2016~~ (divestitures which are further discussed in ~~millions~~):Note 3.

CEQP CMLP
December 31, December 31,
2017 2016 2017 2016
Customer accounts $ 89.8
$ 162.4
$ 89.8
$ 162.4
Gas gathering, compression and processing contracts 82.0
63.2
82.0
63.2
Trademarks 19.8
15.6
5.8
4.6
Total accumulated amortization $ 191.6
$ 241.2
$ 177.6
$ 230.2

~~Crestwood Equity’s amortization~~Amortization expense related to ~~its intangible assets for the years ended~~ ~~December 31, 2017~~, ~~2016~~ ~~and~~ ~~2015, was approximately $53.7 million, $72.5 million and $102.8 million. Crestwood Midstream’s amortization expense related to its~~our intangible assets for the years ended December 31, ~~2017, 2016~~2022, 2021 and ~~2015~~2020, was approximately ~~$50.6~~$78.9 million, ~~$69.3~~$61.4 million and ~~$89.6~~$60.7 million.

Estimated amortization of our intangible assets for the next five years is as follows (in millions):


Year Ending December 31,
2023	$	64.0
2024	$	60.7
2025	$	60.7
2026	$	60.7
2027	$	60.7

CEQP CMLP
Year Ending
December 31,

2018 $ 43.4
$ 42.0
2019 41.7
41.7
2020 41.7
41.7
2021 41.7
41.7
2022 41.7
41.7

Accrued Expenses and Other Liabilities

Accrued expenses and other liabilities consisted of the following at (in millions):



	December 31,
		2022		2021
CMLP
Accrued expenses		$	66.5	$	66.2
Accrued property taxes		8.4		4.5
Income tax payable		0.9		0.4
Interest payable		43.2		30.6
Accrued additions to property, plant and equipment		35.6		17.4
Operating leases		10.9		13.2
Finance leases		1.9		1.7
Contract liabilities		11.7		10.7
Asset retirement obligations		0.4		1.4
Total CMLP accrued expenses and other liabilities		$	179.5	$	146.1
CEQP
Accrued expenses		1.2		0.9
Income tax payable		0.1		0.1
Total CEQP accrued expenses and other liabilities		$	180.8	$	147.1

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Other Long-Term Liabilities

Other long-term liabilities consisted of the following (in millions):



	December 31,
		2022		2021
CMLP
Contract liabilities		$	212.3	$	187.1
Operating leases		17.4		19.4
Asset retirement obligations		36.4		34.8
Intangible liabilities, net(1)		50.0		—
Other		14.2		12.8
Total CMLP other long-term liabilities		$	330.3	$	254.1
CEQP
Other		3.1		4.6
Total CEQP other long-term liabilities		$	333.4	$	258.7

(1)Intangible liabilities primarily consist of revenue contracts acquired in conjunction with the Sendero Acquisition and CPJV Acquisition during the year ended December 31, ~~2017~~2022. As of and ~~2016~~ (during the year ended December 31, 2022, accumulated amortization and amortization expenses related to these intangible liabilities was approximately $2.8 million. The estimated amortization of our intangible liabilities for the next 5 years is approximately $6.0 million in ~~millions~~):each year. See Note 3 for a further discussion of these intangible liabilities.

CEQP CMLP
December 31, December 31,
2017 2016 2017 2016
Accrued expenses $ 56.6
$ 46.5
$ 55.5
$ 45.1
Accrued property taxes 4.8
4.2
4.8
4.2
Accrued natural gas purchases —
4.9
—
4.9
Income tax payable 0.3
1.6
0.3
0.4
Interest payable 20.3
22.8
20.3
22.8
Accrued additions to property, plant and equipment 22.3
1.7
22.2
1.7
Capital leases 1.0
1.3
1.0
1.3
Deferred revenue 0.6
7.5
0.6
7.5
Total accrued expenses and other liabilities $ 105.9
$ 90.5
$ 104.7
$ 87.9

Note 5 - Asset Retirement Obligations

We have legal obligations to retire certain of our assets associated with our facilities and right-of-way contracts we hold. Where we can reasonably estimate the ~~asset retirement obligation,~~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.

~~The following table presents the changes in the net asset retirement obligations for the years ended December 31, 2017 and 2016 (in millions~~):

December 31,
2017 2016
Net asset retirement obligation at January 1 $ 27.8
$ 26.4
Liabilities incurred —
1.0
Liabilities settled (1.2 ) (1.2 )
Accretion expense 1.4
1.6
Change in estimate (0.5 ) —
Net asset retirement obligation at December 31 $ 27.5
$ 27.8

We did not have any material assets that were legally restricted for use in settling asset retirement obligations as of December 31, ~~2017~~2022 and ~~2016.~~2021.

The following table presents the changes in our net asset retirement obligations (in millions):


	December 31,
	2022		2021
Net asset retirement obligations at January 1	$	36.2	$	35.1
Liabilities acquired(1)	23.6		—
Liabilities incurred	2.3		—
Liabilities settled	(0.6)		(0.4)
Accretion expense	2.0		1.9
Other(2)	(26.7)		(0.4)
Net asset retirement obligations at December 31(3)	$	36.8	$	36.2

(1)Relates to obligations associated with acquisitions during 2022 as further discussed in Note 3.

(2)Relates primarily to obligations associated with the divestitures of our Barnett and Marcellus assets during 2022, as further discussed in Note 3.

(3)Includes $0.4 million and $1.4 million of current ARO liabilities at December 31, 2022 and 2021.

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Note 6 - Investments in Unconsolidated Affiliates

Net Investments and Earnings (Loss)

We account for each of our investments in unconsolidated affiliates under the equity method of accounting. Our Crestwood Permian Basin LLC (Crestwood Permian Basin) equity investment is included in our gathering and processing south segment. Our Tres Palacios Holdings LLC (Tres Holdings) and Powder River Basin Industrial Complex, LLC (PRBIC) equity investments are included in our storage and logistics segment.

Our net investments in and earnings (loss) from our unconsolidated affiliates are as follows (in millions, unless otherwise stated):


	Ownership Percentage		Investment				Earnings (Loss) from Unconsolidated Affiliates
	December 31,		December 31,				Year Ended December 31,
	2022		2022		2021		2022		2021		2020
Crestwood Permian Basin LLC(1)	50.00	%	$	76.5	$	—	$	2.4	$	—	$	—
Tres Palacios Holdings LLC(2)	50.01	%	39.8		36.2		5.2		9.3		—
Powder River Basin Industrial Complex, LLC(3)	50.01	%	3.2		3.5		(0.6)		(0.1)		(4.3)
Crestwood Permian Basin Holdings LLC	—	%	—		116.1		8.7		9.6		(1.0)
Stagecoach Gas Services LLC	—	%	—		—		—		(139.2)		37.8
Total			$	119.5	$	155.8	$	15.7	$	(120.4)	$	32.5

Ownership Percentage Investment Earnings (Loss) from Unconsolidated Affiliates
December 31, December 31, Year Ended December 31,
2017 2017 2016 2017 2016 2015
Stagecoach Gas Services LLC 50.00 % $ 849.8
$ 871.0
$ 25.3
$ 15.9
$ —

Jackalope Gas Gathering Services, L.L.C. 50.00 %
⁽¹⁾
184.9
197.2
10.5
20.8
(43.4 )
⁽³⁾
Crestwood Permian Basin Holdings LLC 50.00 % 102.0
(0.5 ) 8.4
(0.5 ) —

Tres Palacios Holdings LLC 50.01 % 37.8
39.0
2.2
(0.3 ) 2.5

Powder River Basin Industrial Complex, LLC⁽²⁾
50.01 % 8.5
8.7
1.4
(4.4 )
⁽³⁾
(19.9 )
⁽³⁾
Total $ 1,183.0
$ 1,115.4
$ 47.8
$ 31.5
$ (60.8 )
(1)As of December 31, 2022, our equity in the underlying net assets of Crestwood Permian Basin was less than our carrying value of our investment balance by approximately $2.3 million. During the year ended December 31, 2022, we recorded amortization of less than $0.1 million related to this basis difference, which we amortize over the life of Crestwood Permian Basin’s property, plant and equipment.


~~(1)~~	~~Excludes non-controlling interest related to our investment in Jackalope. See Note 12 for a further discussion of our non-controlling interest related to our investment in Jackalope.~~


~~(2)~~	During the year ended December 31, 2015, we recorded additional equity earnings of approximately $3.2 million related to a gain associated with the adjustment of our member’s capital account by our equity investee.

~~(3)~~

During the year ended December 31, 2016, we recorded a reduction of our equity earnings from PRBIC of approximately $5.8 million related to impairments recorded by our equity investee. During the year ended December 31, 2015, we recorded impairments of our PRBIC and Jackalope equity investments of approximately $23.4 million and $51.4 million. For a further discussion of these impairments, see Note 2.

(2)As of December 31, 2022, our equity in the underlying net assets of Tres Palacios Holdings LLC (Tres Holdings) exceeded the carrying value of our investment balance by approximately $20.2 million. During each of the years ended December 31, 2022, 2021 and 2020, we recorded amortization of approximately $1.3 million related to this excess basis, which we amortize over the life of Tres Palacios’ sublease agreement.

~~Description~~(3)As of ~~Investments~~December 31, 2022, our equity in the underlying net assets of Powder River Basin Industrial Complex, LLC (PRBIC) approximates the carrying value of our investment balance. During the year ended December 31, 2020, we recorded a $4.5 million reduction to the equity earnings from our PRBIC equity method investment as a result of recording our proportionate share of a long-lived asset impairment recorded by the equity method investee.

Crestwood Permian Basin Holdings LLC Acquisition

In ~~October 2016, Crestwood Infrastructure, our wholly-owned subsidiary, and an affiliate of First Reserve formed a joint venture,~~July 2022, we acquired the remaining 50% equity interest in Crestwood Permian ~~to fund~~Basin Holdings LLC (Crestwood Permian) and as a result, we control and own 100% of the ~~Nautilus gathering system (described below) and other potential investments~~equity interests in ~~the Delaware~~Crestwood Permian. As ~~part~~a result of this transaction, we ~~transferred to the~~eliminated our historical equity investment in Crestwood Permian ~~joint venture 100%~~of approximately $177.7 million as of the ~~equity interest of~~acquisition date and began consolidating Crestwood Permian’s operations. Our Crestwood Permian ~~Basin LLC (Crestwood Permian Basin), which owns the Nautilus~~equity investment was previously included in our gathering ~~system. We manage~~ and ~~account for our~~processing south segment. Crestwood Permian’s operations includes its 50% ~~ownership~~equity interest in Crestwood Permian Basin, which isowns a ~~VIE, under the equity method of accounting as we exercise significant influence, but do not control Crestwood Permian~~natural gas gathering system and ~~we are not its primary beneficiary due to First Reserve’s rights to exercise control over the entity.~~

~~Crestwood Permian Basin has a long-term agreement with SWEPI LP (SWEPI)~~related assets. Shell Midstream Partners, L.P., a subsidiary of Royal Dutch Shell plc, ~~to construct, own and operate a natural gas gathering system (the Nautilus gathering system) in SWEPI’s operated position in~~owns the

Delaware Permian. SWEPI has dedicated to Crestwood Permian Basin approximately 100,000 acres and gathering rights for SWEPI’s gas production across a large acreage position in Loving, Reeves and Ward Counties, Texas. Crestwood Permian Basin provides gathering, dehydration, compression and liquids handling services to SWEPI on a fixed-fee basis. In conjunction with the Crestwood Permian Basin’s agreement with SWEPI, Crestwood Permian granted Shell Midstream Partners L.P. (Shell Midstream), a subsidiary of Royal Dutch Shell plc, an option to purchase up to remaining 50% equity interest in Crestwood Permian Basin. In October 2017, Shell Midstream exercised its option and purchased a 50% equity interest in Crestwood Permian Basin from Crestwood Permian for approximately $37.9 million in cash. Crestwood Permian distributed to us approximately $18.9 million of the cash proceeds received.

CEQP issued a guarantee in conjunction with the Crestwood Permian Basin gas gathering agreement with SWEPI described above, under which CEQP has agreed to fund 100% of the costs to build the Nautilus gathering system (which is currently estimated to cost $180 million, of which approximately $84.3 million has been spent through December 31, 2017) if Crestwood Permian fails to do so. We do not believe this guarantee is probable of resulting in future losses based on our assessment of the nature of the guarantee, the financial condition of the guaranteed party and the period of time that the guarantee has been outstanding, and as a result, we have not recorded a liability on our balance sheet at December 31, 2017 and 2016.

On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico, our wholly-owned subsidiary that owns our Delaware Basin assets located in Eddy County, New Mexico. This contribution was treated as a transaction between entities under common control (because of our relationship with First Reserve), and accordingly we deconsolidated Crestwood New Mexico and our investment in Crestwood Permian was increased by the historical book value of these assets of approximately $69.4 million. In conjunction with this contribution, First Reserve has agreed to contribute to Crestwood Permian the first $151 million of capital costs required to fund the expansion of the Delaware Basin assets, which includes a new processing plant located in Orla, Texas and associated pipelines (Orla processing plant).

Stagecoach Gas Services LLC Divestiture

~~On June 3, 2016,~~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 formed Stagecoach Gas to own and further develop our NE S&T assets. During 2016, we contributed to Stagecoach Gas the entities owning the NE S&T assets. Additionally, CEGP contributed $975 million to Stagecoach Gas in exchange for a 50%sold each of their equity ~~interest~~interests in Stagecoach Gas and ~~Stagecoach Gas distributed~~its wholly-owned subsidiary, Twin Tier Pipeline LLC, (Second Closing) to ~~us the~~Kinder Morgan. We received cash proceeds ~~received (net~~ of approximately $3$15.4 million ~~of cash transferred~~related to the ~~joint venture) from CEGP. We deconsolidated~~Second Closing.

In conjunction with the ~~NE S&T assets as a result of this transaction discussed above~~Initial Closing and ~~began accounting for our 50% equity interest in Stagecoach Gas under the equity method of accounting. We recognized a loss of approximately $32.4 million on the deconsolidation of the NE S&T assets.~~

Pursuant to the Stagecoach Gas limited liability company agreement, we may be required to make payments of up to $57 million to CEGP after December 31, 2020 if certain criteria are not met by Stagecoach Gas by December 31, 2020, including achieving certain performance targets on growth capital projects. These growth capital projects depend on the construction of other third-party expansion projects, and during 2017, those third-party projects experienced regulatory and other delays that caused Stagecoach Gas to delay its growth capital projects. Although Stagecoach Gas anticipates that these growth capital projects will be constructed in the future, it does not expect that these projects will produce meaningful operating results prior to December 31, 2020. As a result, at December 31, 2017,Second Closing, we recorded a ~~liability of $57~~$155.6 million ~~for this obligation, which is reflected in other long-term liabilities on our consolidated balance sheet and in loss on contingent consideration~~reduction in our ~~consolidated income statement for~~equity earnings from unconsolidated affiliates during the year ended December 31, ~~2017.~~

~~Jackalope Gas Gathering Services, L.L.C.~~

~~Crestwood Niobrara LLC (Crestwood Niobrara),~~2021 related to losses recorded by us and our ~~consolidated subsidiary, owns a 50% ownership interest in Jackalope~~Stagecoach equity investment associated with the sale, which ~~we account for under~~also eliminated our $51.3 million historical basis difference between our investment balance and the equity ~~method~~in the underlying net assets of ~~accounting. Williams Partners LP operates~~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

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$3.1 million related to the sale, which were paid by us during 2021 on behalf of Stagecoach Gas. Our Stagecoach Gas equity investment was previously included in our storage and ~~owns the remaining 50% interest in Jackalope. Crestwood Niobrara manages the commercial operations of the Jackalope system.~~logistics segment.

Tres ~~Palacios~~ Holdings ~~LLC~~Divestiture

~~Crestwood Midstream owns a 50.01% ownership interest in Tres Palacios Holdings LLC (Tres Holdings)~~On February 20, 2023, we and ~~is the operator of Tres Palacios Gas Storage LLC (Tres Palacios) and its assets.~~ Brookfield Infrastructure Group ~~owns the remaining 49.99% ownership interest in Tres Holdings. We account for~~entered into an agreement with a third party to sell each of our ~~investment~~respective interests in Tres Holdings ~~under~~for net proceeds of approximately $335 million. The transaction is expected to close in the ~~equity method~~second quarter of ~~accounting.~~2023, subject to customary closing conditions.

~~Powder River Basin Industrial Complex, LLC~~Distributions and Contributions

~~Crestwood Crude Logistics LLC (Crude Logistics),~~The following table summarizes our consolidated subsidiary, owns a 50% ownership interest in PRBIC which we account for under the equity method of accounting. Twin Eagle Powder River Basin, LLC owns the remaining 50% ownership interest in PRBIC.

~~Summarized Financial Information of Unconsolidated Affiliates~~

~~Below is summarized financial information for~~distributions from and contributions to our ~~significant~~ unconsolidated affiliates (in ~~millions; amounts represent 100%~~millions):


	Distributions(1)						Contributions(2)
	Year Ended December 31,						Year Ended December 31,
	2022		2021		2020		2022		2021		2020
Crestwood Permian Basin	$	4.5	$	—	$	—	$	—	$	—	$	—
Tres Holdings	8.7		15.5		6.4		7.1		6.9		6.0
PRBIC	—		—		0.4		0.3		—		—
Crestwood Permian	13.6		16.3		11.9		83.5		10.7		3.4
Stagecoach Gas	—		640.9		59.7		—		—		—
Total	$	26.8	$	672.7	$	78.4	$	90.9	$	17.6	$	9.4

(1)In July 2021, Stagecoach Gas closed on the sale of ~~unconsolidated affiliate information~~):

~~Financial Position Data~~

December 31,
2017 2016
Current Assets Non-Current Assets Current Liabilities Non-Current Liabilities Members’ Equity Current Assets Non-Current Assets Current Liabilities Non-Current Liabilities Members’ Equity
Stagecoach⁽¹⁾
$ 55.1
$ 1,765.4
$ 7.0
$ 1.4
$ 1,812.1
$ 57.0
$ 1,807.6
$ 6.0
$ 4.1
$ 1,854.5
Other⁽²⁾⁽³⁾
81.3
801.1
53.4
93.6
735.4
50.4
708.5
23.2
74.4
661.3
Total $ 136.4
$ 2,566.5
$ 60.4
$ 95.0
$ 2,547.5
$ 107.4
$ 2,516.1
$ 29.2
$ 78.5
$ 2,515.8


~~(1)~~	As of December 31, 2017, our equity in the underlying net assets of Stagecoach Gas exceeded our investment balance by approximately $51.4 million. This excess amount is entirely attributable to goodwill and, as such, is not subject to amortization. Our Stagecoach Gas investment is included in our storage and transportation segment.

~~(2)~~

Includes our Jackalope, Tres Holdings, PRBIC and Crestwood Permian investments. As of December 31, 2017, our equity in the underlying net assets of Jackalope, Tres Holdings, PRBIC and Crestwood Permian exceeded our investment balance by approximately $0.7 million, $26.5 million, $6.4 million and $11.6 million, respectively. Our Tres Holdings and PRBIC investments are included in our storage and transportation segment and our Jackalope and Crestwood Permian investments are included in our gathering and processing segment.

~~(3)~~

On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico. This contribution was treated as a transaction between entities under common control (because of our relationship with First Reserve) and the accounting standards related to such transactions requires Crestwood Permian to record the assets and liabilities of Crestwood New Mexico at our historical book value. The difference between our equity in Crestwood New Mexico’s net assets and our investment balance is not subject to amortization.

~~Operating Results Data~~

Year Ended December 31,
2017 2016 2015
Operating Revenues Operating Expenses
Net
Income
Operating Revenues Operating Expenses
Net
Income
Operating Revenues Operating Expenses
Net
Income
Stagecoach $ 168.6
$ 77.7
$ 91.1
$ 99.3
$ 44.1
$ 55.3
$ —
$ —
$ —
Other⁽¹⁾
181.8
143.6
38.9
127.6
113.9
13.5
104.7
79.5
24.9
Total $ 350.4
$ 221.3
$ 130.0
$ 226.9
$ 158.0
$ 68.8
$ 104.7
$ 79.5
$ 24.9

~~(1)~~

~~Includes our Jackalope, Tres Holdings, PRBIC and Crestwood Permian 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 Jackalope equity investment of less than $0.1 million for both the years ended December 31, 2017 and 2016, and $3.0 million for the year ended December 31, 2015, which we amortize over the life of Jackalope’s gathering agreement with Chesapeake Energy Corporation (Chesapeake). We recorded amortization of the excess basis in our Tres Holdings equity investment of approximately $1.3 million for each of the years ended December 31, 2017, 2016 and 2015, which we amortize over the life of Tres Palacios’ sublease agreement. We recorded amortization of the excess basis in our PRBIC equity investment of approximately $0.6 million and $1.6 million for the years ended December 31, 2017 and 2016, which we amortize over the life of PRBIC’s property, plant and equipment and its agreement with Chesapeake.

~~Distributions and Contributions~~

Distributions Contributions
Year Ended December 31, Year Ended December 31,
2017 2016 2015 2017 2016 2015
Stagecoach Gas $ 47.3
$ 16.0
$ —
$ 0.8
$ —
$ —
Jackalope⁽¹⁾
26.3
27.4
12.5
3.5
1.4
25.4
Tres Holdings⁽²⁾
9.0
8.5
7.4
5.6
11.0
5.7
PRBIC⁽¹⁾
1.6
2.0
1.9
—
—
10.7
Crestwood Permian⁽³⁾
23.4
—
—
117.5
—
—
Total $ 107.6
$ 53.9
$ 21.8
$ 127.4
$ 12.4
$ 41.8

~~(1) Jackalope and PRBIC are required to make quarterly distributions~~ of its ~~available cash~~wholly-owned subsidiaries to ~~its members based on their respective ownership percentage. We~~

~~received~~ a ~~cash distribution~~subsidiary of ~~$7.4~~Kinder Morgan and distributed to us approximately $613.9 million ~~from Jackalope in January 2018, and we received a cash distribution of $0.3 million from PRBIC in February~~

~~2018.~~

~~(2) Tres Holdings is required, within 30 days following the end of each quarter, to make quarterly distributions of its available cash (as defined in its limited~~

~~liability company agreement) to its members based on their respective ownership percentage.~~

~~(3) On June 21, 2017, we contributed to Crestwood Permian 100% of the equity interest of Crestwood New Mexico at~~as our ~~historical book value of~~

~~approximately $69.4 million. This contribution was treated as a non-cash transaction between entities under common control.~~

~~Stagecoach Gas~~. Stagecoach Gas is required, within 30 days following the end of each quarter, to distribute 65% and 35% of its available cash (as defined in its limited liability company agreement) to CEGP and us, respectively. Because our ownership and distribution percentages differ, we determine the equity earnings from Stagecoach Gas using the Hypothetical Liquidation at Book Value (HLBV) method. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that we would receive if Stagecoach Gas were to liquidate all of its assets, as valued in accordance with GAAP, and distribute that cash to the members. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is ourproportionate share of the ~~earnings or losses~~gross proceeds received from the ~~equity investment for~~sale. We utilized approximately $3 million of these proceeds to pay transaction costs related to the ~~period, which approximates how earnings are allocated~~sale described above, $40 million of these proceeds to pay our remaining contingent consideration obligation and related accrued interest described below, and the remaining proceeds to repay a portion of the amounts outstanding under the ~~terms of the limited liability company agreement.~~ Crestwood Midstream credit facility.

(2)In January ~~2018,~~2023, we ~~received~~made a cash ~~distribution from Stagecoach Gas~~contribution of approximately ~~$11.3 million.~~$5.1 million to our Tres Holdings equity investment.

~~Crestwood Permian~~. Crestwood Permian is required, within 30 days following the end of each quarter to distribute 100% of its available cash (as defined in its limited liability company agreement) to its members based on their respective ownership percentages. Pursuant to Crestwood Permian's limited liability company agreement, we will receive 100% of Crestwood New Mexico's available cash (as defined in the limited liability company agreement) until the earlier of the Orla processing plant in-service date or June 30, 2018, at which time the distributions will be based on the members respective ownership percentages. Because our ownership and distribution percentages will differ during this period, equity earnings from Crestwood Permian is determined using the HLBV method. Under the HLBV method, a calculation is prepared at each balance sheet date to determine the amount that we would receive if Crestwood Permian were to liquidate all of its assets, as valued in accordance with GAAP, and distribute that cash to the members. The difference between the calculated liquidation distribution amounts at the beginning and the end of the reporting period, after adjusting for capital contributions and distributions, is our share of the earnings or losses from the equity investment for the period, which approximates how earnings are allocated under the terms of the limited liability company agreement. In January 2018, we received a cash distribution from Crestwood Permian of approximately $4.3 million.

Note 7 – Risk Management

We are exposed to certain market risks related to our ongoing business operations. These risks include exposure to changing commodity prices. We utilize derivative instruments to manage our exposure to fluctuations in commodity prices, which is discussed below. Additional information related to our derivatives is discussed in Note 2 and Note 8.8.

~~Commodity Derivative Instruments and Price Risk Management~~

Risk Management Activities

We sell NGLs (such as propane, ethane, butane and heating oil), crude oil and natural gas to ~~energy related~~energy-related businesses and may use a variety of financial and other instruments including forward contracts involving physical delivery of NGLs, ~~heating~~crude oil and ~~crude oil.~~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 ~~the~~our consolidated balance sheets, and changes in the fair value of these derivatives that impact ~~the~~our consolidated statements of operations are reflected in costs of product/services sold. ~~During~~Our commodity-based derivatives that are settled with physical commodities are reflected as an increase to product revenues, and the ~~years ended December 31, 2017, 2016~~commodity inventory that is utilized to satisfy those physical obligations is reflected as an increase to product costs in our consolidated statements of operations. Our commodity-based derivatives that are settled financially are also reflected in product costs in our consolidated statements of operations. The following table summarizes the increase (decrease) in our product revenues and ~~2015, the impact to~~product costs, net, in our consolidated statements of operations related to our commodity-based derivatives ~~reflected~~ (in ~~costs~~millions):


	Year Ended December 31,
	2022		2021		2020
Product revenues	$	548.6	$	486.7	$	214.3
Product costs, net	$	(9.4)	$	44.5	$	20.7

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Table of ~~product/services sold was a loss of $31.2 million, a loss of $7.8 million and a gain of $18.9 million, respectively.~~ Contents

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 ~~of product/services sold~~ related to these instruments.

~~Commodity Price and Credit Risk~~

Notional Amounts and Terms

The notional amounts ~~and terms~~ of our derivative financial instruments include the following:


	December 31, 2022		December 31, 2021
	Fixed Price Payor	Fixed Price Receiver	Fixed Price Payor	Fixed Price Receiver
Propane, ethane, butane, heating oil and crude oil (MMBbls)	67.2	70.2	71.6	75.8
Natural gas (Bcf)	44.2	48.4	31.9	43.4

December 31, 2017 December 31, 2016

Fixed Price
Payor

Fixed Price
Receiver

Fixed Price
Payor

Fixed Price
Receiver
Propane, crude and heating oil (MMBbls) 15.3
17.5
13.1
15.1
Natural gas (MMcf) 780
660
—
—

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 3436 months or less; however, ~~88%~~92% of the contracted volumes will be delivered or settled within 12 ~~months~~.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. ~~The aggregate fair value of all commodity derivative instruments with credit-risk-related contingent features that were in a liability position at~~ ~~December 31, 2017~~ ~~and 2016, was~~ ~~$28.9 million~~ and $13.9 million. At December 31, 2017 and 2016, we posted less than $0.1 million of collateral for our commodity derivative instruments with credit-risk-related contingent features. In addition, at December 31, 2017 and 2016, we had a New York Mercantile Exchange (NYMEX) related net derivative asset position of $27.2 million and $14.3 million, for which we posted $5.6 million and $4.2 million of cash collateral in the normal course of business. At December 31, 2017 and 2016, we also received collateral of ~~$3.7 million~~ ~~and $4.3 million in the normal course of business.~~ 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. For a summary of the fair value of our commodity derivative instruments with credit-risk-related contingent features and their associated collateral, see Note 8.

Note 8 – Fair Value Measurements

The accounting standard for fair value measurement establishes a three-tier fair value hierarchy, which prioritizes the inputs used in measuring fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurement) and the lowest priority to unobservable inputs (Level 3 measurement). The three levels of the fair value hierarchy are as follows:

•Level 1—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 ~~the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.~~ Level 1 primarily consists of financial instruments such as exchange-traded derivatives, listed equities and US government treasury securities.

•Level 2—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.

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Instruments in this category include non-exchange-traded derivatives such as over the counter (OTC) forwards, options and physical exchanges.

•Level 3—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.

~~Cash, Accounts Receivable and Accounts Payable~~

~~As of~~ ~~December 31, 2017~~ ~~and~~ ~~2016, 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 CMLP credit facility approximates the carrying amounts as of~~ ~~December 31, 2017~~ ~~and~~ ~~2016, due primarily to the variable nature of the interest rate of the instrument, which is considered a Level 2 fair value measurement.~~

~~Senior Notes~~

We estimate the fair value of our senior notes primarily based on quoted market prices for the same or similar issuances (representing a Level 2 fair value measurement). The following table reflects the carrying value (reduced for deferred financing costs associated with the respective notes) and fair value of our senior notes (~~in millions~~):

December 31, 2017 December 31, 2016
Carrying Amount
Fair
Value
Carrying Amount Fair
Value
2020 Senior Notes $ —
$ —
$ 340.6
$ 350.2
2022 Senior Notes $ —
$ —
$ 429.3
$ 447.3
2023 Senior Notes $ 692.1
$ 728.8
$ 690.6
$ 722.6
2025 Senior Notes $ 492.3
$ 517.9
$ —
$ —

Financial Assets and Liabilities

As of December 31, ~~2017~~2022 and ~~2016,~~2021, 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 ~~heating oil,~~ crude oil, NGLs and ~~NGLs.~~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, ~~2017~~2022 and ~~2016~~2021 (in millions):


	December 31, 2022
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)		Collateral/Margin Received or Paid		Fair Value
Assets
Assets from price risk management	$	62.8	$	474.3	$	—	$	537.1	$	(452.1)	$	(12.2)	$	72.8
Other investments(2)	2.6		—		—		2.6		—		—		2.6
Total assets at fair value	$	65.4	$	474.3	$	—	$	539.7	$	(452.1)	$	(12.2)	$	75.4

Liabilities
Liabilities from price risk management with credit-risk-related contingent features	$	65.7	$	420.1	$	—	$	485.8	$	(452.1)	$	(25.6)	$	8.1
Liabilities from price risk management without credit-risk-related contingent features	—		11.9		—		11.9		—		3.9		15.8
Total liabilities at fair value	$	65.7	$	432.0	$	—	$	497.7	$	(452.1)	$	(21.7)	$	23.9

114

Table of Contents


	December 31, 2017																	December 31, 2021
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting⁽¹⁾			Collateral/Margin Received or Paid			Recorded in Balance Sheet			Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting(1)		Collateral/Margin Received or Paid		Fair Value
Assets																	Assets
Assets from price risk management	$	1.1	$	102.2	$	—	$	103.3	$	(74.6	)	$	(21.5	)	$	7.2	Assets from price risk management	$	33.3	$	695.6	$	—	$	728.9	$	(607.4)	$	(79.4)	$	42.1
Suburban Propane Partners, L.P. units⁽²⁾	3.5		—		—		3.5		—			—			3.5
Other investments(2)																	Other investments(2)	2.2		—		—		2.2		—		—		2.2
Total assets at fair value	$	4.6	$	102.2	$	—	$	106.8	$	(74.6	)	$	(21.5	)	$	10.7	Total assets at fair value	$	35.5	$	695.6	$	—	$	731.1	$	(607.4)	$	(79.4)	$	44.3

Liabilities																	Liabilities
Liabilities from price risk management	$	1.4	$	118.2	$	—	$	119.6	$	(74.6	)	$	3.9		$	48.9
Liabilities from price risk management with credit-risk-related contingent features																	Liabilities from price risk management with credit-risk-related contingent features	$	26.9	$	635.1	$	—	$	662.0	$	(607.4)	$	2.8	$	57.4
Liabilities from price risk management without credit-risk-related contingent features																	Liabilities from price risk management without credit-risk-related contingent features	—		51.2		—		51.2		—		6.0		57.2
Total liabilities at fair value	$	1.4	$	118.2	$	—	$	119.6	$	(74.6	)	$	3.9		$	48.9	Total liabilities at fair value	$	26.9	$	686.3	$	—	$	713.2	$	(607.4)	$	8.8	$	114.6

	December 31, 2016
	Level 1		Level 2		Level 3		Gross Fair Value		Contract Netting⁽¹⁾			Collateral/Margin Received or Paid			Recorded in Balance Sheet
Assets
Assets from price risk management	$	0.6	$	84.4	$	—	$	85.0	$	(67.8	)	$	(10.9	)	$	6.3
Suburban Propane Partners, L.P. units⁽²⁾	4.3		—		—		4.3		—			—			4.3
Total assets at fair value	$	4.9	$	84.4	$	—	$	89.3	$	(67.8	)	$	(10.9	)	$	10.6

Liabilities
Liabilities from price risk management	$	2.7	$	90.2	$	—	$	92.9	$	(67.8	)	$	3.5		$	28.6
Total liabilities at fair value	$	2.7	$	90.2	$	—	$	92.9	$	(67.8	)	$	3.5		$	28.6



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



Crestwood Equity Partners LP						o☐
Crestwood Midstream Partners LP						o☐


Crestwood Equity Partners LP						☒
Crestwood Midstream Partners LP						☐


Crestwood Equity Partners LP						☐
Crestwood Midstream Partners LP						☐


Crestwood Equity Partners LP						☐
Crestwood Midstream Partners LP						☐



x☒		ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
	~~For the fiscal year ended December 31, 2017~~



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



Crestwood Equity Partners LP						None
Crestwood Midstream Partners LP						None



~~Crestwood Equity Partners LP~~		x
~~Crestwood Midstream Partners LP~~		x



Crestwood Equity Partners LP						$~~1.1~~1.7 billion
Crestwood Midstream Partners LP						None




Crestwood Equity Partners LP	~~$26.95 per common unit~~	~~71,231,599~~105,356,560
Crestwood Midstream Partners LP	None	~~None~~



Crestwood Equity Partners LP						~~None~~Portions of Crestwood Equity Partners LP’s Proxy Statement for the 2023 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


				Page
		PART I

Item 1.		Business		~~Page~~ 10
		~~PART I~~

Item 1.1A.		~~Business~~Risk Factors		627

~~Item 1A.~~		~~Risk Factors~~	25

Item 1B.	Unresolved Staff Comments		4549

Item 2.		Properties		4549

Item 3.		Legal Proceedings		4550

Item 4.		Mine Safety Disclosures		4550

		PART II

Item 5.		Market for the Registrant’s Common Equity, Related Unitholder Matters and Issuer Purchases of Equity Securities		4651

Item 6.		Selected Financial Data		4851

Item 7.		Management’s Discussion and Analysis of Financial Condition and Results of Operations		52

Item 7A.		Quantitative and Qualitative Disclosures about Market Risk		7667

Item 8.		Financial Statements and Supplementary Data		7769

Item 9.		Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		7769

Item 9A.		Controls and Procedures		7769

Item 9B.		Other Information		7870

		PART III

Item 10.		Directors, Executive Officers and Corporate Governance		7971

Item 11.		Executive Compensation		8471

Item 12.		Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters		9671

Item 13.		Certain Relationships and Related Transactions, and Director Independence		9871

Item 14.		Principal Accountant Fees and Services		~~100~~71

		PART IV

Item 15.		Exhibits, Financial Statement Schedules		~~101~~72



/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.
~~ASC~~
ASU		Accounting Standards ~~Codification.~~Update
~~ASU~~		~~Accounting Standards Update.~~
Barrels (Bbls)	One barrel of petroleum products equal to 42 U.S. gallons.
~~Base gas~~Bcf		A quantity of natural gas held within the confines of the natural gas storage facility and used for pressure support and to maintain a minimum facility pressure. May consist of injected base gas or native base gas. Also known as cushion gas.
~~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~~
EPA		Environmental Protection ~~Agency.~~Agency
~~FASB~~		~~Financial Accounting Standards Board.~~
FERC		Federal Energy Regulatory ~~Commission.~~Commission
~~Firm service~~U.S. GAAP		Services pursuant to which customers receive an assured or firm right to (i) in the context of storage service, store product in the storage facility or (ii) in the context of transportation service, transport product through a pipeline, over a defined period of time.
~~GAAP~~	Generally Accepted Accounting ~~Principles.~~Principles in the United States
~~Gas storage capacity~~HP		The maximum volume of natural gas that can be cost-effectively injected into a storage facility and extracted during the normal operation of the storage facility. Gas storage capacity excludes base gas.Horsepower
HPHub		~~Horsepower.~~
~~Hub~~	Geographic location of a storage facility and multiple pipeline ~~interconnections.~~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.
~~Interruptible service~~		Services pursuant to which customers receive only limited assurances regarding the availability of (i) with respect to storage services, capacity and deliverability in storage facilities or (ii) with respect to transportation services, capacity and deliverability from receipt points to delivery points. Customers pay fees for interruptible services based on their actual utilization of the storage or transportation assets.
~~MMBbls~~

MBbls		One thousand barrels
MMBbls		One million ~~barrels.~~barrels
MMcf		One million cubic feet of natural ~~gas.~~gas
Mscf		One thousand standard cubic feet
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).
~~NYPSC~~NYSE		~~New York State Public Service Commission.~~
~~NYSE~~	New York Stock ~~Exchange.~~Exchange
~~Salt cavern~~		~~A man-made cavern developed in a salt dome or salt beds by leaching or mining of the salt.~~
SEC		Securities and Exchange ~~Commission.~~Commission
Withdrawal rate		The rate at which a customer is permitted to withdraw gas from a natural gas storage facility.
~~Working gas~~		~~Natural gas in a storage facility in excess of base gas. Working gas may or may not be completely withdrawn during any particular withdrawal season.~~
~~Working gas storage capacity~~	~~See gas storage capacity (above).~~



Shale Play (State)	Counties / Parishes	Pipeline (Miles)	Gathering Capacity	2017 Average Gathering Volumes	Compression (HP)	Number of In-Service Processing Plants	Processing Capacity (MMcf/d)	Gross Acreage Dedication
Bakken North Dakota	McKenzie and Dunn	640 ⁽¹⁾	100 MMcf/d - natural gas gathering 125 MBbls/d - crude oil gathering 40 MBbls/d - water gathering	48 MMcf/d - natural gas gathering 80 MBbls/d - crude oil gathering 35 MBbls/d - water gathering	18,000	1	30	150,000
Marcellus West Virginia	Harrison, Barbour and Doddridge	80	875 MMcf/d	423 MMcf/d	131,380	—	—	140,000
Barnett Texas	Hood, Somervell, Tarrant, Johnson and Denton	507	925 MMcf/d	319 MMcf/d	153,465	1	425	140,000
Fayetteville Arkansas	Conway, Faulkner, Van Buren, and White	173	510 MMcf/d	46 MMcf/d	18,670	—	—	143,000
Granite Wash Texas	Roberts	36	36 MMcf/d	10 MMcf/d	10,400	1	36	22,000
Delaware Permian⁽²⁾ New Mexico/Texas	Eddy (New Mexico) Loving, Reeves, Ward, Culberson (Texas)	189	165 MMcf/d	74 MMcf/d	33,310 ⁽³⁾	2	75	214,000
Powder River Basin ⁽³⁾ Wyoming	Converse	211	140 MMcf/d	60 MMcf/d	50,895	1	120	358,000


Basin	Type of Contracts	Weighted Average Remaining Contract Terms (in years)	Major Customers
Williston Basin	Fixed-fee, percentage-of-proceeds	9	Chord Energy Corporation, Devon Energy Corporation, Enerplus Resources (USA) Corporation
Powder River Basin	Fixed-fee	13	Continental Resources, Inc., Occidental Petroleum Corporation (Oxy)


~~(1)~~ Delaware Basin (System)	Type of Contracts	Weighted Average Remaining Contract Terms (in years)	Major Customers
Willow Lake/Orla	Fixed-fee, ~~contracts represent contracts in which our customers agree to pay a flat rate based on the amount of gas delivered. Mixed contracts include percent-of-proceeds and fixed-fee arrangements.~~percentage-of-proceeds	9	Novo Oil & Gas Northern Delaware LLC, Mewbourne Oil Company (Mewbourne), ConocoPhillips
Carlsbad	Fixed-fee, percentage-of-proceeds	4	Mewbourne, Marathon Oil Permian LLC, BTA Oil Producers LLC, Kaiser Francis Oil Company
Desert Hills	Fixed-fee	7	ConocoPhillips
Panther	Fixed-fee	12	Percussion Petroleum, LLC
Nautilus	Fixed-fee	14	ConocoPhillips, Battalion Oil Corporation



Storage Facility / Location	Certificated Working Gas Storage Capacity (Bcf)		Certificated Maximum Injection Rate (MMcf/d)	Certificated Maximum Withdrawal Rate (MMcf/d)	Pipeline Connections
Stagecoach Tioga County, NY; Bradford County, PA	26.2		250	500	TGP’s 300 Line; Millennium; UGI’s Sunbury Pipeline,⁽¹⁾ Transco’s Leidy Line⁽¹⁾
Thomas Corners Steuben County, NY	7.0		70	140	TGP’s 200 Line; Millennium; Dominion
Seneca Lake Schuyler County, NY	1.5	⁽²⁾	73	145	Dominion; Millennium
Steuben Steuben County, NY	6.2		30	60	TGP’s 200 Line; Millennium; Dominion
Northeast Storage Total	40.9		423	845
Tres Palacios	34.9		1,000	2,500	Multiple⁽³⁾
Total	75.8		1,423	3,345


~~(1)~~	~~Stagecoach is connected to UGI Energy Services, LLC’s (UGI) Sunbury Pipeline and Transcontinental Gas Pipe Line Corporation’s (Transco) Leidy Line through the MARC I Pipeline.~~


~~(1)~~	~~Consists of 262 miles of natural gas gathering pipeline, 183 miles of crude oil gathering pipeline, and 195 miles of produced water gathering pipeline.~~


~~(2)~~	~~Our Delaware Permian assets in New Mexico and Texas are owned by Crestwood Permian Basin Holdings LLC (Crestwood Permian)~~Wild Basin), ~~our 50% equity method investment.~~


~~(3)~~	~~Includes 16,800 HP that is owned and operated by a third party under a compression services agreement.~~


~~(4)~~	~~Our Powder River Basin assets are owned by Jackalope Gas Gathering Services, L.L.C. (Jackalope), our 50% equity method investment.~~


Delaware Basin (System)	Gathering Capacity	2022 Average Gathering Volumes	Number of In-Service Processing Plants	Processing Capacity(1) (MMcf/d)	Gross Acreage Dedication
Willow Lake/Orla	596 MMcf/d - natural gas	164 MMcf/d - natural gas	1	263	19,000
Carlsbad	326 MMcf/d - natural gas	186 MMcf/d - natural gas	2	350	80,000
Desert Hills	125 MBbls/d - produced water	68 MBbls/d - produced water	—	—	30,000
Panther	90 MBbls/d - crude oil 229 MBbls/d - produced water	21 MBbls/d - crude oil 63 MBbls/d - produced water	—	—	96,000
Nautilus	217 MMcf/d - natural gas	122 MMcf/d - natural gas	—	—	94,000



Shale Play	Type of Services	Type of Contracts⁽¹⁾	Gross Acreage Dedication	Major Customers	Weighted Average Remaining Contract Terms (in years)
Bakken	Gathering - crude oil, natural gas and water	Mixed	150,000	WPX, Bruin E&P Partners, LLC, Rimrock Energy Partners, LLC, XTO Energy, QEP Resources, Inc., Enerplus	8
Marcellus	Gathering	Fixed-fee	140,000	Antero	14
	Compression	Fixed-fee	—	Antero	2
Barnett	Gathering	Mixed	140,000	BlueStone, Devon Energy, Tokyo Gas America Ltd. (Tokyo Gas)	7
	Processing	Mixed	—	BlueStone, Devon Energy, Tokyo Gas	9
	Compression	Mixed	—	BlueStone, Devon Energy, Tokyo Gas	7
Fayetteville	Gathering	Fixed-fee	143,000	BHP Billiton Petroleum (BHP)	7
	Treating	Fixed-fee	—	BHP	7
Granite Wash	Gathering	Fixed-fee	22,000	Sabine Oil and Gas	7
	Processing	Mixed	—	Sabine Oil and Gas	7
Permian	Gathering	Fixed-fee	214,000	Mewbourne, Concho, Marathon Oil Corp, SWEPI	7
	Processing	Mixed	—	Mewbourne, Matador	4
Powder River Basin	Gathering	Fixed-fee	358,000	Chesapeake	10
	Processing	Fixed-fee	—	Chesapeake	10


~~(2)~~	~~Stagecoach Gas has been authorized by the FERC to expand the facility’s working gas storage capacity to 2 Bcf.~~


~~(3)~~	Tres Palacios is interconnected to Florida Gas Transmission Company, LLC, Kinder Morgan Tejas Pipeline, L.P., Houston Pipe Line Company LP, Central Texas Gathering System, Natural Gas Pipeline Company of America, Transco, TGP, Gulf South Pipeline, Valero Natural Gas Pipeline Company, Channel Pipeline Company, and Texas Eastern Transmission, L.P.


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


~~(2)~~	~~Mixed contracts include both firm and fixed-fee arrangements.~~



Quarters Ended:	Low		High		Cash Distribution Per Unit
2017
December 31, 2017	$	22.15	$	26.10	$	0.600
September 30, 2017	22.30		26.65		0.600
June 30, 2017	20.00		27.35		0.600
March 31, 2017	24.35		28.30		0.600
2016
December 31, 2016	$	18.51	$	25.70	$	0.600
September 30, 2016	18.67		22.22		0.600
June 30, 2016	10.40		23.59		0.600
March 31, 2016	7.90		21.56		0.600



Crestwood Equity	Gathering and Processing			Storage and Transportation			Marketing, Supply and Logistics
Revenues	$	1,688.2		$	37.2		$	2,155.5
Intersegment revenues	134.5			6.7			(141.2		)
Costs of product/services sold	1,480.8			0.3			1,893.6
Operations and maintenance expenses	68.4			4.2			63.4
Loss on long-lived assets, net	(14.4		)	—			(48.2		)
Goodwill impairments	—			—			(38.8		)
Loss on contingent consideration	—			(57.0		)	—
Earnings from unconsolidated affiliates, net	18.9			28.9			—
Other income, net	0.8			—			—
EBITDA for the year ended December 31, 2017	$	278.8		$	11.3		$	(29.7	)

Revenues	$	1,118.8		$	165.3		$	1,236.4
Intersegment revenues	108.6			4.2			(112.8		)
Costs of product/services sold	917.0			5.1			1,003.0
Operations and maintenance expenses	77.0			21.4			59.7
Loss on long-lived assets, net	(2.0		)	(32.2		)	(31.4		)
Goodwill impairments	(8.6		)	(44.9		)	(109.1		)
Earnings from unconsolidated affiliates, net	20.3			11.2			—
EBITDA for the year ended December 31, 2016	$	243.1		$	77.1		$	(79.6	)

Revenues	$	1,381.0		$	266.3		$	985.5
Intersegment revenues	66.7			—			(66.7		)
Costs of product/services sold	1,103.9			20.1			759.5
Operations and maintenance expenses	89.0			31.7			69.5
Loss on long-lived assets, net	(787.3		)	(1.6		)	(32.3		)
Goodwill impairments	(329.7		)	(623.4		)	(453.2		)
Loss from unconsolidated affiliates, net	(43.4		)	(17.4		)	—
EBITDA for the year ended December 31, 2015	$	(905.6	)	$	(427.9	)	$	(395.7	)



Growth capital	$	141.4
Maintenance capital	22.0
Other⁽¹⁾	25.0
Purchases of property, plant and equipment	188.4
Reimbursements of property, plant and equipment	(19.6		)
Net	$	168.8


Growth capital(1)	~~Represents gross purchases~~$	191.6
Maintenance capital	28.7
Other(2)	9.0
Purchases of property, plant and equipment ~~that are reimbursable by third parties.~~	$	229.3



	Less than 1 Year		1-3 Years		3-5 Years		Thereafter		Total
Long-term debt:
Principal	$	0.9	$	319.3	$	0.4	$	1,200.0	$	1,520.6
Interest⁽¹⁾	85.9		162.9		145.0		75.6		469.4
Future minimum payments under operating leases⁽²⁾	35.2		53.3		19.2		18.8		126.5
Asset retirement obligations	—		—		—		27.5		27.5
Fixed price commodity purchase commitments⁽³⁾	447.3		32.0		—		—		479.3
Standby letters of credit	52.2		—		—		—		52.2
Purchase commitments and other contractual obligations⁽⁴⁾	65.8		—		—		—		65.8
Total contractual obligations	$	687.3	$	567.5	$	164.6	$	1,321.9	$	2,741.3


~~(1)~~	$318.2 million of our long-term debt is variable interest rate debt at Alternate Base rate or Eurodollar rate plus an applicable spread. These rates plus their applicable spreads were between 3.94% and 6.00% at December 31, 2017. These rates have been applied for each period presented in the table.


~~(2)~~	~~See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 15 for a further discussion of these obligations.~~


~~(3)~~	~~Fixed price purchase commitments are volumetrically offset by third party fixed price sale contracts.~~


	December 31, 2022
Current assets	$	588.4
Current assets - affiliates	$	1.3
Property, plant and equipment, net	$	3,295.8
Non-current assets	$	1,012.9
Current liabilities	$	466.1
Current liabilities - affiliates	$	41.5
Long-term debt, less current portion	$	3,171.5
Non-current liabilities	$	147.6


	Year Ended December 31, 2022
Revenues	$	5,410.1
Revenues - affiliates	$	384.4
Cost of products/services sold	$	4,288.8
Cost of products/services sold - affiliates	$	431.2
Operations and maintenance expenses(1)	$	161.7
General and administrative expenses(2)	$	124.4
Operating income	$	213.7
Net income	$	39.0