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YoY shift: Neutral
Year-over-year tone shift - average net-tone change across Risk Factors and MD&A vs the prior 10-K. This filing is -0.11pp more bearish than last year's.
Why YoY instead of absolute: the LM lexicon has ~6.6× more negative words than positive (legal/risk-disclosure language is heavy on hedging), so every 10-K reads bearish on raw tone. Year-over-year change strips that bias and surfaces the actual shift in management's framing.
Tone shift by section
The two components the gauge averages: how Risk Factors and MD&A each shifted in net tone versus last year's 10-K. The headline above is their average, so a green needle over a soft section just means the other section carried it.
Risk Factors
-0.10pp
Flat
Net-tone change vs last year's 10-K.
MD&A
-0.12pp
Flat
Net-tone change vs last year's 10-K.
Per-snippet highlights
Sentence-level sentiment highlighting with category and subcategory filters is coming once the snippet-scoring pipeline lands. For now, dig into the actual section text on the Sections tab.
Language change vs prior 10-K
Risk Factors (Item 1A) - words with the biggest YoY frequency increase
Negative rising
negatively+5
unable+4
disruptions+4
litigation+4
force+4
Positive rising
able+5
attractive+3
successfully+2
effective+2
achieved+2
Risk Factors (Item 1A)
19,213 words
Item 1A. Risk Factors
Risks Inherent in Our Business
Our business depends on hydrocarbon supply and demand fundamentals, which can be adversely affected by numerous factors outside of our control.
Our success depends on the supply and demand for natural gas, NGLs and crude oil, which has historically generated the need for new or expanded midstream infrastructure. The degree to which our business is impacted by changes in supply or demand varies. Our business can be negatively impacted by sustained downturns in supply and demand for one or more commodities, including reductions in our ability to renew contracts on favorable terms and to construct new infrastructure. For example, significantly lower commodity prices during the past few years have resulted in an industry-wide reduction in capital expenditures by producers and a slowdown in drilling, completion and supply development efforts. Notwithstanding this market downturn, production volumes of crude oil, natural gas and NGLs have continued to grow (or decline at a rate than expected). Similarly, major factors that impact natural gas demand domestically include the effects of the COVID-19 pandemic, the realization of potential liquefied natural gas exports and demand growth within the power generation market. Factors that impact crude oil demand include production cuts and freezes implemented by OPEC members and other large oil producers such as Russia. For example, during the first half of 2020, the combined effect of OPEC and Russia’s to agree on a plan to production of oil and related commodities, the outbreak of the COVID-19 pandemic and the in available storage for hydrocarbons in the United States contributed to a sharp drop in prices for crude oil. Subsequently, in 2022, Russia launched a military action Ukraine. The has caused, and could intensify, in the prices of natural gas, oil and NGLs, and the extent and duration of the military action, sanctions and resulting market have been significant and could continue to have a substantial impact on the global economy and our business for an unknown period of time. There is evidence that the increase in crude oil prices during 2022 was partially due to the impact of the between Russia and Ukraine on the global commodity and financial markets, and in response to economic and trade sanctions that certain countries have imposed on Russia. Alternatively, a cessation of the hostilities between Russia and Ukraine as a result of a negotiated withdrawal or otherwise could cause commodity prices to . Further, in 2022, OPEC+ announced a 2 million barrel per day reduction in production quotas. This action was taken largely in response to the U.S. decision to continue releasing crude from its Strategic Petroleum Reserve. While actual OPEC+ production capabilities are to discern, any return to previous targeted production levels could cause commodity prices to .
Language change vs prior 10-K
MD&A (Item 7) - words with the biggest YoY frequency increase
Negative rising
divestitures+10
loss+8
impairments+1
divestiture+1
unfavorably+1
Positive rising
gain+5
better+1
successfully+1
best+1
accomplish+1
MD&A (Item 7)
9,826 words
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Our Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our consolidated financial statements and the accompanying footnotes, and Part I, Item 1. Business.
A comparative discussion of our 2021 operating results to our 2020 operating results can be found in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations included in our Annual Report on Form 10-K for the year ended December 31, 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 sectors of the energy value chain. Our midstream infrastructure is geographically located in or near significant supply basins, especially developed and emerging liquids-rich and crude oil shale plays, across the United States. We believe that our strategy of focusing on prolific, low-cost shale plays positions us well to generate greater returns in varying commodity price environments and capture upside economics when development activity occurs.
We cannot predict what actions OPEC and other oil-producing countries will take in the future or other geopolitical and domestic activities that may significantly influence commodity prices. In addition, the supply and demand for natural gas, NGLs and crude oil for our business will depend on many other factors outside of our control, some of which include:
• changes in general domestic and global economic and political conditions, including economic downturns or recessionary environments;
• disruptions of financial and credit markets, including inflation, which affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements;
• changes in domestic regulations that could impact the supply or demand for oil and gas;
• technological advancements that may drive further increases in production and reduction in costs of developing shale plays;
• competition from imported supplies and alternate fuels;
• commodity price changes that could negatively impact the supply of, or the demand for these products;
• outbreak of illness, pandemic or any other public health crisis, including the COVID-19 pandemic;
• the availability of hydrocarbon storage and transportation infrastructure;
• increased costs to explore for, develop, produce, gather, process or transport commodities;
• impact of interest rates on economic activity;
• shareholder activism and activities by non-governmental organizations to limit sources of funding for the energy sector or restrict the exploration, development and production of oil and gas;
• operational hazards, including terrorism, cyber-attacks or domestic vandalism;
• geopolitical events, such as the ongoing military conflict involving Russia and Ukraine;
• adoption of various energy efficiency and conservation measures; and
• perceptions of customers on the availability and price volatility of our services, particularly customers’ perceptions on the volatility of commodity prices over the longer-term.
If volatility and seasonality in the oil and gas industry increase, because of increased production capacity, reduced demand for energy, or otherwise, the demand for our services and the fees that we will be able to charge for those services may decline. In
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addition to volatility and seasonality, an extended period of low commodity prices could adversely impact storage and transportation values for some period of time until market conditions adjust. For example, in response to low commodity prices experienced during early 2020, some of our customers reduced capital expenditures and curtailed production, which adversely affected our gathering and processing north and south segments’ results. With West Texas Intermediate crude oil prices ranging from $71.05 to $123.64 per barrel in 2022, the sustainability of recent prices improvements and longer-term oil prices cannot be predicted. These commodity price impacts could have a negative impact on our business, financial condition and results of operations.
The widespread outbreak of an illness, pandemic (like COVID-19) or any other public health crisis may have material adverse effects on our business, financial position, results of operations and/or cash flows.
During the past few years, the global and U.S. economy was negatively impacted by the COVID-19 pandemic, which disrupted global supply chains, reduced consumer activity, disrupted travel and created significant volatility and disruption of financial and commodity markets. The effects of the COVID-19 pandemic resulted in a significant reduction in global demand for natural gas, NGLs and crude oil and a significant and persistent reduction in the market price of crude oil during 2020. As a result, many producers, including some of our customers, curtailed some of their short-term drilling and production activity and reduced or slowed down their plans for future drilling and production activity. This decrease in activity decreased the demand that certain of these customers had for our services in 2020, and may continue to impact demand for our services in the future if our customers continue to or further curtail drilling and production activity in the future. As COVID-19 vaccines have become more readily available and social distancing guidelines, travel restrictions and stay-at-home orders have eased, the pandemic’s impact on the global economy and demand for natural gas, NGLs, and crude oil, and related commodity prices, has changed over time.
The extent of the impact of the COVID-19 pandemic or any other future public health crisis on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas (including its impact on travel, manufacturing and consumer product demand have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations. There is uncertainty around the extent and duration of the disruption. The degree to which the COVID-19 pandemic or any other public health crisisadversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Additionally, the actions taken to contain the COVID-19 pandemic include actions implemented by governmental authorities, such as large-scale travel bans and restrictions, border closures, quarantines, shelter-in-place orders and business and government shutdowns, all of which affect the demand for crude oil, natural gas and NGLs. Due to these factors, we expect to see continued volatility in commodity prices for the foreseeable future. These potential impacts, while uncertain, could adversely affect our operating results.
Our future growth may be limited if we are unable to complete successful, accretive growth projects.
Our business strategy depends on our ability to provide increased services to our customers and develop growth projects that can be financed appropriately. We may be unable to complete successful, accretive growth projects for any of the following reasons, among others:
• we fail to identify (or we are outbid for) attractive expansion or development projects or acquisition candidates that satisfy our economic and other criteria;
• we fail to secure adequate customer commitments to use the facilities to be developed, expanded or acquired; or
• we cannot obtain governmental approvals or other rights, licenses or consents needed to complete such projects or acquisitions on time or on budget, if at all.
The development and construction of gathering, processing, storage and transportation facilities involves numerous regulatory, environmental, safety, political and legal uncertainties beyond our control and may require the expenditure of significant amounts of capital. When we undertake these projects, they may not be completed on schedule, at the budgeted cost or at all. Moreover, our revenues may not increase immediately upon the expenditure of funds on a particular growth project. For instance, if we build a new gathering system, processing plant or transmission pipeline, the construction may occur over an extended period of time and we will not receive material increases in revenues until the project is placed in service. Accordingly, if we do pursue growth projects, we can provide no assurances that our efforts will provide a platform for additional growth for our company.
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Our ability to finance new growth projects and make capital expenditures may be limited by our access to the capital markets or ability to raise investment capital at a cost of capital that allows for accretive midstream investments.
There has been significant volatility in energy commodity prices in recent years and such volatility may increase the concerns of energy investors regarding the future outlook for the industry. This has resulted in historic increased trading volatility in the equity and debt securities of energy companies, as well as a negative impact on the ability of companies in the oil and gas industry to seek financing and access the capital markets on favorable terms or at all during such times of volatility. Our growth strategy depends on our ability to identify, develop and contract for new growth projects and raise the investment capital, at a reasonable cost of capital, required to generate accretive returns from the growth project. This trend may continue and could negatively impact our ability to grow for any of the following reasons:
• access to the public equity and debt markets for partnerships of similar size to us may limit our ability to raise new equity and debt capital to finance new growth projects;
• if market conditions deteriorate below current levels, it is unlikely that we could issue equity at costs of capital that would enable us to invest in new growth projects on an accretive basis; or
• we cannot raise financing for such projects or acquisitions on economically acceptable terms.
The growth projects we complete may not perform as anticipated.
Even if we complete growth projects that we believe will be strategic and accretive, such projects may nevertheless reduce our cash available for distribution due to the following factors, among others:
• mistaken assumptions about capacity, revenues, synergies, costs (including operating and administrative, capital, debt and equity costs), inflation, customer demand, growth potential, assumed liabilities and other factors;
• the failure to receive cash flows from a growth project or newly acquired asset due to delays in the commencement of operations for any reason;
• unforeseen operational issues or the realization of liabilities that were not known to us at the time the acquisition or growth project was completed;
• the inability to attract new customers or retain acquired customers to the extent assumed in connection with an acquisition or growth project;
• the failure to successfully integrate growth projects or acquired assets or businesses into our operations and/or the loss of key employees; or
• the impact of regulatory, environmental, political and legal uncertainties, or force majeure events, that are beyond our control.
In particular, we may construct facilities to capture anticipated future growth in production and/or demand in a region in which such growth does not materialize. As a result, new facilities may not be able to attract enough throughput to achieve our expected investment return, which could adversely affect our business, financial condition, results of operations and ability to make distributions.
If we complete future growth projects, our capitalization and results of operations may change significantly, and our investors may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in determining the application of these funds and other resources. If any growth projects we ultimately complete are not accretive to our cash available for distribution, our ability to make distributions may be reduced.
We may rely upon third-party assets to operate our facilities, and we could be negatively impacted by circumstances beyond our control that temporarily or permanently interrupt the operation of such third-party assets.
Certain of our operations and investments depend on assets owned and controlled by third parties to operate effectively. For example, (i) certain of our rich gas gathering systems depend on interconnections, compression facilities and processing plants owned by third parties for us to move gas off our systems; (ii) our crude oil gathering systems depend on third-party pipelines to move crude to demand markets or rail terminals and our crude oil rail terminals depend on railroad companies to move our customers’ crude oil to market; and (iii) our natural gas storage facility relies on third-party interconnections and pipelines to receive and deliver natural gas. In addition, certain of our customers’ operations rely on assets owned and controlled by them or other third parties to operate efficiently in order to deliver their commodities to us. Since we do not own or operate these third-party facilities, their continuing operation is outside of our control. If third-party facilities become unavailable or constrained, including due to force majeure events, or other downstream facilities utilized to move our customers’ product to their end destination become unavailable, it could have a material adverse effect on our business, financial condition, results of
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operations and ability to make distributions. For example, in the fourth quarter of 2022, extreme winter weather events impacted our properties in the Williston Basin, Powder River Basin and Delaware Basin. The severity and duration of these weather events forced our customers to contend with surface equipment freezing, widespread power outages and limited road accessibility, which resulted in well shut-ins, facility downtime and delays in drilling and completion activity during the fourth quarter. These factors impacted gathering volumes for our properties in the affected areas during the fourth quarter of 2022, which impacted our results of operations during 2022.
In addition, the rates charged by processing plants, pipelines and other facilities interconnected to our assets affect the utilization and value of our services. Significant changes in the rates charged by these third parties, or the rates charged by the third parties that own downstream assets required to move commodities to their final destinations, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
A substantial portion of our revenue is derived from our operations in the Williston Basin, and due to such geographic concentration, adverse developments in the Williston Basin could impact our financial condition and results of operations.
A significant portion of our revenue is derived from our operations in the Williston Basin, which increased in concentration as a result of the acquisitions and divestitures that we completed during 2022. These operations accounted for approximately 61% of our total revenues, less of costs of product/services sold, during the year ended December 31, 2022. Due to this geographic concentration of our operations, adverse developments that affect customers, suppliers or operations in the Williston Basin, such as catastrophic events or weather, health pandemics, regional labor shortages, and changes in supply or demand of crude oil, natural gas and related commodities that impact regional commodity prices and availability of infrastructure, could have a significantly greater impact on our financial condition and results of operations than if we maintained operations in more diverse locations. For example, in the fourth quarter of 2022, extreme winter weather events impacted a number of our properties, including those in the Williston Basin, resulting in well shut-ins, facility downtime and delays in drilling and completion activity by our customers, which impacted gathering volumes for our properties in the Williston Basin and impacted our results of operations during the fourth quarter of 2022.
Our gathering and processing operations depend, in part, on drilling and production decisions of others.
Our gathering and processing operations are dependent on the continued availability of natural gas and crude oil production. We have no control over the level of drilling activity in our areas of operation, the amount of reserves associated with wells connected to our systems, or the rate at which production from a well declines. Our gathering systems are connected to wells whose production will naturally decline over time, which means that our cash flows associated with these wells will decline over time. To maintain or increase throughput levels on our gathering systems and utilization rates at our natural gas processing plants, we must continually obtain new natural gas and crude oil supplies. Our ability to obtain additional sources of natural gas and crude oil primarily depends on the level of successful drilling activity near our systems, our ability to compete for volumes from successful new wells and our ability to expand our system capacity as needed. If we are not able to obtain new supplies of natural gas and crude oil to replace the natural decline in volumes from existing wells, throughput on our gathering and processing facilities would decline, which could have a material adverse effect on our results of operations and distributable cash flow.
Although we have acreage dedications from customers that include certain producing and non-producing oil and gas properties, our customers are not contractually required to develop the reserves or properties they have dedicated to us. We have no control over producers or their drilling and production decisions in our areas of operations, which are affected by, among other things, (i) the availability and cost of capital; (ii) prevailing and projected commodity prices and fluctuations thereof; (iii) demand for natural gas, NGLs and crude oil; (iv) levels of reserves and geological considerations; (v) governmental regulations, including the availability of drilling permits and the regulation of hydraulic fracturing; (vi) the availability and cost of drilling rigs and other development services; (vii) the availability of storage of crude oil and other commodities; and (viii) the impact of illness, pandemics or any other public health crisis, including the COVID-19 pandemic and of force majeure events. As it relates to certain drilling methods, including hydraulic fracturing, the EPA has completed a study of potential adverse impacts that those drilling methods and fracturing activities may have on water quality and public health, concluding that water cycle activities associated with hydraulic fracturing may impact drinking water resources under certain circumstances. Moreover, the Biden Administration may seek to pursue legislation, executive actions or regulatory initiatives that restrict hydraulic fracturing activities on federal lands. Drilling and production activity generally decreases as commodity prices decrease (such as what was experienced with the decline in commodity prices during 2020, as further described in “ Our business depends on hydrocarbon supply and demand fundamentals, which can be adversely affected by numerous factors outside of our control” ) and sustained declines in commodity prices could lead to a material decrease in such activity. Because of these factors, even if oil and gas reserves are known to exist in areas served by our assets, producers may choose not to develop those reserves. For example, due
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to the sharp decreases in commodity prices experienced in 2020, many of our customers announced reductions in their estimated capital expenditures. Reductions in exploration or production activity in our areas of operations could lead to reduced utilization of our systems.
Estimates of oil and gas reserves depend on many assumptions that may turn out to be inaccurate, and future volumes on our gathering systems may be less than anticipated.
We normally do not obtain independent evaluations of natural gas or crude oil reserves connected to our gathering systems. We therefore do not have independent estimates of total reserves dedicated to our systems or the anticipated life of such reserves. It often takes producers longer periods of time to determine how to efficiently develop and produce hydrocarbons from unconventional shale plays than conventional basins, which can result in lower volumes becoming available as soon as expected in the shale plays in which we operate. If the total reserves or estimated life of the reserves connected to our gathering systems is less than anticipated and we are unable to secure additional sources of natural gas or crude oil, it could have a material adverse effect on our business, results of operations and financial condition.
We are exposed to credit risks of our customers, and any material nonpayment or nonperformance by our key customers could adversely affect our cash flows and results of operations.
Many of our customers may experience financial problems that could have a significant effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce performance of obligations under contractual arrangements. In addition, many of our customers finance their activities through cash flows from operations, the incurrence of debt or the issuance of equity. The combination of the reduction of cash flows resulting from declines in commodity prices (such as experienced during 2020), inflation, a reduction in borrowing bases under a reserve-based credit facility, the lack of availability of debt or equity financing and declining economic conditions may result in a significant reduction of customers’ liquidity and limit their ability to make payments or perform on their obligations to us. Furthermore, some of our customers may be highly leveraged and subject to their own operating and regulatory risks, which increases the risk that they may default on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, reduction of our operating cash flows and may also reduce or curtail their future use of our products and services, which could reduce our revenues.
Our storage and logistics operations are seasonal and generally have lower cash flows in certain periods during the year, which may require us to borrow money to fund our working capital needs of these businesses.
The natural gas liquids inventory we pre-sell to our customers is higher during the second and third quarters of a given year, and our cash receipts during that period are lower. As a result, we may have to borrow money to fund the working capital needs of our storage and logistics operations during those periods. Any restrictions on our ability to borrow money could impact our ability to pay quarterly distributions to our unitholders.
Counterparties to our commodity derivative and physical purchase and sale contracts in our storage and logistics operations may not be able to perform their obligations to us, which could materially affect our cash flows and results of operations.
We encounter risk of counterparty non-performance in our storage and logistics operations. Disruptions in the price or supply of NGLs, natural gas or crude oil for an extended or near term period of time could result in counterparty defaults on our derivative and physical purchase and sale contracts. This could impair our expected earnings from the derivative or physical sales contracts, our ability to obtain supply to fulfill our sales delivery commitments or our ability to obtain supply at reasonable prices, which could adversely affect our financial condition and results of operations.
Our storage and logistics operations and certain of our gathering and processing operations are subject to commodity risk, basis risk or risk of adverse market conditions, which can adversely affect our financial condition and results of operations.
We attempt to lock in a margin for a portion of the commodities we purchase by selling such commodities for physical delivery to our customers or by entering into future delivery obligations under contracts for forward sale. Through these transactions, we seek to maintain a position that is substantially balanced between purchases, and sales or future delivery obligations. Any event that disrupts our anticipated physical supply of commodities could expose us to risk of loss resulting from the need to fulfill our obligations required under contracts for forward sale. Basis risk describes the inherent market price risk created when a commodity of certain grade or location is purchased, sold or exchanged as compared to a purchase, sale or exchange of a like commodity at a different time or place. Transportation costs and timing differentials are components of basis risk. In a backwardated market (when prices for future deliveries are lower than current prices), basis risk is created with respect to
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timing. In these instances, physical inventory generally loses value as the price of such physical inventory declines over time. Basis risk cannot be entirely eliminated, and basis exposure, particularly in backwardated or other adverse market conditions, can adversely affect our financial condition and results of operations.
Changes in future business conditions could cause our long-lived assets and goodwill to become impaired, and our financial condition and results of operations could suffer if we record future impairments of long-lived assets and goodwill.
We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value of our assets based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. This differs from our evaluation of goodwill, which is evaluated for impairment annually on December 31, and whenever events indicate that it is more likely than not that the fair value of a reporting unit could be less than the carrying amount. This evaluation requires us to compare the fair value of each of our reporting units primarily utilizing discounted cash flows, to its carrying value (including goodwill). If the fair value exceeds the carrying value amount, goodwill of the reporting unit is not considered impaired.
Our long-lived assets and goodwill impairment analyses are sensitive to changes in key assumptions used in our analysis, such as expected future cash flows, the degree of volatility in equity and debt markets and our unit price. If the assumptions used in our analysis are not realized, it is possible a material impairment charge may need to be recorded in the future. We cannot accurately predict the amount and timing of any impairment of long-lived assets or goodwill. Any additional impairment charges that we may take in the future could be material to our results of operations and financial condition. For a further discussion of our long-lived assets and goodwill impairments, see Critical Accounting Policies and Estimates discussed in Part II, Item 7. Management’s Discussion and Analysis of Financial Conditions and Results of Operations and Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 2.
Our industry is highly competitive, and increased competitive pressure could adversely affect our ability to execute our growth strategy.
We compete with other energy midstream enterprises, some of which are much larger and have significantly greater financial resources or operating experience, in our areas of operation. Furthermore, depressed commodity price environments may cause further consolidation within the energy industry, leading to combined companies with greater resources and better economies of scale. Our competitors may expand or construct infrastructure that creates additional competition for the services we provide to customers. Our ability to renew or replace existing contracts with our customers at rates sufficient to maintain current revenues and cash flow could be adversely affected by the activities of our competitors and our customers. All of these competitive pressures could have a material adverse effect on our business, results of operations, financial condition and ability to make distributions.
Our level of indebtedness could adversely affect our ability to raise additional capital to fund operations, limit our ability to react to changes in our business or industry, and place us at a competitive disadvantage.
We had approximately $3.4 billion of long-term debt outstanding as of December 31, 2022. If we are unable to generate sufficient cash flow to satisfy debt obligations or to obtain alternative financing, our business, results of operations, financial condition and business prospects could be materially and adversely affected.
Our substantial debt could have adverse consequences to our unitholders. For example, it could:
• increase our vulnerability to general adverse economic and industry conditions;
• limit our ability to fund future capital expenditures and working capital, to engage in development activities or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive covenants or terms of our debt;
• result in an event of default if we fail to satisfy debt obligations or fail to comply with the financial and other restrictive covenants contained in the agreements governing our indebtedness, which event of default could result in all of our debt becoming immediately due and payable and could permit our lenders to foreclose on any of the collateral securing such debt;
• increase our cost of borrowing;
• restrict us from making strategic acquisitions or investments, or cause us to make non-strategic divestitures;
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• limit our flexibility in planning for, or reacting to, changes in our business or industry in which we operate, placing us at a competitive disadvantage compared to our peers who are less highly leveraged and who therefore may be able to take advantage of opportunities that our leverage prevents us from exploring; and
• impair our ability to obtain additional financing in the future.
Realization of any of these factors could adversely affect our financial condition, results of operations and cash flows.
Restrictions in our revolving credit facility and indentures governing our senior notes could adversely affect our business, financial condition, results of operations and ability to make distributions.
Our revolving credit facility and indentures governing our senior notes contain various covenants and restrictive provisions that will limit our ability to, among other things:
• incur additional debt;
• make distributions on or redeem or repurchase units;
• make investments and acquisitions;
• incur or permit certain liens to exist;
• enter into certain types of transactions with affiliates;
• merge, consolidate or amalgamate with another company; and
• transfer or otherwise dispose of assets.
Furthermore, our Crestwood Midstream revolving credit facility contains covenants which requires us to maintain certain financial ratios such as (i) a net debt to consolidated EBITDA ratio (as defined in our credit agreement) of not more than 5.50 to 1.0; (ii) a consolidated EBITDA to consolidated interest expense ratio (as defined in our credit agreement) of not less than 2.50 to 1.0; and (iii) a senior secured leverage ratio (as defined in our credit agreement) of not more than 3.50 to 1.0.
Borrowings under our Crestwood Midstream revolving credit facility are secured by pledges of the equity interests of, and guarantees by, substantially all of our restricted domestic subsidiaries, and liens on substantially all of our real property (outside of New York) and personal property. None of our equity investments have guaranteed, and none of the assets of our equity investments secure, our obligations under our revolving credit facility.
The provisions of our credit agreement and indentures governing our senior notes may affect our ability to obtain future financing and pursue attractive business opportunities and our flexibility in planning for, and reacting to, changes in business conditions. In addition, a failure to comply with the provisions of our revolving credit facility or indentures governing our senior notes could result in events of default, which could enable our lenders or holders of our senior notes, subject to the terms and conditions of our credit agreement or indentures, as applicable, to declare any outstanding principal of that debt, together with accrued interest, to be immediately due and payable. If the payment of any such debt is accelerated, our assets may be insufficient to repay such debt in full, and the holders of our common units could experience a partial or total loss of their investment.
A change of control could result in us facing substantial repayment obligations under our Crestwood Midstream revolving credit facility and indentures governing our senior notes.
Crestwood Midstream’s credit agreement and indentures governing our senior notes contain provisions relating to a change of control of Crestwood Equity’s general partner. If these provisions are triggered, our outstanding indebtedness may become due. In the event our outstanding indebtedness became due, there is no assurance that we would be able to pay the indebtedness, in which case the lenders under the revolving credit facility would have the right to foreclose on our assets and holders of our senior notes would be entitled to require us to repurchase all or a portion of our notes at a purchase price equal to 101% of the principal amount thereof, plus accrued and unpaid interest, if any, to the date of such repurchase, which would have a material adverse effect on us. There is no restriction on our ability or the ability of Crestwood Equity’s general partner to enter into a transaction which would trigger the change of control provision. In certain circumstances, the control of our general partner may be transferred to a third party without unitholder consent, and this may be considered a change in control under our revolving credit facility and senior notes. Please read “The control of our general partner may be transferred to a third party without unitholder consent.”
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Our ability to make cash distributions may be diminished, and our financial leverage could increase, if we are not able to obtain needed capital or financing on satisfactory terms.
Historically, we have used cash flow from operations, borrowings under our revolving credit facility, proceeds received from divestitures and issuances of debt or equity to fund our capital programs, working capital needs and acquisitions. Our capital program may require additional financing above the level of cash generated by our operations to fund growth. If our cash flow from operations decreases or distributions from our equity investments decrease as a result of lower throughput volumes on their systems or otherwise, our ability to expend the capital necessary to expand our business or increase our future cash distributions may be limited. If our cash flow from operations and the distributions we receive from subsidiaries are insufficient to satisfy our financing needs, we cannot be certain that additional financing will be available to us on acceptable terms, if at all. Our ability to obtain bank financing or to access the capital markets for future equity or debt offerings may be limited by our financial condition or general economic conditions at the time of any such financing or offering. Even if we are successful in obtaining the necessary funds, the terms of such financings could have a material adverse effect on our business, results of operations, financial condition and ability to make cash distributions to our unitholders. Further, incurring additional debt may significantly increase our interest expense and financial leverage and issuing additional limited partner interests may result in significant unitholder dilution and would increase the aggregate amount of cash required to maintain the cash distribution rate which could materially decrease our ability to pay distributions. If additional capital resources are unavailable, we may curtail our activities or be forced to sell some of our assets on an untimely or unfavorable basis.
Increases in interest rates could adversely impact our unit price, ability to issue equity or incur debt for acquisitions or other purposes, and ability to make payments on our debt obligations.
Interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. Therefore, changes in interest rates either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue equity or incur debt for acquisitions or other purposes and to make payments on our debt obligations.
A downgrade of our credit ratings could impact our and our subsidiaries’ liquidity, access to capital and costs of doing business, and maintaining credit ratings is under the control of independent third parties.
A downgrade of our credit ratings may increase our and our subsidiaries’ cost of borrowing and could require us to post collateral with third parties, negatively impacting our available liquidity. Our and our subsidiaries’ ability to access capital markets could also be limited by a downgrade of our credit ratings and other disruptions. Such disruptions could include:
• economic downturns;
• deteriorating capital market conditions;
• declining market prices for crude oil, natural gas, NGLs and other commodities;
• terrorist attacks or threatened attacks on our facilities or those of other energy companies; and
• the overall health of the energy industry, including the bankruptcy or insolvency of other companies.
Credit rating agencies perform independent analysis when assigning credit ratings. The analysis includes a number of criteria including, but not limited to, business composition, market and operational risks, as well as various financial tests. Credit rating agencies continue to review the criteria for industry sectors and various debt ratings and may make changes to those criteria from time to time. Credit ratings are not recommendations to buy, sell or hold investments in the rated entity. Ratings are subject to revision or withdrawal at any time by the rating agencies, and we cannot assure you that we will maintain our current credit ratings.
The loss of key personnel could adversely affect our ability to operate.
Our success is dependent upon the efforts of our senior management team, as well as on our ability to attract and retain both executives and employees for our field operations. Our senior executives have significant experience in the oil and gas industry and have developed strong relationships with a broad range of industry participants. The loss of these executives, or the loss of key field employees operating in competitive markets, could prevent us from implementing our business strategy and could have a material adverse effect on our customer relationships, results of operations and ability to make distributions.
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We operate joint ventures that may limit our operational flexibility.
We conduct a portion of our operations through joint ventures (including our Crestwood Permian Basin, Tres Holdings and PRBIC joint ventures), and we may enter into additional joint ventures in the future. In a joint venture arrangement, we could have less operational flexibility, as actions must be taken in accordance with the applicable governing provisions of the joint venture. In certain cases, we:
• could have limited ability to influence or control certain day to day activities affecting the operations;
• could have limited control on the amount of capital expenditures that we are required to fund with respect to these operations;
• could be dependent on third parties to fund their required share of capital expenditures;
• may be subject to restrictions or limitations on our ability to sell or transfer our interests in the jointly owned assets; and
• may be required to offer business opportunities to the joint venture, or rights of participation to other joint venture partners or participants in certain areas of mutual interest.
In addition, joint venture partners may have obligations that are important to the success of the joint venture, such as the obligation to pay substantial carried costs pertaining to the joint venture. The performance and ability of our joint venture partners to satisfy their obligations under joint venture arrangements is outside of our control. If these parties do not satisfy their obligations, our business may be adversely affected. Our joint venture partners may be in a position to take actions contrary to our instructions or requests contrary to our policies or objectives, and disputes between us and our joint venture partners may result in operational delays, litigation or operational impasses. The risks described above or the failure to continue our joint ventures or to resolvedisagreements with our joint venture partners could adversely affect our ability to conduct business that is the subject of a joint venture, which could in turn negatively affect our financial condition and results of operations.
Moreover, our decision to operate aspects of our business through joint ventures could limit our ability to consummate strategic transactions. Similarly, due to the perceived challenges of existing joint ventures, companies like ours that fund a considerable portion of their operations through joint ventures may be less attractive merger or take-over candidates. We cannot provide any assurance that our operating model will not negatively affect the value of our common units.
We may not be able to renew or replace expiring contracts.
Our primary exposure to market risk occurs at the time contracts expire and are subject to renegotiation and renewal. As of December 31, 2022, the weighted average remaining term of our consolidated portfolio of natural gas gathering contracts is approximately eight years, our consolidated portfolio of crude oil gathering contracts is approximately nine years and our consolidated portfolio of produced water gathering contracts is approximately nine years. The extension or replacement of existing contracts depends on a number of factors beyond our control, including:
• the macroeconomic factors affecting natural gas, NGL and crude economics for our current and potential customers;
• the level of existing and new competition to provide services to our markets;
• the balance of supply and demand, on a short-term, seasonal and long-term basis, in our markets;
• the extent to which the customers in our markets are willing to contract on a long-term basis; and
• the effects of federal, state or local regulations on the contracting practices of our customers.
Any failure to extend or replace a significant portion of our existing contracts, or extending or replacing them at unfavorable or lower rates, could have a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
Inflation could adversely impact our ability to control operating expenses and capital costs, increase our level of indebtedness and adversely impact our customer base. The fees we charge to customers under our contracts may not escalate sufficiently to cover our cost increases, which could negatively impact our business, financial condition and results of operations.
Although inflation in the United States has been relatively low in recent years, it rose to historically high levels in 2022. In addition, global and industry-wide supply chain disruptions caused by the COVID-19 pandemic have resulted in shortages in labor, materials and services. Such inflation and shortages have resulted in cost increases for labor, materials and services and could continue to cause costs to increase. Historically, we have been able to partially mitigate the impact that cost increases could have on our business, financial condition and results of operations through negotiated contractual rates and amounts authorized to be collected from our customers, and we intend to continue to do so. We cannot predict any future trends in the
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rate of inflation, and a significant increase in inflation, to the extent we are unable to recover higher costs through our commercial agreements or rates, would negatively impact our business, financial condition and results of operations.
Our contracts may be suspended in some circumstances.
Some third parties’ obligations under their agreements with us may be permanently or temporarily reduced upon the occurrence of certain events, some of which are beyond our control, including force majeure events wherein the supply of natural gas or crude oil is curtailed or cut off. Force majeure events generally include, without limitation, revolutions, wars, acts of enemies, embargoes, import or export restrictions, strikes, lockouts, fires, storms, floods, winter storms, acts of God, explosions, mechanical or physical failures of our equipment or facilities or those of third parties. If any third party suspends or terminates its contracts with us, our business, financial condition, results of operations and ability to make distributions could be materially adversely affected.
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and the inability to do so may disrupt our business and hinder our ability to grow.
We have completed a number of acquisitions in recent years, and we may continue to acquire businesses or assets that complement or expand our business. However, there is no guarantee that we will be able to identify attractive or suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets.
The success of any completed acquisition, including those that we have completed recently, will depend on our ability to effectively integrate the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseendifficulties and may require a disproportionate amount of our managerial and financial resources. Even if we are able to integrate acquired business operations successfully, there can be no assurance that the integration will result in the full realization of the anticipated benefits of such acquisitions, including cost savings or operational effectiveness, or that any such benefits may be achieved within an anticipated time frame.
Our failure to achieve consolidation savings, to successfully integrate the acquired businesses and assets into our existing operations or to minimize any unforeseen operational difficulties could have a material adverse effect on our business, financial condition 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 the energy midstream industry, such as:
• damage to pipelines and plants, related equipment and surrounding properties caused by natural disasters and acts of terrorism or domestic vandalism;
• subsidence of the geological structures where we store NGLs, or storage cavern collapses;
• operator error;
• inadvertentdamage from construction, farm and utility equipment;
• leaks, migrations or losses of natural gas, NGLs, crude oil or produced water;
• fires and explosions;
• cyber intrusions; and
• other hazards that could also result in personal injury, including loss of life, property and natural resources damage, pollution of the environment or suspension of operations.
These risks could result in substantial losses due to breaches of contractual commitments, personal injury and/or loss of life, damage to and destruction of property and equipment and pollution or other environmental damage. For example, we have experienced releases on our Arrow water gathering system on the Fort Berthold Indian Reservation in North Dakota, the remediation and repair costs of which were covered by insurance, but nonetheless potential future water spills could subject us to substantial penalties, fines and damages from regulatory agencies and individual landowners. These risks may also result in curtailment or suspension of our operations. A natural disaster or other hazard affecting the areas in which we operate could have a material adverse effect on our operations. We are not fully insured against all risks inherent in our business. We are also not insured against all environmental accidents that might occur, some of which may result in toxic tort claims. If a significant accident or event occurs for which we are not fully insured, it could result in a material adverse effect on our business, financial condition, results of operations and ability to make distributions.
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We may not be able to maintain or obtain insurance of the type and amount we desire at reasonable rates. As a result of market conditions, premiums and deductibles for certain of our insurance policies may substantially increase. In some instances, certain insurance could become unavailable or available only for reduced amounts of coverage. Additionally, we may be unable to recover from prior owners of our assets, pursuant to our indemnification rights, for potential environmental liabilities. Although we maintain insurance policies with insurers in such amounts and with such coverages and deductibles as we believe are reasonable and prudent, our insurance may not be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage.
We do not own all of the land on which our pipelines and facilities are located, which could disrupt our operations.
We do not own all of the land on which our pipelines and facilities (particularly our gathering and processing facilities) have been constructed, which subjects us to the possibility of more onerous terms or increased costs to obtain and maintain valid easements and rights-of-way. Easements and rights-of-way exists for varying periods of time. We obtain standard easement rights to construct and operate pipelines on land owned by third parties, and our rights frequently revert back to the landowner after we stop using the easement for its specified purpose. With regard to easements and rights-of-way on tribal lands, following a 2017 court decision issued by the federal Tenth Circuit Court of Appeals, tribal ownership of even a very small fractional interest in an allotted land (that is, tribal land owned or at one time owned by an individual Indian landowner) bars condemnation of any interest in the allotment. Consequently, the inability to condemn such allotted tribal lands under circumstances where an existing pipeline rights-of-way may soon lapse or terminate serves as an additional impediment for pipeline operators. We cannot guarantee that we will always be able to renew existing rights-of-way or obtain new rights-of-way without experiencing significant costs. Our loss of easement rights could have a material adverse effect on our ability to operate our business, thereby resulting in a material reduction in our results of operations and ability to make distributions.
Terrorist attacks or “cyber security” events, or the threat of them, may adversely affect our business.
The U.S. government has issued public warnings that indicate that pipelines and other assets might be specific targets for terrorist organizations or “cyber security” events. These potential targets might include our pipeline systems or operating systems and may affect our ability to operate or control our pipeline assets or utilize our customer service systems. Also, destructive forms of protests and opposition by extremists and other disruptions, including acts of sabotage or eco-terrorism, against oil and natural gas development and production or midstream processing or transportation activities could potentially result in damage or injury to persons, property or the environment or lead to extended interruptions of our or our customers’ operations. Additionally, the oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain processing and operational activities. At the same time, companies in our industry have been the targets of cyber-attacks and ransomware demands, and it is possible that the attacks in our industry will continue and grow in number. In addition, to assist in conducting our business, we rely on information technology systems and data hosting facilities, including systems and facilities that are hosted by third parties and with respect to which we have limited visibility and control. These systems and facilities may be vulnerable to a variety of evolving cyber security risks or information security breaches, including unauthorized access, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions. These cyber security risks could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary, personal data and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as advanced persistentthreats, may remain undetected for an extended period. The occurrence of any of these events, including any attack or threat targeted at our pipelines and other assets, could cause a substantial decrease in revenues, increased costs or other financial losses, exposure or loss of customer information, damage to our reputation or business relationships, increased regulation or litigation, disruption of our operations and/or inaccurate information reported from our operations. These developments may subject our operations to increased risks, as well as increased costs, and, depending on their ultimate magnitude, could have a material adverse effect on our business, results of operations and financial condition. Although we have adopted controls and systems, including updating our systems with recent patches and updates from our software providers and procuring limited insurance for certain cyber-related losses, that are designed to protect information and mitigate the risk of data loss and other cyber security events, such measures cannot entirely eliminate cyber security threats, particularly as these threats continue to evolve and grow. Furthermore the controls and systems we have installed may be breached or be inadequate to address a risk that arises. We are not aware of any cyber security events that impacted our company that have or could have resulted in a material loss; however there is no assurance that such a breach has not already occurred and we are unaware of it, and that we will not suffer such a loss in the future.
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The risk of terrorism and political unrest in various energy producing regions may adversely affect the economy and price and availability of products.
An act of terror, or political unrest, in any of the major energy producing regions of the world could potentially result in disruptions in the supply of crude oil and natural gas, which could have a material impact on both availability and price. Since Russia’s military invasion of Ukraine in 2022, prices for commodities produced in those countries, including crude oil and natural gas, have risen sharply and have been volatile due to market concerns of worldwide supply constraints. Terrorist attacks in the areas of our operations could negatively impact our ability to transport propane to our locations. These risks could potentially negatively impact our consolidated results of operations.
We are or may become subject to cyber security and data privacy laws, regulations, litigation and directives relating to our processing of personal data.
Several jurisdictions in which we operate throughout the United States may have laws governing how we must respond to a cyber incident that results in the unauthorized access, disclosure or loss of personal data. Additionally, new laws and regulations governing cybersecurity, data privacy and unauthorized disclosure of confidential information, including international comprehensive data privacy regulations and recent U.S. state legislation in California, Virginia and Colorado (some of which, among other things, provides for a private right of action), pose increasingly complex compliance challenges and could potentially elevate our costs over time. Our business involves collection, uses and other processing of personal data of our employees, contractors, suppliers and service providers. As legislation continues to develop and cyber incidents continue to evolve, we will likely be required to expend significant resources to continue to modify or enhance our protective measures to comply with such legislation and to detect, investigate and remediate vulnerabilities to cyber incidents and report any cyber incidents to the applicable regulatory authorities. In particular, in response to recent ransomware attacks, the Department of Homeland Security has issued a security directive to certain pipeline companies requiring the companies to appoint personnel, perform cybersecurity assessments, and report incidents and other information. Any failure by us, or a company we acquire, to comply with such laws and regulations could result in reputational harm, loss of goodwill, penalties, liabilities, and/or mandated changes in our business practices.
Risks Related to Regulatory Matters
Increasing attention to environmental, social and governance (ESG) matters may impact our business.
Increasing attention to climate change, societal expectations for companies to address climate change, investor and societal expectations regarding voluntary ESG disclosures, and customer demand for alternative forms of energy may result in increased costs, reduced demand for our services, reduced profits, increased risks of governmental investigations and private party litigation, and negative impacts on our common unit price and access to capital markets. Additionally, there are organizations that provide information to investors on corporate governance, climate change, health and safety and other ESG-related factors and have developed ratings processes for evaluating companies on their approach to ESG matters. Unfavorable ESG ratings could lead to increased negative investor sentiment toward us or our customers and to the diversion of investment to other industries which could have a negative impact on our unit price and/or our access to capital and costs of capital. Additionally, to the extent ESG matters negatively impact our reputation, we may not be able to compete as effectively to recruit or retain employees, which may adversely affect our operations. Such ESG matters may also impact our customers or suppliers, which may adversely impact our business, financial condition, or results of operations.
Additionally, we have announced various voluntary ESG targets in our carbon management plan and may not be able to meet such targets in the manner or on such a timeline as initially contemplated, as a result of, but not limited to, unforeseen costs or technical difficulties associated with achieving such results. To the extent we do meet such targets, it may be achieved through various contractual arrangements, including the purchase of various credits that may be deemed to mitigate our ESG impact instead of actual changes in our ESG performance. Also, despite these goals, we may receive pressure from investors, lenders, or other groups to adopt more aggressive climate or other ESG-related goals, but we cannot guarantee that we will be able to implement such goals because of potential costs or technical or operational obstacles.
Furthermore, public statements with respect to ESG matters, such as emissions reduction goals, other environmental goals, or other commitments addressing certain social issues, are becoming increasingly subject to heightened scrutiny from public and governmental authorities related to the risk of potential “greenwashing,” (i.e., misleading information or falseclaimsoverstating potential ESG benefits). For example, in March 2021, the SEC established the Climate and ESG Task Force in the Division of Enforcement to identify and address potential ESG-related misconduct, including greenwashing. Certain non-governmental organizations and other private sectors have also filed lawsuits under various securities and consumer protection
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laws alleging that certain ESG statements, goals or standards were misleading, false, or otherwise deceptive. As a result, we may face increased litigation risk from private parties and governmental authorities related to our ESG efforts. In addition, any allegedclaims of greenwashing against us or others in our industry may lead to further negative sentiment and diversion of investments. Additionally, we could face increasing costs as we attempt to comply with and navigate further regulatory ESG-related focus and scrutiny. See Item 1. Business, “ Regulation” and “Environmental and Occupational Safety and Health Matters ” for a further discussion of these matters.
Our operations are subject to extensive regulation, and regulatory measures adopted by regulatory authorities could have a material adverse effect on our business, financial condition and results of operations.
Our operations, including our Tres Holdings joint venture, are subject to extensive regulation by federal, state and local regulatory authorities. Federal regulation under the Natural Gas Act extends to such matters as:
• rates, operating terms and conditions of service;
• the form of tariffs governing service;
• the types of services we may offer to our customers;
• the certification and construction of new, or the expansion of existing facilities;
• the acquisition, extension, disposition or abandonment of facilities;
• contracts for service between storage and transportation providers and their customers;
• creditworthiness and credit support requirements;
• the maintenance of accounts and records;
• relationships among affiliated companies involved in certain aspects of the natural gas business;
• the initiation and discontinuation of services; and
• various other matters.
The FERC issued a Notice of Inquiry (NOI) on April 19, 2018, thereby initiating a review of its policies on certification of natural gas pipelines, including an examination of its long-standing Policy Statement on Certification of New Interstate Natural Gas Pipeline Facilities, issued in 1999 (1999 Policy Statement), that is used to determine whether to grant certificates for new pipeline projects. On February 18, 2021, the FERC issued another NOI, reopening its review of the 1999 Policy Statement. On February 18, 2022, the FERC issued a Policy Statement on the Certificate of New Interstate Natural Gas Facilities and a Policy Statement on the Consideration of Greenhouse Gas Emissions in Natural Gas Infrastructure Project Reviews (2022 Policy Statements), to be effective that same day. On March 24, 2022, the FERC issued an order converting the 2022 Policy Statements into draft policy statements, and requested further comments. The FERC will not apply the draft 2022 Policy Statements until it issues final guidance on these topics. We are unable to predict what, if any, changes may be proposed to the draft 2022 Policy Statements that will affect our natural gas pipeline business or when such proposals, if any, might become effective. We do not expect that any change in these policy statements would affect us in a materially different manner than any other natural gas pipeline company operating in the United States.
There can be no assurance that the FERC will continue to pursue its approach of pro-competitive policies as it considers matters such as pipeline rates and rules and policies that may affect rights of access to natural gas transportation capacity and transportation and storage facilities. Failure to comply with applicable regulations under the Natural Gas Act, the Natural Gas Policy Act of 1978, the NGPSA and certain other laws, and with implementing regulations associated with these laws, could result in the imposition of administrative and criminal remedies and civil penalties of up to approximately $1.5 million per day, per violation.
A change in the jurisdictional characterization of our gathering assets may result in increased regulation, which could cause our revenues to decline and operating expenses to increase.
Our natural gas and crude oil gathering operations are generally exempt from the jurisdiction and regulation of the FERC, except for certain anti-market manipulation provisions. FERC regulation nonetheless affects our businesses and the markets for products derived from our gathering businesses. The FERC’s policies and practices across the range of its oil and gas regulatory activities, including, for example, its policies on open access transportation, rate making, capacity release and market center promotion, indirectly affect intrastate markets. In recent years, the FERC has pursued pro-competitive policies in its regulation of interstate oil and natural gas pipelines. However, we have no assurance that the FERC will continue this approach as it considers matters such as pipeline rates and rules and policies that may affect rights of access to oil and natural gas transportation capacity. In addition, the distinction between FERC-regulated transmission services and federally unregulated gathering services has regularly been the subject of substantial, on-going litigation. Consequently, the classification and regulation of some of our pipelines could change based on future determinations by the FERC, the courts or Congress. If our
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gathering operations become subject to FERC jurisdiction, the result may adversely affect the rates we are able to charge and the services we currently provide, and may include the potential for a termination of certain gathering agreements.
State and municipal regulations also impact our business. Common purchaser statutes generally require gatherers to gather or provide services without undue discrimination as to source of supply or producer; as a result, these statutes restrict our right to decide whose production we gather or transport. Federal law leaves any economic regulation of natural gas gathering to the states. The states in which we currently operate have adopted complaint-based regulation of gathering activities, which allows oil and gas producers and shippers to file complaints with state regulators in an effort to resolve access and rate grievances. Other state and municipal regulations may not directly regulate our gathering business, but may nonetheless affect the availability of natural gas for purchase, processing and sale, including state regulation of production rates and maximum daily production allowable from gas wells. While our gathering lines currently are subject to limited state regulation, there is a risk that state laws will be changed, which may give producers a stronger basis to challenge the rates, terms and conditions of its gathering lines.
Our operations are subject to compliance with environmental and operational health and safety laws and regulations that may expose us to significant costs and liabilities.
Our operations are subject to stringent federal, tribal, regional, state and local laws and regulations governing worker health and safety aspects of our operations, the discharge of materials into the environment and otherwise relating to environmental protection. These requirements may take the form of laws, regulations, executive actions and various other legal initiatives. See Item 1. Business, “ Regulation” and “Environmental and Occupational Safety and Health Matters ” for a further discussion on these matters. Compliance with these regulations and other regulatory initiatives or any other new environmental laws and regulations could, among other things, require us or our customers to install new or modified emission controls on equipment or processes and incur significantly increased capital or operating expenditures and operating delays, restrictions or cancellations with respect to our operations, which costs may be significant. Additionally, one or more of these developments that impact our customers involved in oil and natural gas exploration and production could reduce demand for our services. These developments could have a material adverse effect on our business, results of operations and financial condition.
Our and our customers’ operations are subject to various risks arising out of the threat of climate change, energy conservation measures, or initiatives that stimulate demand for alternative forms of energy that could result in increased costs, limit the areas in which oil and natural gas production may occur and reduced demand for our services.
The threat of climate change continues to attract considerable attention in the U.S. and in foreign countries. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions, which makes our and our customers’ operations subject to a number of regulatory, political, litigation and financial risks arising out of the threat of climate change, energy conservation measures, or initiatives that stimulate demand for alternative forms of energy that could result in increased operating costs, limit the areas in which oil and natural gas production may occur, and reduce the demand for the crude oil and natural gas. Risks arising out of the threat of climate change, energy conservation measures, governmental requirements for renewable energy resources, increasing customer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices may create new competitive conditions that result in reduced demand for the crude oil and natural gas our customers produce and our services. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows.
In the U.S., no comprehensive climate change legislation has been implemented at the federal level, though the IRA 2022 advances numerous climate-related objectives, including a federal fee on excess methane emissions from certain facilities. However, with the EPA’s determination that GHG emissions present a danger to public health and the environment as a pollutant under the CAA, the EPA has adopted several rules that, among other things, establish construction and operating permit reviews for GHG emissions from certain large stationary sources, require the monitoring and annual reporting of GHG emissions from certain petroleum and natural gas system sources in the U.S., implement New Source Performance Standards directing the reduction of methane from certain new, modified or reconstructed facilities, and together with the U.S. Department of Transportation, implement GHG emissions limits on vehicles manufactured for operation in the U.S. In November 2021, the EPA issued a proposed rule that would make methane emissions from the crude oil and natural gas sources category more stringent, by establishing Quad Ob new source and Quad Oc first time existing source standards of performance for methane and volatile organic compound emissions. The EPA published a supplemental proposal in November 2022 for public comment. Among other items, the proposal sets forth specific revisions strengthening the first nationwide emissions guidelines for states to limit methane from existing crude oil and natural gas facilities. The proposal also revises requirements for fugitive emissions
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monitoring and repair as well as equipment leaks and the frequency of monitoring surveys, establishes a “super emitter” response program to timely mitigate emissions events, and provides additional options for the use of advanced monitoring to encourage the deployment of innovative technologies to detect and reduce methane emissions. The proposal is expected to be finalized in 2023, though it may be challenged in court. We are unable to predict at this time the scope of any final regulatory requirements and the expected cost to comply with such requirements. Any increase in regulatory scope and oversight may increase compliance expenditure or mitigation costs for our operations. Additionally, the IRA 2022 imposes fees on the emission of methane that exceed certain thresholds from sources required to report their GHG emissions to the EPA. The methane emissions fees would start in calendar year 2024 at $900 per ton of methane, increase to $1,200 per ton in 2025, and be set at $1,500 per ton for 2026 and each year thereafter.
The methane emissions fee and renewable and low-carbon energy funding provisions of the law could increase our and our customers' operating costs and accelerate the transition away from fossil fuels, which could in turn reduce demand for our products and services and adversely affect our business and results of operations.
Various states and groups of states have also adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as GHG cap and trade programs, carbon taxes, reporting and tracking programs and restriction of emissions. At the international level, the Paris Agreement requires nations to submit non-binding GHG emissions reduction goals every five years after 2020. In April 2021, the Biden Administration announced nationwide emissions reduction targets that would reduce GHG emissions by 50-52% from their 2005 levels by 2030. The international community gathered again in November 2021 at COP26, during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies, amongst other measures. Relatedly, the United States and European Union jointly announced at COP26 the launch of the Global Methane Pledge, an initiative committing to a collective goal of reducing global methane emissions by at least 30 percent from 2020 levels by 2030, including "all feasible reductions" in the energy sector. At COP27 in November 2022, countries reiterated the agreements from COP26 and were called upon to accelerate efforts toward the phase-out of inefficient fossil fuel subsidies. The United States has also announced, in conjunction with the European Union and other partner countries, that it would develop standards for monitoring and reporting methane emissions to help create a market for low methane-intensity gas. Although no firm commitment or timeline to phase out or phase down all fossil fuels was made at COP27, there can be no guarantees that countries will not seek to implement such a phase out in the future. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, COP27, or other international conventions cannot be predicted at this time and it is unclear what additional initiatives may be adopted or implemented that may have a negative impact to our financial condition or results of operations.
Governmental, scientific and public concern over the threat of climate change arising from GHG emissions has resulted in increasing political risks in the U.S. that may limit fracturing of oil and natural gas wells or result in restrictions of leases or other authorizations for oil and gas development on federal lands and offshore waters. Other actions to restrict oil and natural gas activities that could be pursued by the Biden Administration may include the imposition of more restrictive requirements for the establishment of pipeline infrastructure or the permitting of LNG export facilities, as well as more restrictive GHG emissions limitations for oil and gas facilities. Litigation risks are also increasing, as a number of parties have sought to bring suit against fossil fuel companies in state or federal court, alleging that such companies created public nuisances by producing fuels that contributed to global warming or that such companies have been aware of the adverse effects of climate change for some time but failed to adequatelydisclose those impacts to their investors or customers.
There are also increasing financial risks for fossil fuel energy companies, as various investors become increasingly concerned about the potential effects of climate change and may elect in the future to shift some or all of their investments into other sectors. Institutional lenders who provide financing to fossil fuel energy companies also have become more attentive to sustainable lending practices that favor "clean" power sources such as wind and solar photovoltaic, making those sources more attractive for investment, and some of them may elect not to provide funding for fossil fuel energy companies. For example, at COP26, the Glasgow Financial Alliance for Net Zero (GFANZ) announced that commitments from over 450 firms across 45 countries had resulted in substantial capital committed to net zero goals. The various sub-alliances of GFANZ generally require participants to set short-term, sector-specific targets to transition their financing, investing, and/or underwriting activities to net zero by 2050. Additionally, there is the possibility that financial institutions will be required to adopt policies that limit funding for fossil fuel energy companies. In late 2020, the Federal Reserve joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector, and in September 2022, announced that six of the U.S.' largest banks will participate in a pilot climate scenario analysis exercise, expected to be launched in early 2023, to enhance the ability of firms and supervisors to measure and manage climate-related financial risk. The Federal Reserve released its pilot exercise in January 2023, which is designed to analyze the impact of both physical and transition risks related to climate change on specific assets of the banks’ portfolios. While we cannot predict what policies may
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result from these developments, such efforts could make it more difficult to secure funding for exploration and production or midstream energy business activities.
The adoption and implementation of new or more stringent international, federal or state legislation, regulations or other regulatory initiatives that impose more stringent standards for GHG emissions from the oil and gas sector or otherwise restrict the areas in which this sector may produce fossil fuels or generate GHG emissions could result in increased costs of compliance or costs of consuming, and thereby reduce demand for fossil fuels, which could reduce demand for our transportation and storage services. Political, litigation and financial risks may result in our customers restricting or canceling production activities, incurring liability for infrastructure damages as a result of climatic changes or impairing their ability to continue to operate in an economic manner, which also could reduce demand for our services. Moreover, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and biofuels) could reduce demand for hydrocarbons and for our services. For more information, see our regulatory disclosure in Item 1. Business, “Regulation” and “Environmental and Occupational Safety and Health Matters .”
Finally, climatic events in the areas in which we operate, whether from climate change or otherwise, can cause disruptions and in some cases delays in, or suspension of, our services. These events, including, but not limited to, drought, winter storms, wildfire, extreme temperatures or flooding, may become more intense or more frequent as a result of climate change and could have an adverse effect on our continued operations as well as the operations of our oil and natural gas customers on whom we rely upon for throughput and our third party vendors whom supply us with products and services. Additionally, changing meteorological conditions, particularly temperature, may result in changes to the amount, timing, or location of demand for energy or the products we transport, which may impact demand for our services. While our consideration of changing climatic conditions and inclusion of safety factors in design is intended to reduce the uncertainties that climate change and other events may potentially introduce, our ability to mitigate the adverse impacts of these events depends in part on the effectiveness of our facilities and our disaster preparedness and response and business continuity planning, which may not have considered or be prepared for every eventuality.
We may incur higher costs as a result of pipeline integrity management program testing and additional safety legislation.
Pursuant to authority under the NGPSA and HLPSA, PHMSA has established rules requiring pipeline operators to develop and implement integrity management programs for certain natural gas and hazardous liquid pipelines located where a leak or rupture could harm HCAs, MCAs, Class 3 and 4 areas, as well as areas unusually sensitive to environmental damage and commercially navigable waterways. Among other things, these regulations require operators of covered pipelines like us to:
• perform ongoing assessments of pipeline integrity;
• identify and characterize applicable threats to pipeline segments that could impact a HCA, MCA or Class 3 and 4 area;
• maintain processes for data collection, integration and analysis;
• repair and remediate pipelines as necessary; and
• implement preventive and mitigating actions.
Additionally, certain states where we conduct operations, including New Mexico, North Dakota and Wyoming, have adopted regulations similar to existing PHMSA regulations for certain intrastate natural gas pipelines, and New Mexico and Texas have also adopted regulations similar to existing PHMSA regulations for certain intrastate hazardous liquid pipelines. We estimate that the total future costs to complete the testing required by existing PHMSA or any applicable state regulations will not have a material impact to our results. This estimate does not include the costs, if any, for repair, remediation, preventative or mitigating actions that may be determined to be necessary as a result of the testing program itself, which costs could be substantial. The results of this testing could cause us to incur significant and unanticipated capital and operating expenditures for repairs or upgrades deemed necessary to ensure the continued safe and reliable operation of our pipelines.
Moreover, federal legislation or implementing regulations adopted in recent years may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital costs, operational delays and costs of operations. See Item 1. Business, “ Regulation” and “Environmental and Occupational Safety and Health Matters ” for a further discussion on pipeline safety matters.
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Risks Inherent in an Investment in Our Equity
We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses to enable us to pay quarterly distributions to our common and preferred unitholders.
We may not have sufficient cash each quarter to pay quarterly distributions to our common unitholders or, alternatively, we may reallocate a portion of our available cash to debt repayments or capital investments. The amount of cash we can distribute on our common units principally depends upon the amount of cash we generate from our operations, distributions received from our joint ventures, and payments of fees and expenses as well as decisions the board of directors makes regarding acceptable levels of debt or the desire to invest in new growth projects. Our board typically reviews these factors on a quarterly basis. Before we pay any cash distributions on our preferred and common units, we will establish reserves and pay fees and expenses, including reimbursements to our general partner and its affiliates, for all expenses they incur and payments they make on our behalf. These costs will reduce the amount of cash available to pay distributions to our common unitholders and, to the extent we are unable to declare and pay fixed cash distributions on our preferred units, we cannot make cash distributions to our common unitholders until all payments accruing on the preferred units have been paid.
The amount of cash we have available to distribute on our preferred and common units will fluctuate from quarter to quarter based on, among other things:
• the rates charged for services and the amount of services customers purchase, which will be affected by, among other things, the overall balance between the supply of and demand for commodities, governmental regulation of our rates and services and our ability to obtain permits for growth projects;
• force majeure events that damage our or third-party pipelines, facilities, related equipment and surrounding properties;
• prevailing economic and market conditions;
• governmental regulation, including changes in governmental regulation in our industry;
• changes in tax laws;
• the level of competition from other midstream companies;
• the level of our operations and maintenance and general and administrative costs;
• the level of capital expenditures we make;
• our ability to make borrowings under our revolving credit facility;
• our ability to access the capital markets for additional investment capital; and
• acceptable levels of debt, liquidity and/or leverage.
In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including: the level and timing of our capital 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.
Decreases in commodity prices can negatively 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 unitholders.
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We may issue additional common units without common unitholder approval, which would dilute existing common unitholder ownership interests.
Our partnership agreement does not limit the number of additional limited partner interests we may issue at any time without the approval of our existing common unitholders. The issuance of additional common units or other equity interests of equal or senior rank will have the following effects:
• our existing common unitholders’ proportionate ownership interest in us will decrease;
• the amount of cash available for distribution on each common unit may decrease;
• the ratio of taxable income to distributions may increase;
• the relative voting strength of each previously outstanding common unit may be diminished; and
• the market price of the common units may decline.
Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units and has other governance differences from typical corporations .
Unitholders’ voting rights are restricted by a provision in our partnership agreement stating that any units held by a person that owns 20% or more of any class of our common units then outstanding, other than our general partner and its affiliates, cannot be voted on any matter. In addition, our partnership agreement contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting our unitholders’ ability to influence our management. As a result of this provision, the trading price of our common units may be lower than other forms of equity ownership due to the absence of a takeover premium in the trading price or other governance differences.
Common unitholders may have liability to repay distributions and in certain circumstances may be personally liable for the obligations of the partnership.
Under certain circumstances, common unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act (the Delaware Act), we may not make a distribution to our common unitholders if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. A purchaser of units who becomes a limited partner is liable for the obligations of the transferring limited partner to make contributions to the partnership that are known to the purchaser of units at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interests and liabilities that are non-recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.
It may be determined that the right, or the exercise of the right by the limited partners as a group, to (i) remove or replace our general partner; (ii) approve some amendments to our partnership agreement; or (iii) take other action under our partnership agreement constitutes “participation in the control” of our business. A limited partner that participates in the control of our business within the meaning of the Delaware Act may be held personally liable for our obligations under the laws of Delaware to the same extent as our general partner. This liability would extend to persons who transact business with us under the reasonable belief that the limited partner is a general partner. Neither our partnership agreement nor the Delaware Act specifically provides for legal recourse against our general partner if a limited partner were to lose limited liability through any fault of our general partner.
The amount of cash we have available for distribution to common unitholders depends primarily on our cash flow (including distributions from joint ventures) and not solely on profitability, which may prevent us from making cash distributions during periods when we record net income.
The amount of cash we have available for distribution depends primarily upon our cash flow, including cash flow from reserves and working capital or other borrowings and cash distributions received from our joint ventures, and not solely on profitability, which will be affected by non-cash items. As a result, we may pay cash distributions during periods when we record net losses for financial accounting purposes and may not pay cash distributions during periods when we record net income.
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Our preferred units contain covenants that may limit our business flexibility.
Our preferred units contain covenants preventing us from taking certain actions without the approval of the holders of a majority or a super-majority of the preferred units, depending on the action as described below. The need to obtain the approval of holders of the preferred units before taking these actions could impede our ability to take certain actions that management or our board of directors may consider to be in the best interests of its unitholders. The affirmative vote of the then-applicable voting threshold of the outstanding preferred units, voting separately as a class with one vote per preferred unit, shall be necessary to amend our partnership agreement in any manner that (i) alters or changes the rights, powers, privileges or preferences or duties and obligations of the preferred units in any material respect; (ii) except as contemplated in the partnership agreement, increases or decreases the authorized number of preferred units; or (iii) otherwise adversely affects the preferred units, including without limitation the creation (by reclassification or otherwise) of any class of senior securities (or amending the provisions of any existing class of partnership interests to make such class of partnership interests a class of senior securities). In addition, our partnership agreement provides certain rights to the preferred unitholders that could impair our ability to consummate (or increase the cost of consummating) a change-in-control transaction, which could result in less economic benefits accruing to our common unitholders.
The control of our general partner may be transferred to a third party without unitholder consent.
Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of our unitholders. The new owner of our general partner would then be in a position, subject to obtaining any approvals or consents required under the applicable governing documents, to replace the board of directors and officers of our general partner with its own choices and to control the decisions taken by our board of directors and officers. This effectively permits a “change of control” without the vote or consent of the common unitholders. In addition, such a change of control could result in our indebtedness becoming due. Please read risk factor “ A change of control could result in us facing substantial repayment obligations under our revolving credit facility and senior notes.”
Our partnership agreement limits our general partner’s fiduciary duties to us and restricts the remedies available for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.
Our partnership agreement contains provisions that reduce the standards to which our general partner would otherwise be held by state fiduciary duty law. For example, our partnership agreement:
• provides that our general partner is entitled to make decisions in “good faith” if it reasonably believes that the decisions are in our best interests;
• generally provides that affiliated transactions and resolutions of conflicts of interest not approved by the Conflicts Committee of the board of directors of our general partner and not involving a vote of unitholders must be on terms no less favorable to us than those generally being provided to or available from unrelated third parties or be “fair and reasonable” to us and that, in determining whether a transaction or resolution is “fair and reasonable,” our general partner may consider the totality of the relationships among the parties involved, including other transactions that may be particularly advantageous or beneficial to us; and
• provides that our general partner and its officers and directors will not be liable for monetary damages to us, our limited partners or assignees for any acts or omissions unless there has been a final and non-appealable judgment entered by a court of competent jurisdiction determining that the general partner or those other persons acted in bad faith or engaged in fraud, willful misconduct or gross negligence.
Our general partner has a limited call right that may require unitholders to sell their units at an undesirable time or price.
If at any time our general partner and its affiliates own more than 80% of our outstanding units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the units held by unaffiliated persons at a price not less than their then-current market price. As a result, unitholders may be required to sell their units at an undesirable time or price and may not receive any return on their investment. Unitholders may also incur a tax liability upon a sale of their units.
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Risks Related to our Tax Matters
Our tax treatment depends on our status as a partnership for U.S. federal income tax purposes. If the IRS were to treat us as a corporation for federal income tax purposes, or we were to become subject to material additional amounts of entity-level taxation for state tax purposes, then our cash available for distribution to unitholders would be substantially reduced.
The anticipated after-tax economic benefit of an investment in our units depends largely on our being treated as a partnership for U.S. federal income tax purposes.
Despite the fact that we are organized as a limited partnership under Delaware law, we would be treated as a corporation for U.S. federal income tax purposes unless we satisfy a “qualifying income” requirement. Based upon our current operations and current Treasury Regulations, we believe we satisfy the qualifying income requirement. However, no ruling has been or will be requested regarding our treatment as a partnership for U.S. federal income tax purposes. Failing to meet the qualifying income requirement or a change in current law could cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to taxation as an entity.
If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate. Distributions to our unitholders would generally be taxed again as corporate distributions, and no income, gains, losses, deductions or credits would flow through to our unitholders. Because a tax would be imposed upon us as a corporation, our cash available for distribution to our unitholders would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flow and after-tax return to our unitholders, likely causing a substantial reduction in the value of our units.
Our partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution amounts may be adjusted to reflect the impact of that law on us. At the state level, several states have been evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise or other forms of taxation. Imposition of a similar tax on us in the jurisdictions in which we operate or in other jurisdictions to which we may expand could substantially reduce our cash available for distribution to our unitholders.
The tax treatment of publicly traded partnerships or an investment in our units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly applied on a retroactive basis.
The present U.S. federal income tax treatment of publicly traded partnerships, including us, or an investment in our units may be modified by administrative, legislative or judicial changes or differing interpretations at any time. Members of Congress have frequently proposed and considered substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships. Recent proposals have provided for the expansion of the qualifying income exception for publicly traded partnerships in certain circumstances and other proposals have provided for the total elimination of the qualifying income exception upon which we rely for our partnership tax treatment.
In addition, the Treasury Department has issued, and in the future may issue, regulations interpreting those laws that affect publicly traded partnerships. There can be no assurance that there will not be further changes to U.S. federal income tax laws or the Treasury Department’s interpretation of the qualifying income rules in a manner that could impair our ability to qualify as a publicly traded partnership in the future.
Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any changes or other proposals will ultimately be enacted. Any future legislative changes could negatively impact the value of an investment in our units. Unitholders are urged to consult with their own tax advisors with respect to the status of regulatory or administrative developments and proposals and their potential effect on their investment in our units.
If the IRS were to contest the federal income tax positions we take, it may adversely impact the market for our units, and the costs of any such contest would reduce our cash available for distribution to our unitholders.
We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes. The IRS may adopt positions that differ from the positions we take. It may be necessary to resort to administrative or court proceedings to sustain some or all of the positions we take. A court may not agree with the positions we take. Any contest with the IRS may materially and adversely impact the market for our units and the price at which they trade. In addition, the costs of
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any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.
If the IRS makes audit adjustments to our income tax returns for tax years beginning after December 31, 2017, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us, in which case our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.
Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes audit adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under 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 adjustments into account and pay any resulting taxes (including applicable penalties or interest) in accordance with their interests in us during the tax year under audit, there can be no assurance that such election will be practical, permissible or effective in all circumstances. As a result, our current unitholders may bear some or all of the tax liability resulting from such audit adjustment, even if such unitholders did not own units in us during the tax year under audit. If, as a result of any such audit adjustment, we are required to make payments of taxes, penalties and interest, our cash available for distribution to our unitholders might be substantially reduced and our current and former unitholders may be required to indemnify us for any taxes (including any applicable penalties and interest) resulting from such audit adjustments that were paid on such unitholders’ behalf.
Our unitholders are required to pay taxes on their share of our income even if they do not receive any cash distributions from us.
Our unitholders are required to pay any U.S. federal income taxes and, in some cases, state and local income taxes on their share of our taxable income whether or not they receive cash distributions from us. For example, if we sell assets and use the proceeds to repay existing debt or fund capital expenditures, a unitholder may be allocated taxable income and gain resulting from the sale and our cash available for distribution would not increase. Similarly, taking advantage of opportunities to reduce our existing debt, such as debt exchanges, debt repurchases, or modifications of our existing debt could result in “cancellation of indebtedness income” being allocated to our unitholders as taxable income without any increase in our cash available for distribution. Our unitholders may not receive cash distributions from us equal to their share of our taxable income or even equal to the actual tax liability that results from that income.
Tax gain or loss on the disposition of our units could be more or less than expected.
If our unitholders sell their units, they will recognize a gain or loss equal to the difference between the amount realized and the tax basis in those units. Because distributions in excess of our unitholders’ allocable share of our total net taxable income result in a reduction in their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units they sell will, in effect, become taxable income to them if they sell such units at a price greater than their tax basis in those units, even if the price they receive is less than their original cost. In addition, because the amount realized includes a unitholder’s share of our nonrecourse liabilities, if they sell their units they may incur a tax liability in excess of the amount of cash received from the sale.
Furthermore, a substantial portion of the amount realized from the sale of our units, whether or not representing gain, may be taxed as ordinary income due to potential recapture of depreciation deductions. Thus, our unitholders may recognize both ordinary income and capital loss from the sale of their units if the amount realized on a sale of their units is less than their adjusted basis in the units. Net capital loss may only offset capital gains and, in the case of individuals, up to $3,000 of ordinary income per year. In the taxable period in which our unitholders sell their units, they may recognize ordinary income from our allocations of income and gain to them prior to the sale and from recapture items that generally cannot be offset by any capital loss recognized upon the sale of units.
Unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
In general, we are entitled to a deduction for interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year. However, our deduction for business interest is limited to the sum of our business interest income and a certain percentage of our adjusted taxable income. For the purposes of this limitation, our adjusted taxable income is computed without regard to any business interest expense or business interest income. If our business interest is subject to limitation under
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these rules, our unitholders will be limited in their ability to deduct their share of any interest expense that has been allocated to them. As a result, unitholders may be subject to limitation on their ability to deduct interest expense incurred by us.
Tax-exempt entities face unique tax issues from owning our units that may result in adverse tax consequences to them.
Investment in our units by tax-exempt entities, such as employee benefit plans and individual retirement accounts (known as IRAs) raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from U.S. federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Additionally, all or part of any gain recognized by such tax-exempt organization upon a sale or other disposition of our units may be unrelated business taxable income and may be taxable to them. Tax-exempt entities should consult a tax advisor before investing in our units.
Non-U.S. unitholders will be subject to U.S. taxes and withholding with respect to their income and gain from owning our units.
Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business. Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. 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 tax on the amount of 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 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 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 is generally required to withhold 10% of the amount realized by the transferor unless the transferor certifies that it is not a non-U.S. person. While the determination of a partner’s amount realized generally includes any decrease of a partner’s share of the partnership’s liabilities, the Treasury regulations provide that the amount realized on a transfer of an interest in a publicly traded partnership, such as our units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. 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 their tax advisors regarding the impact of these rules on an investment in our units.
We will treat each purchaser of our units as having the same tax benefits without regard to the specific units actually purchased. The IRS may challenge this treatment, which could adversely affect the value of our units.
Because we cannot match transferors and transferees of units and because of other reasons, we have adopted certain methods for allocating depreciation and amortization deductions that may not conform to all aspects of existing Treasury Regulations. A successful IRS challenge to the use of these methods could adversely affect the amount of tax benefits available to our unitholders. It also could affect the timing of these tax benefits or the amount of gain from any sale of our units and could have a negative impact on the value of our units or result in audit adjustments to our unitholders’ tax returns.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month, instead of on the basis of the date a particular unit is transferred. The IRS may challenge this treatment, which could change the allocation of items of income, gain, loss and deduction among our unitholders.
We generally prorate our items of income, gain, loss and deduction between transferors and transferees of our units each month based upon the ownership of our units on the first day of each month (the Allocation Date), instead of on the basis of the date a particular unit is transferred. Similarly, we generally allocate certain deductions for depreciation of capital additions, gain or loss realized on a sale or other disposition of our assets and, in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.
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A unitholder whose units are the subject of a securities loan (i.e., a loan to a “short seller” to cover a short sale of units) may be considered as having disposed of those units. If so, he would no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and may recognize gain or loss from the disposition.
Because there are no specific rules governing the U.S. federal income tax consequences of loaning a partnership interest, a unitholder whose units are the subject of a securities loan may be considered to have disposed of the loaned units. In that case, they may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan, any of our income, gain, loss or deduction with respect to those units may not be reportable by the unitholder and any cash distributions received by the unitholder as to those units could be fully taxable as ordinary income. Unitholders desiring to assure their status as partners and avoid the risk of gain recognition from securities loan are urged to consult a tax advisor to determine whether it is advisable to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.
Our unitholders will likely be subject to state and local taxes and income tax return filing requirements in jurisdictions where they do not live as a result of investing in our units.
In addition to federal income taxes, our unitholders may be subject to other taxes, including state and local taxes, unincorporated business taxes, estate, inheritance or intangible taxes and non-U.S. taxes that are imposed by the various jurisdictions in which we conduct business or own property now or in the future, even if they do not live in any of those jurisdictions. Our unitholders will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these various jurisdictions. Further, unitholders may be subject to penalties for failure to comply with those requirements. It is our unitholders’ responsibility to file all required U.S. federal, state, local and non-U.S. tax returns and pay any taxes due in these jurisdictions. Unitholders should consult with their own tax advisors regarding the filing of such tax returns, the payment of such taxes, and the deductibility of any taxes paid.
The tax treatment of distributions on our preferred units is uncertain and the IRS may determine that preferred distributions are guaranteed payments, which may result in less favorable tax treatment to the holder of such preferred units.
The tax treatment of distributions on our preferred units is uncertain. We will treat each of the holders of the preferred units as partners for tax purposes and will not treat preferred distributions as guaranteed payments for the use of capital. However, if the IRS were to determine that such preferred distributions were guaranteed payments, the preferred distributions would generally be taxable to each of the holders of preferred units as ordinary income and the holders of preferred units would recognize taxable income from the accrual of such a guaranteed payment (even in the absence of a contemporaneous cash distribution). Although we expect that much of our income will be eligible for the 20% deduction for qualified publicly traded partnership income, 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.
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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) storage and 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 and disposal services to producers in the Williston Basin and Powder River Basin.
• Gathering and Processing South . Our gathering and processing south operations provide natural gas gathering, compression, treating and processing services, crude oil gathering services and produced water gathering and disposal services to producers in the Delaware Basin.
• Storage and Logistics . Our storage and logistics operations provide NGLs, crude oil and natural gas storage, terminal, marketing and transportation (including rail, truck and pipeline) services to producers, refiners, marketers, utilities and other customers.
Outlook and Trends
Our business objective is to create long-term value for our unitholders. We expect to create value for our investors by generating stable operating margins and improving cash flows from our diversified midstream operations by prudently financing investments in our assets and expansions of our portfolio, maximizing throughput and optimizing services on our assets, and effectively controlling our capital expenditures, operating and administrative costs.
Throughout 2022, we have taken a number of strategic steps to better position the Company to increase cash flows and our operating scale in our core basins to create a stronger, better capitalized company that can accretively grow cash flows and volumes, while being a high-quality midstream operator and an industry leader in ESG efforts.
In 2022, we successfully executed on our long-term growth strategy through disciplined capital investments utilizing our current financial flexibility. On February 1, 2022, we acquired Oasis Midstream in an equity and cash transaction valued at
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approximately $1.8 billion. Pursuant to 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 the general partner of Oasis Midstream. This transaction further solidifies Crestwood’s competitive position in the Williston Basin and expands the Company’s relationship with Chord. Additionally, the Rough Rider system acquired in the merger with Oasis Midstream is complementary with our Arrow system, which has provided and continues to provide opportunities to drive cost savings and commercial synergies and better utilization of available gas processing capacity.
During 2022, we also completed a series of strategic transactions including (i) the acquisition of Sendero for approximately $631 million, (ii) the acquisition of First Reserve’s 50% equity interest in Crestwood Permian in exchange for approximately $6 million in cash and approximately 11.3 million newly issued CEQP common units, and (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 Crestwood Permian joint venture have significantly increased the Company’s position in the 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 customers to maintain volumes across our asset portfolio; (iv) optimize our storage, transportation and marketing assets to take advantage of regional commodity price volatility; and (v) evaluate our debt and equity structure to preserve liquidity and ensure balance sheet strength. Given our efforts over the past few years to improve the Partnership’s competitive position in the businesses 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 injunctionagainst 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 January 2022, we published our first carbon management plan (CMP), which outlines near-term emissions reduction and management activities that we intend to implement over the next three years. The CMP includes several core objectives, including (i) reducing emissions intensity of our assets; (ii) evaluating opportunities to reduce Scope 2 greenhouse gas (GHG) emissions while managing our operations’ energy efficiency; (iii) enhancing our process by which we manage GHG emissions; (iv) piloting methane emission monitoring devices at certain of our facilities; (v) participating in the development of responsibly
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sourced gas standards for the midstream sector; (vi) investing in technology to better inventory and calculate emissions data and integrating the technology into our operations; and (vii) participating in and providing leadership to trade associations focused on climate-related risks. We have made progress on several of the key objectives of our CMP in 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 have included a methane intensity target of 0.040% in our executives’ and employees’ short-term incentive compensation program for 2023.
We currently believe that our carbon management efforts will help to mitigate the potential impact that emissions may have on our capital expenditures or results of operations in the future.
Critical Accounting Estimates and Policies
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.
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. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our reporting units (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our customers, such as their future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates. If the assumptions embodied in the projections prove inaccurate, we could incur a future impairment charge. In addition, the use of the income approach to determine the fair value of our reporting units (see further discussion of the use of the income approach below) could result in a different fair value if we had utilized a market approach, or a combination thereof.
Upon acquisition, we are required to record the assets, liabilities and goodwill of a reporting unit at its fair value on the date of acquisition. As a result, any level of decrease in the forecasted cash flows of these businesses or increases in the discount rates utilized to value those businesses from their respective acquisition dates would likely result in the fair value of the reporting unit falling below the carrying value of the reporting unit, and could result in an assessment of whether that reporting unit’s goodwill is impaired.
At December 31, 2022, our goodwill consisted of approximately $94.7 million associated with our gathering and processing north Williston reporting unit, $35.6 million associated with our gathering and processing south Permian reporting unit and $92.7 million associated with our storage and logistics NGL Marketing and Logistics reporting unit. We continue to monitor
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our goodwill, and we could experience impairments of 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 operations with goodwill, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value of those businesses. A 5% decrease in the forecasted cash flows or a 1% increase in the discount rates utilized to determine the fair value of each of our reporting units would not have resulted in a goodwill impairment at 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 business combinations and property, plant and equipment that has been constructed in recent years. The initial recording of a majority of these long-lived assets was at fair value, which is estimated by management primarily utilizing market-related information, asset specific information and other projections on the performance of the assets acquired (including an analysis of discounted cash flows which can involve assumptions on discount rates and projected cash flows of the assets acquired). Management reviews this information to determine its reasonableness in comparison to the assumptions utilized in determining the purchase price of the assets in addition to other market-based information that was received through the purchase process and other sources. These projections also include projections on potential and contractual obligations assumed in these acquisitions. Due to the imprecise nature of the projections and assumptions utilized in determining fair value, actual results can, and often do, differ from our estimates.
We utilize assumptions related to the useful lives and related salvage value of our property, plant and equipment in order to determine depreciation and amortization expense each period. Due to the imprecise nature of the projections and assumptions utilized in determining useful lives, actual results can, and often do, differ from our estimates.
To estimate the useful life of our finite lived intangible assets we utilize assumptions of the period over which the assets are expected to contribute directly or indirectly to our future cash flows. Generally this requires us to amortize our intangible assets based on the expected future cash flows (to the extent they are readily determinable) or on a straight-line basis (if they are not readily determinable) of the acquired contracts or customer relationships. Due to the imprecise nature of the projections and assumptions utilized in determining future cash flows, actual results can, and often do, differ from our estimates.
We continually monitor our business, the business environment and the performance of our operations to determine if an event has occurred that indicates that a long-lived asset may be impaired. If an event occurs, which is a determination that involves judgment, we may be required to utilize cash flow projections to assess our ability to recover the carrying value of our assets based on our long-lived assets’ ability to generate future cash flows on an undiscounted basis. This differs from our evaluation of goodwill, for which we perform an assessment of the recoverability of goodwill utilizing fair value estimates that primarily utilize discounted cash flows in the estimation process (as described above), and accordingly a reporting unit that has experienced a goodwill impairment may not experience a similar impairment of the underlying long-lived assets included in that reporting unit.
Projected cash flows of our long-lived assets are generally based on current and anticipated future market conditions, which require significant judgment to make projections and assumptions about pricing, demand, competition, operating costs, construction costs, legal and regulatory issues and other factors that may extend many years into the future and are often outside of our control. If those cash flow projections indicate that the long-lived asset’s carrying value is not recoverable, we record an impairment charge for the excess of the carrying value of the asset over its fair value. The estimate of fair value considers a number of factors, including the potential value we would receive if we sold the asset, discount rates and projected cash flows. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.
During 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 negative information about market conditions or the intent of our long-lived assets’ customers, which could negatively impact the forecasted cash flows or discount rates utilized to determine the fair value of those investments.
Equity Method Investments
We evaluate our equity method investments for impairment when events or circumstances indicate that the carrying value of the equity method investment may be impaired and that impairment is other than temporary. If an event occurs, we evaluate the recoverability of our carrying value based on the fair value of the investment. If an impairment is indicated, we adjust the carrying values of the investment downward, if necessary, to their estimated fair values.
We estimate the fair value of our equity method investments based on a number of factors, including discount rates, projected cash flows, enterprise value and the potential value we would receive if we sold the equity method investment. Estimating projected cash flows requires us to make certain assumptions as it relates to the future operating performance of each of our equity method investments (which includes assumptions, among others, about estimating future operating margins and related future growth in those margins, contracting efforts and the cost and timing of facility expansions) and assumptions related to our equity method investments’ customers, such as their future capital and operating plans and their financial condition. When considering operating performance, various factors are considered such as current and changing economic conditions and the commodity price environment, among others. Due to the imprecise nature of these projections and assumptions, actual results can and often do, differ from our estimates.
We continue to monitor our equity method investments, and if we receive negative information about market conditions or the intent of our equity method investments’ customers to curtail production in the future that negatively impacts the forecasted cash flows or discount rates utilized to determine the fair value of those investments, we could experience impairments to the carrying value of these investments.
Our equity method investments have long-lived assets in their underlying financial statements, and our equity investees apply similar accounting policies and have similar critical accounting estimates in assessing those assets for impairment as we do. During 2021, we recorded a $158.7 million reduction to the equity earnings from our Stagecoach Gas equity method investment primarily as a result of the sale (through a series of transactions) of Stagecoach Gas to a subsidiary of Kinder Morgan. For a further discussion of the Stagecoach Gas divestiture, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6. During 2020, we recorded a $4.5 million reduction to the equity earnings from our PRBIC equity method investment as a result of us recording our proportionate share of a long-lived asset impairment recorded by the equity method investee.
Revenue Recognition
We recognize revenues for services and products under our revenue contracts as our obligations to perform services or deliver/sell products under the contracts are satisfied. A contract’s transaction price is allocated to each performance obligation in the contract and recognized as revenue when, or as, the performance obligation is satisfied. Under certain contracts, we may be entitled to receive payments in advance of satisfying our performance obligations under the contract. We recognize a liability for these payments in excess of revenue recognized and present this deferred revenue as contract liabilities on our 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 impairments on long-lived assets, impairments of goodwill, third party costs incurred related to potential and completed acquisitions, certain environmental remediation costs, the change in fair value of commodity inventory-related derivative contracts, costs associated with the realignment and restructuring of our operations and corporate structure, and other transactions identified in a specific reporting period. The change in fair value of commodity inventory-related derivative contracts is considered in determining Adjusted EBITDA given that the timing of recognizing gains and losses on these derivative contracts differs from the recognition of revenue for the related underlying sale of inventory to which these derivatives relate. Changes in the fair value of other derivative contracts are 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,
Revenues
Costs of product/services sold
Operations and maintenance expense
General and administrative expense
Depreciation, amortization and accretion
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
Operating income
Earnings (loss) from unconsolidated affiliates, net
Interest and debt expense, net
Gain (loss) on modification/extinguishment of debt
Other income (expense), net
Provision for income taxes
Net income (loss)
Add:
Interest and debt expense, net
(Gain) loss on modification/extinguishment of debt
Provision for income taxes
Depreciation, amortization and accretion
EBITDA
Unit-based compensation charges
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
(Earnings) loss from unconsolidated affiliates, net
Adjusted EBITDA from unconsolidated affiliates, net
Change in fair value of commodity inventory-related derivative contracts
Significant transaction and environmental related costs and other items
Adjusted EBITDA
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Crestwood Equity
Crestwood Midstream
Year Ended December 31,
Year Ended December 31,
Net cash provided by operating activities
Net changes in operating assets and liabilities
Amortization of debt-related deferred costs
Interest and debt expense, net
Unit-based compensation charges
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
Earnings (loss) from unconsolidated affiliates, net, adjusted for cash distributions received
Deferred income taxes
Provision for income taxes
Other non-cash income (expense)
EBITDA
Unit-based compensation charges
Loss on long-lived assets, net
Goodwill impairment
Gain on acquisition
(Earnings) loss from unconsolidated affiliates, net
Adjusted EBITDA from unconsolidated affiliates, net
Change in fair value of commodity inventory-related derivative contracts
Significant transaction and environmental related costs and other items
Adjusted EBITDA
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Segment Results
The following tables summarize the EBITDA of our segments ( in millions ):
Gathering and Processing North
Gathering and Processing South
Storage and Logistics
Revenues
Intersegment revenues
Costs of product/services sold
Operations and maintenance expense
Loss on long-lived assets, net
Gain on acquisition
Earnings from unconsolidated affiliates, net
Crestwood Midstream EBITDA for the year ended December 31, 2022
Gain on long-lived assets (1)
Crestwood Equity EBITDA for the year ended December 31, 2022
Revenues
Intersegment revenues
Costs of product/services sold
Operations and maintenance expense
Gain (loss) on long-lived assets, net
Earnings (loss) from unconsolidated affiliates, net
EBITDA for the year ended December 31, 2021
Revenues
Intersegment revenues
Costs of product/services sold
Operations and maintenance expense
Loss on long-lived assets, net
Goodwill impairment
Earnings (loss) from unconsolidated affiliates, net
EBITDA for the year ended December 31, 2020
(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.
Below is a discussion of the factors that impacted EBITDA by segment for the year ended December 31, 2022 compared to the year ended December 31, 2021.
Gathering and Processing North
EBITDA for our gathering and processing north segment increased by approximately $153.9 million during the year ended December 31, 2022 compared to 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, 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 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 $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, 2021 was impacted by a reduction to 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, 2022 compared to 2021, and our costs of product/services sold increased by approximately $459.2 million during 2022 compared to 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 $160.1 million during the year ended December 31, 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 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 resulted in costs of product/services sold increasing more than revenues during the year ended December 31, 2022 compared to 2021. Our NGL marketing and logistics operations’ costs of product/services sold was also impacted by the effect of increasing commodity prices on our 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 costs of product/services sold was a gain of $9.4 million during the year ended December 31, 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 2021, and an increase in product costs of approximately $298.3 million during 2022 compared to 2021. These increases were primarily driven by higher crude oil purchases and 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 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 lower basis differentials in 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 5. During the year ended December 31, 2022, earnings from our Tres Holdings equity investment decreased by $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, 2021.
Other Items Affecting EBITDA Results
General and Administrative Expenses. During the year ended December 31, 2022, our general and administrative expenses increased compared to 2021, primarily due to transaction costs incurred in connection with our strategic transactions executed during 2022 as further discussed in Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.
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Items not affecting EBITDA include the following:
Depreciation, Amortization and Accretion Expense. During the year ended December 31, 2022, our depreciation, amortization and accretion expense increased compared to 2021, primarily due to our acquisitions during 2022, partially offset by the divestitures of our operations in the Barnett and Marcellus Shales during 2022. For a further discussion of these transactions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3.
Interest and Debt Expense, Net. During the year ended December 31, 2022, our interest and debt expense, net increased primarily due to 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 interest and debt expense increased 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, 2022 compared to 2021. These increases in borrowings were partially offset by the proceeds received from the sale of our Barnett and Marcellus assets during 2022. For a further discussion of the long-term debt assumed in conjunction with our acquisitions during 2022, 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 ):
Year Ended December 31,
Credit facilities
Senior notes
Other, net
Gross interest and debt expense
Less: capitalized interest
Interest and debt expense, net
Loss on Extinguishment of Debt. During the year ended December 31, 2021, we recognized a loss on extinguishment of debt of approximately $7.5 million primarily due to the redemption of our 2023 Senior Notes and the amendment of the Crestwood Midstream credit facility in December 2021.
Liquidity and Sources of Capital
Crestwood Equity is a holding company that derives all of its operating cash flow from its operating subsidiaries. Our principal sources of liquidity include cash generated by operating activities from our subsidiaries, distributions from our joint ventures, borrowings under our credit facilities, and sales of equity and debt securities. Our equity investments use cash from their respective operations and contributions from us to fund their operating activities and maintenance and growth capital expenditures. We believe our liquidity sources and operating cash flows are sufficient to address our future operating, debt service and capital requirements.
We make quarterly cash distributions to our common unitholders within approximately 45 days after the end of each fiscal quarter in an aggregate amount equal to our available cash for such quarter. We also pay quarterly cash distributions of approximately $15 million to our preferred unitholders and quarterly cash distributions of approximately $10 million to Crestwood Niobrara’s non-controlling partner. The $434 million of preferred securities issued to Crestwood Niobrara’s non-controlling partner are redeemable by the non-controlling partner beginning in January 2024, and we believe we have adequate borrowing capacity under the Crestwood Midstream credit facility along with adequate other potential sources of capital to fund any such potential redemption.
On January 19, 2023, we declared a quarterly cash distribution of $0.655 per unit to our common unitholders with respect to the fourth quarter of 2022, which was paid on February 14, 2023. Our Board of Directors evaluates the level of distributions to our common and preferred unitholders every quarter and considers a wide range of strategic, commercial, operational and financial factors, including current and projected operating cash flows. We believe our operating cash flows will exceed cash distributions to our partners, preferred unitholders and non-controlling partner, and as a result, we will have adequate operating cash flows as a source of liquidity for our growth capital expenditures.
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The Crestwood Midstream credit agreement provides for a five-year $1.75 billion revolving credit facility that is available to fund acquisitions, working capital and internal growth projects and for general partnership purposes and allows Crestwood Midstream to increase its available borrowings under the facility by $100 million, subject to lender approval and the satisfaction of certain other conditions, as described in the credit agreement. As of December 31, 2022, we had $819.5 million of available capacity under the Crestwood Midstream credit facility, considering the most restrictive debt covenants in the credit agreement. As of December 31, 2022, we were in compliance with all of our debt covenants applicable to our credit facilities and our senior notes. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 9 for a more detailed description of the covenants related to our credit facilities and senior notes.
We may from time to time seek to retire or purchase our outstanding debt through cash purchases and/or exchanges for equity securities, in open market purchases, privately negotiated transactions, tender offers or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material. In January 2023, Crestwood Midstream issued $600 million of 7.375% unsecured senior notes due 2031 (the 2031 Senior Notes). We used the proceeds from the issuance of the 2031 Senior Notes to repay borrowings under the Crestwood Midstream credit facility and to repay all outstanding borrowings under the Crestwood Permian credit facility, which was terminated in January 2023. On February 20, 2023, we and Brookfield entered into an agreement with a third party to sell each of our respective interests in Tres Holdings for approximately $335 million. We intend to use our 50% share of the net proceeds to reduce borrowings under the Crestwood Midstream credit facility. The transaction is expected to close in the second quarter of 2023, subject to customary closing conditions.
Cash Flows
The following table provides a summary of Crestwood Equity’s cash flows by category ( in millions ):
Year Ended December 31,
Net cash provided by operating activities
Net cash provided by (used in) investing activities
Net cash used in financing activities
Operating Activities
Our cash flows from operating activities increased by approximately $12.5 million during the year ended December 31, 2022 compared to 2021. The net increase was primarily driven by the operations acquired in the Oasis Merger, the Sendero Acquisition and the CPJV Acquisition, which are described in Results of Operations above. This net increase was partially offset by a reduction in operation cash flows from the operations divested during the Barnett and Marcellus divestitures during 2022, which are discussed above in Results of Operations .
Investing Activities
Capital Expenditures . The energy midstream business is capital intensive, requiring significant investments for the acquisition or development of new facilities. We categorize our capital expenditures as either:
• growth capital expenditures, which are made to construct additional assets, expand and upgrade existing systems, or acquire additional assets; or
• maintenance capital expenditures, which are made to replace partially or fully depreciated assets, to maintain the existing operating capacity of our assets, extend their useful lives or comply with regulatory requirements.
During 2023, we anticipate growth capital expenditures of approximately $135 million to $155 million, maintenance capital expenditures of approximately $25 million to $30 million, and approximately $10 million to $20 million on capital expenditures that are directly reimbursable by our customers. We anticipate that our growth and reimbursable capital expenditures in 2023 will increase the services we can provide to our customers and the operating efficiencies of our systems. We expect to finance our capital expenditures with a combination of cash generated by our operating subsidiaries, distributions received from our equity investments and borrowings under our credit facility. Additional commitments or expenditures will be made at our discretion, and any discontinuation of the construction of these projects could result in less future operating cash flows and earnings.
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The following table summarizes our capital expenditures for the year ended December 31, 2022 ( in millions ):
Growth capital (1)
Maintenance capital
Other (2)
Purchases of property, plant and equipment
(1) Includes $3.2 million paid related to outstanding litigation on the construction of the Bear Den II cryogenic processing plant.
(2) Represents purchases of property, plant and equipment that are reimbursable by third parties.
Acquisitions and Divestitures . Below is a summary of the acquisition and divestiture activities that impacted our investing activities during the years ended December 31, 2022 and 2021. For a further discussion of these transactions, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 3, Note 6 and Note 11.
• Oasis Merger . In February 2022, we acquired Oasis Midstream, which included cash consideration of $160 million, net of cash acquired of approximately $14.9 million.
• Sendero Acquisition . In July 2022, we acquired Sendero for cash consideration of approximately $631.2 million, net of cash acquired of approximately $28.5 million.
• CPJV Acquisition . In July 2022, we acquired First Reserve’s 50% equity interest in Crestwood Permian, which included cash consideration of approximately $5.9 million, net of acquired cash of approximately $149.4 million.
• Crude Oil Railcars Sale . In April 2022, we sold our crude oil railcars for approximately $24.7 million primarily as a result of the exit of our crude railcar operations.
• Barnett Divestiture . In July 2022, we sold our assets in the Barnett Shale for approximately $290 million, including working capital adjustments.
• Marcellus Divestiture . In October 2022, we sold our assets in the Marcellus Shale for approximately $206 million.
• Stagecoach Gas Divestiture . In conjunction with the second closing, in November 2021, we sold our remaining Stagecoach Gas equity investment for approximately $15 million.
Investments in/Capital Distributions from Unconsolidated Affiliates . Pursuant to our joint venture agreements with our respective equity investments, we periodically make contributions to our equity investments to fund their expansion projects and for other operating purposes. During the years ended December 31, 2022 and 2021, we contributed approximately $90.9 million and $17.6 million to our equity investments.
During the year ended December 31, 2021, we received a distribution from Stagecoach Gas of approximately $614 million, which represented our proportionate share of the gross proceeds received by Stagecoach Gas related to the first closing of its sale of certain of its assets. For further discussion of this distribution, see Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 6.
Financing Activities
The following equity and debt transactions impacted our financing activities during the year ended December 31, 2022 compared to 2021.
Equity and Debt Transactions
• During the year ended December 31, 2022, CEQP acquired 4.6 million CEQP common units from OMS Holdings LLC, a subsidiary of Chord, for approximately $123.7 million;
• During the year ended December 31, 2022, distributions to our partners increased by approximately $100.9 million compared to 2021, primarily due to an increase in common units outstanding as a result of the units issued in conjunction with the Oasis Merger and the CPJV Acquisition, as well as an increase in our distribution per limited partner unit from $0.625 per unit to $0.655 per unit;
• During the year ended December 31, 2022, our taxes paid for unit-based compensation vesting increased by approximately $7.5 million compared to 2021, primarily due to higher vesting of unit-based compensation awards;
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• During the year ended December 31, 2022, our payments for finance leases increased by approximately $29.2 million primarily due to an option we exercised under our leases to purchase crude oil rail cars;
• During the year ended December 31, 2022, we borrowed amounts under the Crestwood Midstream credit facility to (i) fund cash consideration of approximately $631.2 million to acquire Sendero; (ii) fund approximately $5.9 million of cash consideration to acquire the remaining 50% equity interest in Crestwood Permian; (iii) fund $160.0 million of cash consideration paid in conjunction with the Oasis Merger; and (iv) repay approximately $218.4 million outstanding under the credit facility acquired in conjunction with the Oasis Merger;
• During the year ended December 31, 2021, we paid approximately $690.5 million to repurchase and cancel approximately $687.2 million of senior notes that were due in 2023;
• During the year ended December 31, 2021, we received net proceeds of approximately $691 million from the issuance of senior notes due February 2029; and
• During the year ended December 31, 2022, our other debt-related transactions resulted in net repayments under our credit facilities of approximately $435.8 million compared to net repayments of approximately $446.4 million during 2021.
Guarantor Summarized Financial Information
Crestwood Midstream and Crestwood Midstream Finance Corp. are issuers of our debt securities (the Issuers). Crestwood Midstream is a holding company and owns no operating assets and has no significant operations independent of its subsidiaries. Crestwood Midstream Finance Corp. is Crestwood Midstream’s 100% owned subsidiary and has no material assets or operations other than those related to its service as co-issuer of our senior notes. Obligations under Crestwood Midstream’s senior notes and its credit facility are jointly and severally guaranteed by substantially all of its subsidiaries (collectively, the Guarantor Subsidiaries), except for Crestwood Infrastructure Holdings LLC, Crestwood Niobrara LLC, Crestwood Pipeline and Storage Northeast LLC, Powder River Basin Industrial Complex LLC, and Tres Palacios Holdings LLC and their respective subsidiaries (collectively, Non-Guarantor Subsidiaries). The assets and credit of our Non-Guarantor Subsidiaries are not available to satisfy the debts of the Issuers or Guarantor Subsidiaries, and the liabilities of our Non-Guarantor Subsidiaries do not constitute obligations of the Issuers or Guarantor Subsidiaries. In January 2023, Crestwood Permian and certain of its subsidiaries were designated as Guarantor Subsidiaries of Crestwood Midstream’s senior notes and its credit facility. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 9 for additional information regarding the Crestwood Midstream credit facility and senior notes and related guarantees.
The following tables provide summarized financial information for the Issuers and Guarantor Subsidiaries (collectively, the Obligor Group) on a combined basis after elimination of significant intercompany balances and transactions between entities in the Obligor Group. The investment balances in the Non-Guarantor Subsidiaries have been excluded from the supplemental summarized combined financial information. Transactions with other related parties, including the Non-Guarantor Subsidiaries, represent affiliate transactions and are presented separately in the summarized combined financial information below.
Summarized Combined Balance Sheet Information (in millions)
December 31, 2022
Current assets
Current assets - affiliates
Property, plant and equipment, net
Non-current assets
Current liabilities
Current liabilities - affiliates
Long-term debt, less current portion
Non-current liabilities
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Summarized Combined Income Statement Information (in millions)
Year Ended December 31, 2022
Revenues
Revenues - affiliates
Cost of products/services sold
Cost of products/services sold - affiliates
Operations and maintenance expenses (1)
General and administrative expenses (2)
Operating income
Net income
(1) We have operating agreements with certain of our affiliates pursuant to which we charge them operations and maintenance expenses in accordance with their respective agreements, and these charges are reflected as a reduction of operations and maintenance expenses in our consolidated statements of operations. During the year ended December 31, 2022, we charged $27.5 million to our affiliates under these agreements. See Part IV, Item 15. Exhibits, Financial Statement Schedules, Note 19 for a further description of our related party operating agreements.
(2) Includes $32.8 million of net general and administrative expenses that were charged by our affiliates to us.
