GEL US Equity☆

Item 1A. Risk Factors

The following risk factors and other information included in this Annual Report on Form 10-K should be carefully considered. The occurrence of any of the following risks or of unknown risks and uncertainties may adversely affect our business, operating results and financial condition.

Risk Factors Summary

Risks Related to the Operations of Our Business

•We may not be able to fully execute our growth strategy due to various factors, such as unreceptive capital markets and/or excessive competition for acquisitions.

•We may not have sufficient cash from operations to pay the current level of quarterly distributions following the establishment of cash reserves and payment of fees and expenses.

•Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current commodity (crude oil, natural gas, refined products, soda ash, NaHS and caustic soda) volumes, which often depend on actions and commitments by parties beyond our control.

•Many of our crude oil and natural gas transportation customers are producers whose drilling activity levels and spending for transportation have historically been, and may continue to be, impacted by volatility in the commodity markets.

•Fluctuations in prices for crude oil, refined petroleum products, NaHS, soda ash and caustic soda could adversely affect our business.

Risks Related to Liquidity and Financing

•Our indebtedness could adversely restrict our ability to operate, affect our financial condition, prevent us from complying with requirements under our debt instruments and prevent us from paying cash distributions to our unitholders.

•We may not be able to access adequate capital (debt and/or equity) on economically viable terms, or any terms.

Risks Related to Legal and Regulatory Compliance

•Our operations are subject to federal, state and local environmental protection and safety laws and regulations.

•Climate change legislation and regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs.

•Changes in environmental laws could increase costs and harm our business, financial condition and results of operations.

Risks Related to Our Partnership Structure

•Individual members of the Davison family can exert significant influence over us and may have conflicts of interest with us and may be permitted to favor their interests to the detriment of our other unitholders.

•Our Class B Common Units may be transferred to a third party without unitholder consent, which could affect our strategic direction.

•The interruption of distributions to us from our subsidiaries and joint ventures could affect our ability to make payments on indebtedness or cash distributions to our unitholders.

•We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Tax Risks to Our Unitholders

•Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the Internal Revenue Service, or IRS, were to treat us as a corporation (for U.S. federal income tax purposes) or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our unitholders could be substantially reduced.

•Our unitholders will be required to pay taxes on income (as well as deemed distributions, if any) from us even if they do not receive any cash distributions from us.

•Our unitholders will likely be subject to state and local taxes in states where they do not live as a result of an investment in our units.

32

Table of Contents

General Risks

•We are exposed to the credit risk of our customers in the ordinary course of our business activities.

•A natural disaster, pandemic, epidemic, accident, terrorist attack or other interruption event could result in an economic slowdown, severe personal injury, property damage and/or environmental damage, which could curtail our operations or otherwise adversely affect our assets and cash flow.

•Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions. Compliance with and changes in cyber security requirements have a cost impact on our business.

•Our significant unitholders may sell units or other limited partner interests in the trading market, which could reduce the market price of our common units.

•We may issue additional common units without unitholders’ approval, which would dilute their ownership interests.

Risks Related to the Operations of Our Business

We may not be able to fully execute our growth strategy due to various factors, such as unreceptive capital markets and/or excessive competition for acquisitions.

Our strategy contemplates substantial growth through the development and acquisition of a wide range of midstream and other infrastructure and mining assets while maintaining a strong balance sheet. This strategy includes constructing and acquiring additional assets and businesses to enhance our ability to compete effectively, diversify our asset portfolio and, thereby, provide more stable cash flow. We regularly consider and enter into discussions regarding, and are currently contemplating, additional potential joint ventures, stand-alone projects and other transactions that we believe will present opportunities to realize synergies, expand our role in the infrastructure and mining businesses, and increase our market position and, ultimately, increase distributions to unitholders. A number of factors could adversely affect our ability to execute our growth strategy, including an inability to raise adequate capital on acceptable terms, competition from competitors and/or an inability to successfully integrate one or more acquired businesses into our operations.

We will need new capital to finance the future development and acquisition of assets and businesses. Limitations on our access to capital will impair our ability to execute this strategy. Expensive capital will limit our ability to develop or acquire accretive assets. Although we intend to continue to expand our business, this strategy may require substantial capital, and we may not be able to raise the necessary funds on satisfactory terms, if at all.

In addition, we experience competition for the assets we purchase or contemplate purchasing. Increased competition for a limited pool of assets could result in our not being the successful bidder more often or our acquiring assets at a higher relative price than that which we have paid historically. Either occurrence would limit our ability to fully execute our growth strategy. Our ability to execute our growth strategy may impact the market price of our securities.

We may be unable to integrate successfully businesses we acquire. We may incur substantial expenses, delays or other problems in connection with our growth strategy that could negatively impact our results of operations. Moreover, acquisitions and business expansions involve numerous risks, including: difficulties in the assimilation of the operations, technologies, services and products of the acquired companies or business segments; inefficiencies and complexities that can arise because of unfamiliarity with new assets and the businesses associated with them, including unfamiliarity with their markets; and diversion of the attention of management and other personnel from day-to-day business to the development or acquisition of new businesses and other business opportunities.

We may not have sufficient cash from operations to pay the current level of quarterly distributions following the establishment of cash reserves and payment of fees and expenses.

The amount of cash we distribute on our common and Class A Convertible Preferred Units principally depends upon margins we generate from our businesses, which fluctuate from quarter to quarter based on, among other things: the volumes and prices at which we purchase and sell crude oil, natural gas, refined products and caustic soda; the volumes of sodium hydrosulfide, or NaHS, and soda ash that we receive for our sodium minerals and sulfur services and the prices at which we sell NaHS and soda ash; the demand for our services; the level of competition; the level of our operating costs; the effect of worldwide energy conservation measures; governmental regulations and taxes; the level of our general and administrative costs; and prevailing economic conditions.

In addition, the actual amount of cash we will have available for distribution will depend on other factors that include: the level of capital expenditures we make, including the cost of acquisitions (if any); our debt service requirements; fluctuations in our working capital; restrictions on distributions contained in our debt instruments or organizational documents governing our joint ventures and unrestricted subsidiaries; our ability to borrow under our working capital facility to pay distributions; and the amount of cash reserves required in the conduct of our business.

33

Table of Contents

Our ability to pay distributions each quarter depends primarily on our cash flow, including cash flow from financial reserves and working capital borrowings, and our cash requirements, so it is not solely a function of profitability, which will be affected by non-cash items. As a result, we may make cash distributions during periods when we record losses and we may not make distributions during periods when we record net income.

Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current commodity (crude oil, natural gas, refined products, soda ash, NaHS and caustic soda) volumes, which often depend on actions and commitments by parties beyond our control.

Our profitability and cash flow are dependent on our ability to increase or, at a minimum, maintain our current commodity (crude oil, natural gas, refined products, soda ash, NaHS, and caustic soda) volumes. We access commodity volumes through various sources, such as our mines, producers, service providers (including gatherers, shippers, marketers and other aggregators) and refiners. Depending on the needs of each customer and the market in which it operates, we can provide a service for a fee (as in the case of our pipeline, marine vessel and railcar transportation operations), we can acquire the commodity from our customer and resell it to another party, or, in the case of soda ash, we can produce the commodity ourselves.

Our source of volumes depends on successful exploration and development of additional crude oil and natural gas reserves by others; our successful development of our trona reserves, continued demand for refining and our related sulfur removal and other services, for which we are paid in NaHS; the breadth and depth of our logistics operations; the extent that third parties provide NaHS for resale; and other matters beyond our control.

The crude oil, natural gas and refined products available to us and our refinery customers are derived from reserves produced from existing wells, and these reserves naturally decline over time. In order to offset this natural decline, our energy infrastructure assets must access additional reserves. Additionally, some of the projects we have planned or recently completed are dependent on reserves that we expect to be produced from newly discovered properties that producers are currently developing.

Finding and developing new reserves is very expensive, requiring large capital expenditures by producers for exploration and development drilling, installing production facilities and constructing pipeline extensions to reach new wells. Many economic and business factors out of our control can adversely affect the decision by any producer to explore for and develop new reserves. These factors include the prevailing market price of the commodity, the capital budgets of producers, the depletion rate of existing reservoirs, the success of new wells drilled, environmental concerns, regulatory initiatives, cost and availability of equipment, capital budget limitations or the lack of available capital and other matters beyond our control. Additional reserves, if discovered, may not be developed in the near future or at all. The volatility in crude oil and natural gas prices has forced some producers to significantly defer or curtail their planned capital expenditures. Thus, crude oil and natural gas production in our market areas could decline, which could have a material negative impact on our revenues and prospects.

Demand for our services is dependent on the demand for crude oil and natural gas. Any decrease in demand for crude oil or natural gas, including by those refineries or connecting carriers to which we deliver could adversely affect our cash flows. The demand for crude oil also is dependent on the competition from refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements or alternative fuel sources such as electricity, coal, fuel oils or nuclear energy, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services. A reduction in demand for our services in the markets we serve could result in impairments of our assets and have a material adverse effect on our business, financial condition and results of operations.

Our ability to access NaHS depends primarily on the demand for our proprietary sulfur removal process. Demand for our services could be adversely affected by many factors, including lower refinery utilization rates, U.S. refineries accessing more “sweet” (instead of “sour”) crude and the development of alternative sulfur removal processes that might be more economically beneficial to refiners.

We are dependent on third parties for NaOH for use in our sulfur removal process as well as volume to market to third parties. Should regulatory requirements or operational difficulties disrupt the manufacture of caustic soda by these producers, we could be affected.

Our sulfur removal operations are dependent upon the supply of caustic soda, the demand for NaHS and the continuing operations of the refiners for whom we process sour natural gas.

Caustic soda is a major component of the proprietary sulfur removal process we provide to our refinery customers. Because we are a large consumer of caustic soda, we can leverage our economies of scale and logistics capabilities to effectively market caustic soda to third parties. NaHS, the resulting by-product from our sulfur removal operations, is a vital ingredient in a number of industrial and consumer products and processes. Any decrease in the supply of caustic soda could affect our ability to provide sulfur removal services to refiners and any decrease in the demand for NaHS by the parties to whom we sell the NaHS could adversely affect our business. Refineries’ need for our sulfur removal services is also dependent

34

Table of Contents

on refining competition from other refineries by refiners to process more “sweet” (instead of “sour”) crude, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services.

Our crude oil and natural gas transportation operations are dependent upon demand for crude oil by refiners, primarily in the Midwest and Gulf Coast, and the demand for natural gas.

Any decrease in this demand for crude oil by those refineries or connecting carriers to which, or for the natural gas, we deliver could adversely affect our cash flows. Those refineries’ demand for crude oil also is dependent on the competition from other refineries, the impact of future economic conditions, fuel conservation measures, alternative fuel requirements, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services. The demand for natural gas is dependent on the impact of future economic conditions, fuel conservation measures, alternative fuel requirements and alternative fuel sources such as electricity, coal, fuel oils or nuclear energy, government regulation or technological advances in fuel economy and energy generation devices, all of which could reduce demand for our services.

We face intense competition to obtain crude oil, natural gas and refined products volumes.

Our competitors-gatherers, transporters, marketers, brokers and other aggregators-include integrated, large and small independent energy companies, as well as their marketing affiliates, who vary widely in size, financial resources and experience. Some of these competitors have capital resources many times greater than ours and control substantially greater supplies of crude oil, natural gas and refined products.

Even if reserves exist or refined products are produced in the areas accessed by our facilities, we may not be chosen by the refiners or producers to gather, refine, market, transport, store or otherwise handle any of these crude oil and natural gas reserves, NaHS, caustic soda, soda ash or other refined products. We compete with others for any such volumes on the basis of many factors, including: geographic proximity to the production and/or refineries; costs of connection; available capacity; rates; logistical efficiency in all of our operations; operational efficiency in our sulfur removal business; customer relationships; and access to markets.

Additionally, on our onshore pipelines most of our third-party shippers do not have long-term contractual commitments to ship crude oil on our pipelines. A decision by a shipper to substantially reduce or cease to ship volumes of crude oil on our pipelines could cause a significant decline in our revenues. In Mississippi, we are dependent on interconnections with other pipelines to provide shippers with a market for their crude oil, and in Texas, we are dependent on interconnections with other pipelines to provide shippers with transportation to our pipeline. Any reduction of throughput available to our shippers on these interconnecting pipelines as a result of testing, pipeline repair, reduced operating pressures or other causes could result in reduced throughput on our pipelines that would adversely affect our cash flows and results of operations.

Fluctuations in demand for crude oil or natural gas or availability of refined products or NaHS, such as those caused by refinery downtime or shutdowns, can negatively affect our operating results. Reduced demand in areas we service with our pipelines, marine vessels, rail facilities and trucks can result in less demand for our transportation services.

Many of our crude oil and natural gas transportation customers are producers whose drilling activity levels and spending for transportation have historically been, and may continue to be, impacted by volatility in the commodity markets.

Many of our customers finance their drilling activities through cash flow from operations, the incurrence of debt or the issuance of equity. Extreme volatility in commodity prices has caused many of our customers’ equity value to substantially decline. New credit facilities and other debt financing from institutional sources have generally become more difficult and expensive to obtain, and there may be a general reduction in the amount of credit available in the markets in which we conduct business. For example, prices for crude oil declined precipitously starting in the second half of 2014 from over $100 per barrel in June 2014 to approximately $30 per barrel in early 2016. Over the last two years, average monthly prices for crude oil ranged from a high of over $80 per barrel to a low of less than $20 per barrel, and such extreme volatility may continue going forward. Adverse price changes put downward pressure on drilling budgets for crude oil and natural gas producers, which have resulted, and could continue to result, in lower volumes than we otherwise would have seen being transported on our pipeline and transportation systems, which could have a material negative impact on our revenues and prospects.

Fluctuations in prices for crude oil, refined petroleum products, NaHS, soda ash and caustic soda could adversely affect our business.

Because we purchase (or otherwise acquire) and sell crude oil, refined petroleum products, NaHS soda ash and caustic soda we are exposed to some direct commodity price risks. Prices for those commodities can fluctuate in response to changes in supply, market uncertainty and a variety of additional factors that are beyond our control, which could have an adverse effect on our cash flows, profit and/or Segment Margin. We attempt to limit those commodity price risks through back-to-back

35

Table of Contents

purchases and sales, hedges and other contractual arrangements; however, we cannot completely eliminate our commodity price risk exposure.

Our use of derivative financial instruments could result in financial losses.

We use derivative financial instruments and other hedging mechanisms from time to time to limit a portion of the effects resulting from changes in commodity prices. To the extent we hedge our commodity price exposure, we forego the benefits we would otherwise experience if commodity prices were to increase. In addition, we could experience losses resulting from our hedging and other derivative positions. Such losses could occur under various circumstances, including if our counterparty does not perform its obligations under the hedge arrangement, our hedge is imperfect or our hedging policies and procedures are not followed.

Non-utilization of certain assets could significantly reduce our profitability due to the fixed costs incurred with respect to such assets.

From time to time in connection with our business, we may lease or otherwise secure the right to use certain third party assets (such as railcars, trucks, barges, pipeline capacity, storage capacity and other similar assets) with the expectation that the revenues we generate through the use of such assets will be greater than the fixed costs we incur pursuant to the applicable leases or other arrangements. However, when such assets are not utilized or are under-utilized, our profitability is negatively affected because the revenues we earn are either non-existent or reduced (in the event of under-utilization), but we remain obligated to continue paying any applicable fixed charges, in addition to incurring any other costs attributable to the non-utilization of such assets. For example, in connection with our operations, we lease all of our railcars that obligate us to pay the applicable lease rate without regard to utilization. If business conditions are such that we do not utilize a portion of our leased assets for any period of time, we will still be obligated to pay the applicable fixed lease rate. In addition, during the period of time that we are not utilizing such assets, we will incur incremental costs associated with the cost of storing such assets, and we will continue to incur costs for maintenance and upkeep. Our failure to utilize a significant portion of our leased assets and other similar assets could have a significant negative impact on our profitability and cash flows.

In addition, certain of our field and pipeline operating costs and expenses are fixed and do not vary with the volumes we gather and transport. These costs and expenses may not decrease ratably or at all should we experience a reduction in our volumes transported by truck, marine vessel or rail or transported by our pipelines. As a result, we may experience declines in our margin and profitability if our volumes decrease.

We cannot cause our joint ventures and certain of our unrestricted subsidiaries to take or not to take certain actions unless some or all of the joint venture or third party participants agree.

Due to the nature of joint ventures, each participant (including us) in our material joint ventures has made substantial investments (including contributions and other commitments) in that joint venture and, accordingly, has required that the relevant charter documents contain certain features designed to provide each participant with the opportunity to participate in the management of the joint venture and to protect its investment in that joint venture, as well as any other assets which may be substantially dependent on or otherwise affected by the activities of that joint venture. These participation and protective features include a governance structure that consists of a management committee composed of members, only some of which are appointed by us. In addition, many of our joint ventures are operated by our “partners” and have “stand-alone” credit agreements that limit their freedom to take certain actions. Thus, without the concurrence of the other joint venture participants and/or the lenders of our joint venture participants, we cannot cause our joint ventures to take or not to take certain actions, even though those actions may be in the best interest of the joint ventures or us. Similarly, third parties that invested in Alkali Holdings’ equity have required that Alkali Holdings' governing documents contain certain features designed to protect their investment. These features include a governance structure that consists of a board of managers composed of members, only a majority of which are appointed solely by us. Certain fundamental decisions of Alkali Holdings may require consent of the full board of managers and, thus, without the concurrence of one of more third parties, we cannot cause Alkali Holdings to take or not to take certain fundamental actions, even though those actions may be in the best interest of Alkali Holdings or us.

The insolvency of an operator of our joint ventures, the failure of an operator of our joint ventures to adequately perform operations or an operator’s breach of applicable agreements could reduce our revenue and result in our liability to governmental authorities for compliance with environmental, safety and other regulatory requirements and to the operator’s suppliers and vendors. As a result, the success and timing of development activities of our joint ventures operated by others and the economic results derived therefrom depends upon a number of factors outside our control, including the operator’s timing and amount of capital expenditures, expertise and financial resources, and the inclusion of other participants.

In addition, joint venture participants may have obligations that are important to the success of the joint venture, such as the obligation to pay their share of capital and other costs of the joint venture. The third party equity investors in Alkali Holdings have obligations to invest additional capital in Alkali Holdings, subject to certain conditions. The performance and ability of third parties to satisfy their obligations under joint venture arrangements and Alkali Holdings’ governing documents

36

Table of Contents

is outside our control. If these third parties do not satisfy their obligations under these arrangements, our business may be adversely affected.

We may not be able to renew our marine transportation time charters and contracts when they expire at favorable rates, for extended periods, or at all, which may increase our exposure to the spot market and lead to lower revenues and increased expenses.

During the year ended December 31, 2021, our marine transportation segment received approximately 49% of its revenue from time charters and other fixed contracts, which help to insulate us from revenue fluctuations caused by weather, navigational delays and short-term market declines. We earned approximately 51% of our marine transportation revenues from spot contracts, where competition is high and rates are typically volatile and subject to short-term market fluctuations, and where we bear the risk of vessel downtime due to weather and navigational delays. If we deploy a greater percentage of our vessels in the spot market, we may experience a lower overall utilization of our fleet through waiting time or ballast voyages, leading to a decline in our operating revenue and gross profit. There can be no assurance that we will be able to enter into future time charters or other fixed contracts on terms favorable to us. For further discussion of our marine transportation contracts, see “Marine Transportation - Customers”.

A decrease in the cost of importing refined petroleum products could cause demand for U.S. flag product carrier and barge capacity and charter rates to decline, which would decrease our revenues and our ability to pay cash distributions on our units.

The demand for U.S. flag product carriers and barges is influenced by the cost of importing refined petroleum products. Historically, charter rates for vessels qualified to participate in the U.S. coastwise trade under the Jones Act have been higher than charter rates for foreign flag vessels. This is due to the higher construction and operating costs of U.S. flag vessels under the Jones Act requirements that such vessels be built in the U.S. and manned by U.S. crews. This has made it less expensive for certain areas of the U.S. that are underserved by pipelines or which lack local refining capacity, such as in the Northeast, to import refined petroleum products carried aboard foreign flag vessels than to obtain them from U.S. refineries. If the cost of importing refined petroleum products decreases to the extent that it becomes less expensive to import refined petroleum products to other regions of the East Coast and the West Coast than producing such products in the U.S. and transporting them on U.S. flag vessels, demand for our vessels and the charter rates for them could decrease.

We face periodic dry-docking costs for our vessels, which can be substantial.

Vessels must be dry-docked periodically for regulatory compliance and for maintenance and repair. Our dry-docking requirements are subject to associated risks, including delay, cost overruns, lack of necessary equipment, unforeseen engineering problems, employee strikes or other work stoppages, unanticipated cost increases, inability to obtain necessary certifications and approvals and shortages of materials or skilled labor. A significant delay in dry-dockings could have an adverse effect on our marine transportation contract commitments. The cost of repairs and renewals required at each dry-dock are difficult to predict with certainty and can be substantial.

The U.S. inland waterway infrastructure is aging and may result in increased costs and disruptions to our marine transportation segment.

Maintenance of the U.S. inland waterway system is vital to our marine transportation operations. The system is composed of over 12,000 miles of commercially navigable waterway, supported by over 240 locks and dams designed to provide flood control, maintain pool levels of water in certain areas of the country and facilitate navigation on the inland river system. The U.S. inland waterway infrastructure is aging, with more than half of the locks over 50 years old. As a result, due to the age of the locks, scheduled and unscheduled maintenance outages may be more frequent in nature, resulting in delays and additional operating expenses. Failure of the federal government to adequately fund infrastructure maintenance and improvements in the future would have a negative impact on our ability to deliver products for our marine transportation customers on a timely basis.

Failure to obtain or renew surety bonds on acceptable terms could affect our ability to secure reclamation obligations and, therefore, our ability to conduct our mining operations.

We are required to obtain surety bonds or post other financial security to secure performance or payment of certain long-term obligations, such as mine closure or reclamation costs. The amount of security required to be obtained can change as the result of new laws, as well as changes to the factors used to calculate the bonding or security amounts. We may have difficulty procuring or maintaining our surety bonds. Our bond issuers may demand higher fees or additional collateral, including letters of credit or other terms less favorable to us upon those renewals. Because we are required to have these bonds or other acceptable security in place before mining can commence or continue, our failure to maintain surety bonds, letters of credit or other guarantees or security arrangements would materially and adversely affect our ability to mine trona. That failure could result from a variety of factors, including lack of availability, higher expense or unfavorable market terms, the exercise by

37

Table of Contents

third-party surety bond issuers of their right to refuse to renew the surety and restrictions on availability of collateral for current and future third-party surety bond issuers under the terms of our financing arrangements.

Risks Related to Liquidity and Financing

Our indebtedness could adversely restrict our ability to operate, affect our financial condition, prevent us from complying with requirements under our debt instruments and prevent us from paying cash distributions to our unitholders.

We have outstanding debt and the ability to incur more debt. As of December 31, 2021, we had approximately $49.0 million outstanding of senior secured indebtedness and an additional $2.9 billion of senior unsecured indebtedness. We must comply with various affirmative and negative covenants contained in our credit agreement and the indentures governing our notes, some of which may restrict the way in which we would like to conduct our business. Among other things, these covenants limit or will limit our ability to incur additional indebtedness or liens, make payments in respect of or redeem or acquire any debt or equity issued by us, sell assets, make loans or investments, make guarantees, enter into any hedging agreement for speculative purposes, acquire or be acquired by other companies, and amend some of our contracts.

The restrictions under our indebtedness may prevent us from engaging in certain transactions which might otherwise be considered beneficial to us and could have other important consequences to unitholders. For example, they could increase our vulnerability to general adverse economic and industry conditions, limit our ability to make distributions; to fund future working capital, capital expenditures and other general partnership requirements; to engage in future acquisitions, construction or development activities; to access capital markets (debt and equity); or to otherwise fully realize the value of our assets and opportunities because of the need to dedicate a substantial portion of our cash flows from operations to payments on our indebtedness or to comply with any restrictive terms of our indebtedness; limit our flexibility in planning for, or reacting to, changes in our businesses and the industries in which we operate; and place us at a competitive disadvantage as compared to our competitors that have less debt.

We may incur additional indebtedness (public or private) in the future under our existing credit agreement, by issuing debt instruments, under new credit agreements, under joint venture credit agreements, under new credit agreements of our unrestricted subsidiaries, under capital leases or synthetic leases, on a project-finance or other basis or a combination of any of these. If we incur additional indebtedness in the future, it likely would be under our existing or replacement credit agreement or under arrangements that may have terms and conditions at least as or even more restrictive as those contained in our existing credit agreement and the indentures governing our existing notes. Failure to comply with the terms and conditions of any existing or future indebtedness would constitute an event of default. If an event of default occurs, the lenders or noteholders will have the right to accelerate the maturity of such indebtedness and foreclose upon the collateral, if any, securing that indebtedness. In addition, if there is a change of control as described in our senior secured credit facility, that would be an event of default, unless our creditors agreed otherwise, and, under our senior secured credit facility, any such event could limit our ability to fulfill our obligations under our debt instruments and to make cash distributions to unitholders which could adversely affect the market price of our securities.

In addition, from time to time, some of our joint ventures or unrestricted subsidiaries may have substantial indebtedness, which will include affirmative and negative covenants and other provisions that limit their freedom to conduct certain operations, events of default, prepayment and other customary terms.

We may not be able to access adequate capital (debt and/or equity) on economically viable terms or any terms.

The capital markets (debt and equity) have previously been from time to time disrupted and volatile as a result of adverse conditions, including recessionary pressures, bubble-effects and precipitous commodity price declines. These circumstances and events, which can last for extended periods of time, have led to reduced capital availability, tighter lending standards and higher interest rates on loans for companies in the energy industry, especially non-investment grade companies. Although we cannot predict the future condition of the capital markets, future turmoil in capital markets and the related higher cost of capital could have a material adverse effect on our business, liquidity, financial condition and cash flows, particularly if our ability to borrow money from lenders or access the capital markets to finance our operations were to be limited.

If we are unable to access the amounts and types of capital we seek at a cost and/or on terms that have been available to us historically, we could be materially and adversely affected. Such an inability to access capital could limit or prohibit our ability to execute significant portions of our business plan, such as executing our growth strategy, refinancing our debt and/or optimizing our capital structure.

Our actual construction, development and acquisition costs could exceed our forecast, and our cash flow from construction and development projects may not be immediate.

Our forecast contemplates significant expenditures for the development, construction or other acquisition of infrastructure and mining assets, including some construction and development projects with technological challenges. We (or

38

Table of Contents

our joint ventures) may not be able to complete our projects at the costs or within the timeframes currently estimated. If we (or our joint ventures) experience material cost overruns, we will have to finance these overruns using one or more of the following methods: using cash from operations; delaying other planned projects; incurring additional indebtedness; or issuing additional debt or equity.

Any or all of these methods may not be available when needed, may be prohibited or restricted by our or our joint venture’s debt or other contractual arrangements or may adversely affect our future results of operations.

In addition, some construction projects require substantial investments over a long period of time before they begin generating any meaningful cash flow.

Fluctuations in interest rates could adversely affect our business.

We have exposure to movements in interest rates. The interest rates on our senior secured credit facility ($49.0 million outstanding at December 31, 2021) are variable. Our results of operations and our cash flow, as well as our access to future capital and our ability to fund our growth strategy, could be adversely affected by significant increases in interest rates.

An increase in interest rates may also cause a corresponding decline in demand for equity investments, in general, and in particular, for yield-based equity investments such as our common units. Any such reduction in demand for our common units resulting from other more attractive investment opportunities may cause the trading price of our common units to decline.

Changes in the method pursuant to which the London Interbank Offered Rate (“LIBOR”), or the replacement of LIBOR with an alternative reference rate, may adversely impact our business and results of operations.

We are exposed to market risks due to the floating interest rates on our senior secured credit facility. Obligations under our senior secured credit facility bear interest at LIBORrate or alternate base rate (which approximates the prime rate), at our option, plus the applicable margin. We have not historically hedged our interest rates.

The U.K. Financial Conduct Authority, which regulates LIBOR, has announced that it will no longer persuade or compel banks to submit rates for the calculation of LIBOR after 2021. In March 2021, the ICE Benchmark Administration Limited, the administrator of LIBOR, extended the transition dates of certain LIBOR tenors to June 30, 2023, after which LIBOR reference rates will cease to be provided. Despite this deferral, the LIBOR administrator has advised that no new contracts using U.S. Dollar LIBOR should be entered into after December 31, 2021. It is unknown whether any banks will continue to voluntarily submit rates for the calculation of LIBOR, or whether LIBOR will continue to be published by its administrator based on these submissions, or on any other basis, after such dates.

In March 2020, the Financial Accounting Standards Board (“FASB”) issued ASU 2020-04, Reference Rate Reform (Topic 848), which provides expedients and exceptions for accounting treatment of contracts which are affected by the anticipated discontinuation of LIBOR and other rates resulting from rate reform. The Alternative Reference Rates Committee, a group of market participants convened under the auspices of the U.S. Federal Reserve Board and other U.S. regulators, has recommended the Secured Overnight Financing Rate (“SOFR”), calculated based on repurchase agreements backed by treasury securities, as its recommended alternative benchmark rate to replace LIBOR. The consequences of these developments cannot be entirely predicted but may include an increase in the interest rate on our senior secured credit facility when transitioning from LIBOR to SOFR, which may have an adverse effect on our financial condition, operating results or cash flows.

Risks Related to Legal and Regulatory Compliance

Our operations are subject to federal, state and local environmental protection and safety laws and regulations.

Our operations are subject to stringent federal, state and local environmental protection and safety laws and regulations. See “Regulation-Environmental Regulations.” Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, including the assessment of monetary penalties, the imposition of investigatory and remedial obligations, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and the issuance of orders enjoining future operations or imposing additional compliance requirements. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements would not materially affect us, there is no assurance that this trend will continue in the future. Revised or new additional regulations that result in increased compliance costs or additional operating restrictions, particularly if those costs are not fully recoverable from our customers, could have a material adverse effect on our business, financial position, results of operations and cash flows. Moreover, our operations, including the transportation and storage of crude oil, natural gas and other commodities, involves a risk that crude oil, natural gas and related hydrocarbons or other substances may be released into the environment, which may result in substantial expenditures for a response action, significant government penalties, liability to government agencies for natural resources damages, liability to private parties for personal injury or property damages and significant business interruption. These costs and liabilities could rise under increasingly strict environmental and safety laws, including regulations and enforcement policies, or claims for

39

Table of Contents

damages to property or persons resulting from our operations. If we are unable to recover such resulting costs through increased rates or insurance reimbursements, our cash flows and distributions to our unitholders could be materially affected.

Climate change legislation and regulatory initiatives may decrease demand for the products we store, transport and sell and increase our operating costs.

In recent years, federal, state, and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry, and the U.S. Congress has, from time to time, considered various proposals to reduce GHG emissions. Almost half of the states, either individually or through multi-state regional initiatives, have already taken legal measures to reduce GHG emissions, primarily through the planned development of GHG emission inventories and/or GHG cap-and-trade programs. In addition, states have imposed increasingly stringent requirements related to the venting or flaring of gas during oil and gas operations. While we are subject to certain federal GHG monitoring, reporting and emission control rules, our operations are not adversely and materially impacted by existing federal, state and local climate change initiatives. However, our compliance with any future legislation or regulation of GHGs, if it occurs, may result in materially increased compliance and operating costs.

In addition, in December 2015, the United States participated in the 21st Conference of the Parties (COP-21) of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature, and to conserve and enhance sinks and reservoirs of GHGs. The Agreement went into effect on November 4, 2016. Although the United States withdrew from the Paris Agreement, effective November 4, 2020, President Biden issued an Executive Order on January 20, 2021 to rejoin the Paris Agreement, which took effect on February 19, 2021. On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its greenhouse gas emissions by 50-52 percent below 2005 levels in 2030. In November 2021, in connection with the 26th Conference of the Parties (COP-26) in Glasgow, Scotland, the United States and other world leaders made further commitments to reduce greenhouse gas emissions, including reducing global methane emissions by at least 30% by 2030. Furthermore, many state and local leaders have stated their intent to intensify efforts to support the international climate commitments.

Efforts to regulate or restrict emissions of GHGs in areas that we conduct business could adversely affect the demand for the products that we transport, store and distribute and, depending on the particular program adopted, could increase our costs to operate and maintain our facilities by requiring that we, among other things, measure and report our emissions, install new emission controls on our facilities, acquire allowances to authorize our GHG emissions, pay any taxes related to our GHG emissions and administer and manage a GHG emissions program. We may be unable to include some or all of such increased costs in the rates charged by our pipelines or other facilities, and any such recovery may depend on events beyond our control, including the outcome of future rate proceedings before the FERC or state regulatory agencies and the provisions of any final legislation or implementing regulations. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby adversely affect demand for the crude oil and natural gas that we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations. It is not possible at this time to predict with any accuracy the structure or outcome of any future legislative or regulatory efforts to address such emissions or the eventual costs to us of compliance.

Moreover, climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes and snow or ice storms, as well as rising sea levels. Another possible consequence of climate change is increased volatility in seasonal temperatures. Some studies indicate that climate change could cause some areas to experience temperatures substantially hotter or colder than their historical averages. Extreme weather conditions can interfere with our production and increase our costs and damage resulting from extreme weather may not be fully insured. However, at this time, we are unable to determine the extent to which climate change may lead to increased storm or weather hazards affecting our operations.

President Biden’s regulatory agenda, and a closely divided Congress, creates some regulatory uncertainty for the oil and natural gas industry. Changes in environmental laws could increase costs and harm our business, financial condition and results of operations.

President Biden’s regulatory agenda, as well as a closely divided Congress, creates some regulatory uncertainty in the oil and natural gas industry. President Biden has indicated that he is supportive of, and has issued several executive orders promoting various programs and initiatives designed to, among other things, curtail climate change, control the release of methane from new and existing oil and gas operations, and decarbonize electric generation and the transportation sector. It remains unclear what additional actions the current administration will take and what support they will have for any potential legislative changes from Congress. Further, it is uncertain to what extent any new environmental laws or regulations, or any repeal of existing environmental laws or regulations, may affect our operations. However, such actions could materially increase our costs or impair our ability to explore and develop other projects, which could materially harm our business, financial condition and results of operations.

40

Table of Contents

We have reclamation and mine closing obligations. If the assumptions underlying our accruals are inaccurate, we could be required to expend greater amounts than anticipated.

Our mining operations in Wyoming are subject to mine permits issued by the Land Quality Division of the Wyoming Department of Environmental Quality (“WDEQ”). WDEQ imposes detailed reclamation obligations on us as a holder of mine permits. We accrue for the costs of current mine disturbance and of final mine closure. The amounts recorded are dependent upon a number of variables, including the estimated future closure costs, estimated proven reserves, assumptions involving profit margins, inflation rates and the assumed credit-adjusted risk-free interest rates. If these accruals are insufficient or our liability in a particular year is greater than currently anticipated, our future operating results could be materially adversely affected.

Regulation of the rates, terms and conditions of services and a changing regulatory environment could affect our financial position, results of operations or cash flow.

FERC regulates certain of our energy infrastructure assets engaged in interstate operations. Our intrastate pipeline operations are regulated by state agencies. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the Occupational Safety and Health Administration, as well as other federal and state regulatory agencies. This regulation extends to such matters as: rate structures; rates of return on equity; recovery of costs; the services that our regulated assets are permitted to perform; the acquisition, construction and disposition of assets; and to an extent, the level of competition in that regulated industry.

In addition, some of our pipelines and other infrastructure are subject to laws providing for open and/or non-discriminatory access.

Given the extent of this regulation, the evolving nature of federal and state regulation and the possibility for additional changes, the current regulatory regime may change and affect our financial position, results of operations or cash flow.

Our business would be adversely affected if we failed to comply with the Jones Act foreign ownership provisions.

We are subject to the Jones Act and other federal laws that restrict maritime cargo transportation between points in the U.S. only to vessels operating under the U.S. flag, built in the U.S., at least 75% owned and operated by U.S. citizens (or owned and operated by other entities meeting U.S. citizenship requirements to own vessels operating in the U.S. coastwise trade and, in the case of limited partnerships, where the general partner meets U.S. citizenship requirements) and manned by U.S. crews. To maintain our privilege of operating vessels in the Jones Act trade, we must maintain U.S. citizen status for Jones Act purposes. To ensure compliance with the Jones Act, we must be U.S. citizens qualified to document vessels for coastwise trade. We could cease being a U.S. citizen if certain events were to occur, including if non-U.S. citizens were to own 25% or more of our equity interest or were otherwise deemed to control us or our general partner. We are responsible for monitoring ownership to ensure compliance with the Jones Act. The consequences of our failure to comply with the Jones Act provisions on coastwise trade, including failing to qualify as a U.S. citizen, would have an adverse effect on us as we may be prohibited from operating our vessels in the U.S. coastwise trade or, under certain circumstances, permanently lose U.S. coastwise trading rights or be subject to fines or forfeiture of our vessels.

Our business would be adversely affected if the Jones Act provisions on coastwise trade or international trade agreements were modified or repealed or as a result of modifications to existing legislation or regulations governing the crude oil and natural gas industry in response to the recent lifting of the crude oil export ban and the Deepwater Horizon drilling rig incident in the U.S. Gulf of Mexico and subsequent crude oil spill.

If the restrictions contained in the Jones Act were repealed or altered or certain international trade agreements were changed, the maritime transportation of cargo between U.S. ports could be opened to foreign flag or foreign-built vessels. The Secretary of the Department of Homeland Security, or the Secretary, is vested with the authority and discretion to waive the coastwise laws if the Secretary deems that such action is necessary in the interest of national defense. Any waiver of the coastwise laws, whether in response to natural disasters or otherwise, could result in increased competition from foreign product carrier and barge operators, which could reduce our revenues and cash available for distribution.

Foreign-flag vessels generally have lower construction costs and generally operate at significantly lower costs than we do in U.S. markets, which would likely result in reduced charter rates. We believe that continued efforts will be made to modify or repeal the Jones Act. If these efforts are successful, foreign-flag vessels could be permitted to trade in the U.S. coastwise trade and significantly increase competition with our fleet, which could have an adverse effect on our business.

Events within the crude oil and natural gas industry may adversely affect our customers’ operations and, consequently, our operations and may also subject companies operating in the crude oil and natural gas industry, including us, to additional regulatory scrutiny and result in additional regulations and restrictions adversely affecting the U.S. crude oil and natural gas industry.

41

Table of Contents

OSHA’s emergency temporary standard (“ETS”) mandating either fully vaccination or weekly testing of employees could have a material adverse impact on our business and results of operations.

On November 5, 2021, OSHA announced an ETS requiring that employers with 100 or more employees to implement and enforce a mandatory Covid-19 vaccination policy, unless they adopt a policy requiring employees to choose to either be vaccinated or undergo weekly Covid-19 testing and wear a face covering in the workplace. On November 6, 2021, the ETS was stayed by the U.S. Fifth Circuit Court of Appeals pending additional court review. The Biden administration requested that the U.S. Fifth Circuit Court of Appeals reinstate the mandate. Multiple other lawsuits were filed regarding the ETS in various jurisdictions. The pending lawsuits were consolidated before the U.S. Sixth Circuit Court of Appeals. On December 17, 2021, the U.S. Sixth Circuit Court of Appeals lifted the injunction imposed by the U.S. Fifth Circuit Court of Appeals. Shortly after the ruling, a number of petitions were filed with the U.S. Supreme Court, asking it to immediately block the mandate. On January 13, 2022, the U.S. Supreme Court blocked the mandate. Subsequent to the U.S. Supreme Court’s decision, OSHA withdrew the ETS effective January 26, 2022, although OSHA did not withdraw the proposed rule and indicated it is prioritizing its resources to focus on finalizing a permanent COVID-19 Healthcare Standard. Additional vaccine mandates may be announced in jurisdictions in which our businesses operate. Our implementation of any such requirements if and when they are deemed to be enforceable may result in attrition, including attrition of critically skilled labor, and difficulty securing future labor needs, which could have a material adverse effect on our business and financial condition, and may result in costs of compliance that are difficult to quantify at this time.

Risks Related to Our Partnership Structure

Individual members of the Davison family can exert significant influence over us and may have conflicts of interest with us and may be permitted to favor their interests to the detriment of our other unitholders.

James E. Davison and James E. Davison, Jr., each of whom is a director of our general partner, each own a significant portion of our common units, including our Class B Common Units, the holders of which elect our directors. Other members of the Davison family also own a significant portion of our common units. Collectively, members of the Davison family and their affiliates own approximately 11.0% of our Class A Common Units and 77.0% of our Class B Common Units and are able to exert significant influence over us, including the ability to elect at least a majority of the members of our board of directors and the ability to control most matters requiring board approval, such as material business strategies, mergers, business combinations, acquisitions or dispositions of assets, issuances of additional partnership securities, incurrences of debt or other financings and payments of distributions. In addition, the existence of a controlling group (if one were to form) may have the effect of making it difficult for, or may discourage or delay, a third party from seeking to acquire us, which may adversely affect the market price of our common units. Further, conflicts of interest may arise between us and other entities for which members of the Davison family serve as officers or directors. In resolving any conflicts that may arise, such members of the Davison family may favor the interests of another entity over our interests.

Members of the Davison family own, control and have interests in diverse companies, some of which may (or could in the future) compete directly or indirectly with us. As a result, the interests of the members of the Davison family may not always be consistent with our interests or the interests of our other unitholders. Members of the Davison family could also pursue acquisitions or business opportunities that may be complementary to our business. Our organizational documents allow the holders of our units (including affiliates, like the Davisons) to take advantage of such corporate opportunities without first presenting such opportunities to us. As a result, corporate opportunities that may benefit us may not be available to us in a timely manner, or at all. To the extent that conflicts of interest may arise among us and any member of the Davison family, those conflicts may be resolved in a manner adverse to us or you. Other potential conflicts may involve, among others, the following situations: our general partner is allowed to take into account the interest of parties other than us, such as one or more of its affiliates, in resolving conflicts of interest; our general partner may limit its liability and reduce its fiduciary duties, while also restricting the remedies available to our unitholders for actions that, without such limitations, might constitute breaches of fiduciary duty; our general partner determines the amount and timing of asset purchases and sales, capital expenditures, borrowings, issuance of additional partnership securities, reimbursements and enforcement of obligations to the general partner and its affiliates, retention of counsel, accountants and service providers and cash reserves, each of which can also affect the amount of cash that is distributed to our unitholders; and our general partner determines which costs incurred by it and its affiliates are reimbursable by us and the reimbursement of these costs and of any services provided by our general partner could adversely affect our ability to pay cash distributions to our unitholders.

Our Class B Common Units may be transferred to a third party without unitholder consent, which could affect our strategic direction.

Unlike the holders of common stock in a corporation, our unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Only holders of our Class B Common Units have the right to elect our board of directors. Holders of our Class B Common Units may transfer

42

Table of Contents

such units to a third party without the consent of the unitholders. The new holders of our Class B Common Units may then be in a position to replace our board of directors and officers of our general partner with its own choices and to control the strategic decisions made by our board of directors and officers.

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 any class of our units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates, including any controlling unitholder, 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.

The interruption of distributions to us from our subsidiaries and joint ventures could affect our ability to make payments on indebtedness or cash distributions to our unitholders.

We are a holding company. As such, our primary assets are the equity interests in our subsidiaries and joint ventures. Consequently, our ability to fund our commitments (including payments on our indebtedness) and to make cash distributions depends upon the earnings and cash flow of our subsidiaries and joint ventures and the distribution of that cash to us. While some of our joint ventures and our Alkali Business may generally be required to make cash distributions to us on a quarterly or other periodic basis, distributions from our joint ventures and our unrestricted subsidiaries holding the Alkali Business are subject to the discretion of their respective management committee or similar governing body in one or more respects even if such distributions are generally required, such as with respect to the establishment of cash reserves. Further, the charter documents of certain of our joint ventures and the unrestricted subsidiaries holding the Alkali Business may vest in the management committees or similar governing body’s certain discretion or contain certain limitations regarding cash distributions even if such distributions are generally required. Accordingly, our joint ventures and our unrestricted subsidiaries holding the Alkali Business may not continue to make distributions to us at current levels or at all.

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our partnership agreement requires us to make quarterly distributions to our unitholders of all available cash reduced by any amounts reserved for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units and other limited partner interests may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may not be able to issue more equity to recapitalize.

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17-607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you 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 an 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. Substituted limited partners are liable both for the obligations of the assignor to make contributions to the partnership that were known to the substituted limited partner at the time it became a limited partner and for those obligations that were unknown if the liabilities could have been determined from the partnership agreement. Neither liabilities to partners on account of their partnership interest nor liabilities that are non-recourse to the partnership are counted for purposes of determining whether a distribution is permitted.

Unitholder liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law, and we conduct business in other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some states in which we do business or may do business in from time to time in the future. Unitholders could be liable for any and all of our obligations as if unitholders were a general partner if a court or government agency were to determine that: we were conducting business in a state but had not complied with that particular state’s partnership statute; or unitholders right to act with other unitholders to remove or replace our general partner, to approve some amendments to our partnership agreement or to take other actions under our partnership agreement constitutes “control” of our business.

Tax Risks to Our Unitholders

43

Table of Contents

Our tax treatment depends on our status as a partnership for federal income tax purposes, as well as us not being subject to a material amount of entity-level taxation by individual states. If the IRS were to treat us as a corporation (for U.S. federal income tax purposes) or if we were to become subject to a material amount of entity-level taxation for state tax purposes, then our cash available for distribution to our 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 federal income tax purposes. Section 7704 of the Internal Revenue Code provides that publicly traded partnerships will, as a general rule, be taxed as corporations. However, an exception exists with respect to publicly traded partnerships, 90% or more of the gross income of which for each taxable year consists of “qualifying income.”

If less than 90% of our gross income for any taxable year is “qualifying income” from transportation, processing or marketing of natural resources (including minerals, crude oil, natural gas or products thereof), interest or dividends income, we will be taxable as a corporation under Section 7704 of the Internal Revenue Code for federal income tax purposes for that taxable year and all subsequent years. We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes.

The decision of the U.S. Court of Appeals for the Fifth Circuit in Tidewater Inc. v. U.S., 565 F.3d 299 (5th Cir. April 13, 2009) held that the marine time charter being analyzed in that case was a “lease” that generated rental income rather than income from transportation services for purposes of a foreign sales corporation provision of the Internal Revenue Code. Even though (i) the Tidewater case did not involve a publicly traded partnership and it was not decided under Section 7704 of the Internal Revenue Code relating to “qualifying income,” (ii) some experienced practitioners believe the decision was not well reasoned, (iii) the IRS stated in an Action on Decision (AOD 2010-01) that it disagrees with and will not acquiesce to the Fifth Circuit’s marine time charter analysis contained in the Tidewater case and (iv) the IRS has issued several favorable private letter rulings (which can be relied upon and cited as precedent by only the taxpayers that obtained them) relating to time charters since the Tidewater decision was issued, the Tidewater decision creates some uncertainty regarding the status of income from certain of our marine time charters as “qualifying income” under Section 7704 of the Internal Revenue Code. Notwithstanding the foregoing, the Tidewater case is relevant authority because it is the only case of which we and our outside tax counsel are aware directly analyzing whether a particular time charter would constitute a lease or service agreement for certain U.S. federal tax purposes. Due to the uncertainty created by the Tidewater decision, our outside tax counsel, Akin Gump Strauss Hauer & Feld, LLP, was required to change the standard in its opinion relating to our status as a partnership for federal income tax purposes to “should” from “will.”

Although we do not believe based upon our current operations that we are treated as a corporation for federal income tax purposes, a change in our business (or a change in current law) could cause us to be treated as a corporation for federal income tax purposes or otherwise subject us to taxation as an entity. If we were treated as a corporation for federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate and would pay state income tax at varying rates. Distributions to our unitholders would generally be taxable to them again as corporate distributions and no income, gains, losses, or deductions would flow through to them. 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.

At the state level, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity-level taxation through the imposition of state income, franchise and other forms of taxation. For example, we are required to pay Texas franchise tax on our gross income apportioned to Texas. Imposition of any such taxes on us by any other state would 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 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 interpretation at any time. From time to time, members of Congress propose and consider substantive changes to the existing U.S. federal income tax laws that affect publicly traded partnerships, including the elimination of partnership tax treatment for certain publicly traded partnerships.

Any modifications to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes, or other proposals, will ultimately be enacted. Any such changes could cause a material reduction in our anticipated cash flows and could cause us to be treated as an association taxable as a corporation for U.S. federal income tax purposes subjecting us to the entity-level tax and adversely affecting the value of our units.

44

Table of Contents

A successful IRS contest of the federal income tax positions we take may adversely affect the market for our units, and the costs of any IRS contest would reduce our cash available for distribution to our unitholders and our general partner.

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 some or all of 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, our costs of any contest with the IRS will be borne indirectly by our unitholders and our general partner because these costs will reduce our cash available for distribution.

Pursuant to the Bipartisan Budget Act of 2015, for tax years beginning after December 31, 2017, if the IRS makes adjustments to our income tax returns, it (and some states) may assess and collect any taxes (including any applicable penalties and interest) resulting from such audit adjustments directly from us. To the extent possible under the new rules, our general partner may elect to either cause us to 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 it, 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. If we make payments of taxes and any penalties and interest directly to the IRS in the year in which the audit is completed, our cash available for distribution to our unitholders might be substantially reduced, in which case our current unitholders may bear some or all of the tax liability resulting from such audit adjustments, even if such unitholders did not own units in us during the tax year under audit.

Our unitholders will be required to pay taxes on income (as well as deemed distributions, if any) from us even if they do not receive any cash distributions from us.

Our unitholders will be required to pay any federal income taxes and, in some cases, state and local income taxes on their share of our taxable income (as well as deemed distributions, if any) even if unitholders receive no cash distributions from us. Our unitholders may not receive cash distributions from us equal to their share of our taxable income (or deemed distributions, if any) or even the tax liability that results from that income (or deemed distribution).

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 their tax basis in those units. Because distributions in excess of their allocable share of our net taxable income decrease their tax basis in their units, the amount, if any, of such prior excess distributions with respect to the units a unitholder sells will, in effect, become taxable income to the unitholder if it sells such units at a price greater than its tax basis in those units, even if the price received is less than its original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income due to potential recapture items, including depreciation recapture. In addition, because the amount realized includes a unitholder’s share of our non-recourse liabilities, if our unitholders sell their units, they may incur a tax liability in excess of the amount of cash they receive from the sale.

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

Our ability to deduct interest paid or accrued on indebtedness properly allocable to our trade or business during our taxable year may be limited in certain circumstances. If this limitation were to apply with respect to a taxable year, it could result in an increase in the taxable income allocable to a unitholder for such taxable year without any corresponding increase in the cash available for distribution to such unitholder. However, in certain circumstances, a unitholder may be able to utilize a portion of a business interest deduction subject to this limitation in future taxable years. Unitholders should consult their tax advisors regarding the impact of this business interest deduction limitation on an investment in our units.

Tax-exempt entities and non-U.S. persons 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 individual retirement accounts (known as IRAs), other retirement plans and non-U.S. persons, raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. With respect to taxable years beginning after December 31, 2017, subject to the proposed aggregation rules for certain similarly situated businesses or activities issued by the Treasury Department, a tax-exempt entity with more than one unrelated trade or business (including by attribution from investment in a partnership such as ours) is required to compute the unrelated business taxable income of such tax-exempt entity separately with respect to each trade or business (including for purposes of determining any net operating loss deduction). As a result, for years beginning after December 31, 2017, it may not be possible for tax exempt entities to utilize losses from an investment in our partnership to

45

Table of Contents

offset unrelated business taxable income from another unrelated trade or business and vice versa. Tax-exempt entities should consult a tax advisor before investing in our units.

Non-U.S. unitholders are generally taxed and subject to income tax filing requirements by the United States on income effectively connected with a U.S. trade or business (“effectively connected income”). Income allocated to our unitholders and any gain from the sale of our units will generally be considered to be “effectively connected” with a U.S. trade or business. As a result, distributions to a non-U.S. unitholder will be subject to withholding at the highest applicable effective tax rate and a non-U.S. unitholder who sells or otherwise disposes of a unit will also be subject to U.S. federal income tax on the gain realized from the sale or disposition of that unit. Moreover, the transferee of an interest in a partnership that is engaged in a U.S. trade or business is generally required to withhold 10% of the “amount realized” by the transferor unless the transferor certifies that it is not a foreign person. While the determination of a partner's “amount realized” generally includes any decrease of a partner’s share of the partnership’s liabilities, recently issued Treasury regulations provide that the “amount realized” on a transfer of an interest in a publicly traded partnership, such as our common units, will generally be the amount of gross proceeds paid to the broker effecting the applicable transfer on behalf of the transferor, and thus will be determined without regard to any decrease in that partner’s share of a publicly traded partnership’s liabilities. The Treasury regulations further provide that withholding on a transfer of an interest in a publicly traded partnership will not be imposed on a transfer that occurs prior to January 1, 2023, and after that date, if effected through a broker, the obligation to withhold is imposed on the transfer’s broker. Non-U.S. unitholders should consult a tax advisor before investing in our units.

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

Because we cannot match transferors and transferees of our common units, we adopt depreciation and amortization conventions that may not conform to all aspects of existing Treasury Regulations and may result in audit adjustments to our unitholders’ tax returns without the benefit of additional deductions. A successful IRS challenge to those conventions could adversely affect the amount of tax benefits available to a common unitholder. It also could affect the timing of these tax benefits or the amount of gain from a sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to the common unitholder’s tax returns.

Our unitholders will likely be subject to state and local taxes in states where they do not live as a result of an investment in our units.

In addition to federal income taxes, our unitholders will likely be subject to other taxes, including foreign, state and local taxes, unincorporated business taxes and estate inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if our unitholders do not live in any of those jurisdictions. Our unitholders will likely be required to file foreign, state, and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, our unitholders may be subject to penalties for failure to comply with those requirements. We currently own assets and do business in more than 20 states including Texas, Louisiana, Mississippi, Alabama, Florida, Arkansas and Oklahoma. Many of the states we currently do business in impose a personal income tax. It is our unitholders’ responsibility to file all applicable U.S. federal, foreign, state and local tax returns. 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.

We have subsidiaries that are treated as corporations for federal income tax purposes and subject to corporate-level income taxes.

We conduct a portion of our operations through subsidiaries that are, or are treated as, corporations for federal income tax purposes. We may elect to conduct additional operations in corporate form in the future. These corporate subsidiaries will be subject to corporate-level tax, which, effective for taxable years beginning after December 31, 2017, is 21%, and will likely pay state (and possibly local) income tax at varying rates, on their taxable income. Any such entity level taxes will reduce the cash available for distribution to us and, in turn, to our unitholders. If the IRS were to successfully assert that these corporate subsidiaries have more tax liability than we anticipate or legislation was enacted that increased the corporate tax rate, our cash available for distribution to our unitholders would be further reduced.

46

Table of Contents

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 (i) certain deductions for depreciation of capital additions, (ii) gain or loss realized on a sale or other disposition of our assets and (iii) in the discretion of the general partner, any other extraordinary item of income, gain, loss or deduction based upon ownership on the Allocation Date. Treasury Regulations allow a similar monthly simplifying convention, but such regulations do not specifically authorize all aspects of our proration method. If the IRS were to challenge our proration method, we may be required to change the allocation of items of income, gain, loss and deduction among our unitholders.

A unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of those units. If so, such unitholder 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 a unitholder whose units are loaned to a “short seller” to cover a short sale of units may be considered as having disposed of the loaned units, such unitholder may no longer be treated for tax purposes as a partner with respect to those units during the period of the loan to the short seller and the unitholder may recognize gain or loss from such disposition. Moreover, during the period of the loan to the short seller, 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 a loan to a short seller are urged to modify any applicable brokerage account agreements to prohibit their brokers from borrowing their units.

The IRS could challenge our treatment of the holders of Class A Convertible Preferred Units as partners for tax purposes, and if such challenge were sustained, certain holders of Class A Convertible Preferred Units could be adversely impacted.

The IRS may disagree with our treatment of the Class A Convertible Preferred Units as equity for U.S. federal income tax purposes, and no assurance can be given that our treatment will be sustained. If the IRS were to successfully characterize the Class A Convertible Preferred Units as indebtedness for tax purposes, certain holders of Class A Convertible Preferred Units may be subject to additional withholding and reporting requirements. Further, if the Class A Convertible Preferred Units were treated as indebtedness for U.S. federal tax purposes, rather than equity, distributions likely would be treated as payments of interest by us to the holders of Class A Convertible Preferred Units. Holders of Class A Convertible Preferred Units are encouraged to consult their tax advisors regarding the tax consequences applicable to the re-characterization of the Class A Convertible Preferred Units as indebtedness for tax purposes.

The amount that a Class A Convertible Preferred unitholder would receive upon liquidation may be less than the liquidation value of the Class A Convertible Preferred Units.

In general, we intend to specially allocate to the Class A Convertible Preferred Units items of our gross income in an amount equal to the distributions paid in respect of the Class A Convertible Preferred Units during the taxable year. If the distributions paid in respect of the Class A Convertible Preferred Units during a taxable year exceed the amount of our gross income allocated to the Class A Convertible Preferred Units for such taxable year (as in the case of prior distributions during the PIK period), the per unit capital account balance of the Class A Convertible Preferred unitholders would be reduced by the amount of such excess. If we were to dissolve or liquidate, after satisfying all of our liabilities, our unitholders (including the Class A Convertible Preferred unitholders) would be entitled to receive liquidating distributions in accordance with their capital account balances. In such event, Class A Convertible Preferred unitholders would be specially allocated items of gross income and gain in a manner designed to cause the capital account balance of a preferred unit to equal the liquidation value of a preferred unit. If we were to have insufficient gross income and gain to cause the capital account balance to equal the liquidation value of a preferred unit, then the amount that a Class A Convertible Preferred unitholder would receive upon liquidation would be less than the liquidation value of the Class A Convertible Preferred Units, even though there may be cash available for distribution to the holders of common units or any other junior securities with respect to their capital accounts.

General Risks

We are exposed to the credit risk of our customers in the ordinary course of our business activities.

When we (or our joint ventures) market our products or services, we (or our joint ventures) must determine the amount, if any, of the line of credit. Since certain transactions can involve very large payments, the risk of nonpayment and nonperformance by customers, industry participants and others is an important consideration in our business.

47

Table of Contents

For example, in those cases where we provide division order services for crude oil and natural gas purchased at the wellhead, we may be responsible for distribution of proceeds to all of the interest owners. In other cases, we pay all of or a portion of the production proceeds to an operator who distributes these proceeds to the various interest owners. These arrangements expose us to operator credit risk. As a result, we must determine that operators have sufficient financial resources to make such payments and distributions and to indemnify and defend us in case of a protest, action or complaint.

Additionally, we sell NaHS, soda ash and caustic soda to customers in a variety of industries. Some of these customers are in industries that have been impacted by a decline in demand for their products and services. Even if our credit review and analytical procedures work properly, we have experienced, and we could continue to experience losses in dealings with other parties.

We, along with one other U.S. trona-based soda producer, utilize ANSAC as our exclusive export vehicle for sales to customers in all countries excluding Canada, South Africa and members of the European Community and European Free Trade Area. Because ANSAC makes sales to its end customers directly and then allocates a portion of such sales to each member, we do not have direct access to ANSAC’s customers and we have no direct control over the credit or other terms ANSAC extends to its customers. As a result, we are indirectly exposed to ANSAC’s customer relationship and the credit and other terms ANSAC extends to its customers. In addition, if ANSAC ceased to exist, we could face costs and risks of securing those customers and related logistics arrangements on favorable terms.

Further, many of our customers could be impacted by weakened economic conditions, and volatility in commodity prices, such as crude oil, natural gas, copper, molybdenum, and aluminum in a manner that could influence the need for our products and services and their ability to pay us for those products and services. It is uncertain to what extent commodity prices will experience increased volatility in the future.

A natural disaster, pandemic, epidemic, accident, terrorist attack or other interruption event could result in an economic slowdown, severe personal injury, property damage and/or environmental damage, which could curtail our operations or otherwise adversely affect our assets and cash flow.

Some of our operations involve significant risks of severe personal injury, property damage and environmental damage, any of which could curtail our operations or otherwise expose us to liability and adversely affect our cash flow. Virtually all of our operations are exposed to the elements, including hurricanes, tornadoes, storms, floods, earthquakes and extended periods of below freezing weather. A significant portion of our operations are located along the U.S. Gulf Coast, and our offshore pipelines are located in the Gulf of Mexico. These areas can be subject to hurricanes.

If one or more facilities that are owned by us or that connect to us or our customers is damaged or otherwise affected by severe weather or any other disaster, pandemic, epidemic, accident, catastrophe or event, our operations could be significantly interrupted. Similar interruptions could result from damage to production or other facilities that supply our facilities or other stoppages arising from factors beyond our control. These interruptions might involve significant damage to people, property or the environment, and repairs or recovery might take from a week or less for a minor incident to six months or more for a major interruption. Any event that interrupts the fees generated by our energy infrastructure assets, or which causes us to make significant expenditures not covered by insurance, could reduce our cash available for paying our interest obligations as well as unitholder distributions and, accordingly, adversely impact the market price of our securities. Additionally, the proceeds of any property insurance maintained by us may not be paid in a timely manner or be in an amount sufficient to meet our needs if such an event were to occur, and we may not be able to renew it or obtain other desirable insurance on commercially reasonable terms, if at all.

Any terrorist attack at our facilities, those of our customers and, in some cases, those of other pipelines, could have a material adverse effect on our business.

In addition, a natural disaster, pandemic, epidemic, accident, terrorist attack or other interruption event may cause significant volatility in global financial markets, disruptions to commerce and reduced economic activity. The resulting macroeconomic conditions could adversely affect our cash flows, as well as the market price of our securities.

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.

In December 2019, a novel strain of coronavirus (SARS-Cov-2), which causes Covid-19, was reported to have surfaced in China. The spread of this virus has caused business disruption, including disruption to the oil and natural gas and industrial industries. In March 2020, the World Health Organization declared the outbreak of Covid-19 to be a pandemic, and the U.S. economy began to experience pronounced effects. The Covid-19 pandemic has negatively impacted the global economy, disrupted global supply chains, reduced global demand for oil and gas, petroleum products and industrial products, and created significant volatility and disruption of financial and commodity markets. The extent of the impact of the Covid-19 pandemic on our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors, including the demand for oil and natural gas, petroleum products and industrial products (including the impact that reductions in travel, manufacturing and consumer product demand

48

Table of Contents

have had and will have on the demand for commodities), the availability of personnel, equipment and services critical to our ability to operate our assets and the impact of potential governmental restrictions on travel, transportation and operations. There is uncertainty around the extent and duration of the disruption. The degree to which the Covid-19 pandemic or any other public health crisis adversely impacts our results will depend on future developments, which are highly uncertain and cannot be predicted. These developments include, but are not limited to, the duration and spread of the outbreak, its severity, the actions to contain the virus or treat its impact, its impact on the economy and market conditions and how quickly and to what extent normal economic and operating conditions can resume. These potential impacts, while uncertain, could adversely affect our operating results.

Compliance with and changes in cybersecurity requirements have a cost impact on our business, and failure to comply with such laws and regulations could have an impact on our assets, costs, revenue generation and growth opportunities.

In the second quarter of 2021, the Department of Homeland Security’s Transportation Security Administration (“TSA”) announced two new security directives. These directives require critical pipeline owners to comply with mandatory reporting measures and provide vulnerability assessments. We may be required to expend significant additional resources to respond to cyberattacks, to continue to modify or enhance our protective measures, or to assess, investigate and remediate any critical infrastructure security vulnerabilities. Any failure to remain in compliance with these government regulations may results in enforcement actions which may have a material adverse effect on our business and operations.

Our business could be negatively impacted by security threats, including cybersecurity threats, and related disruptions.

We rely on our information technology infrastructure to process, transmit and store electronic information, including information we use to safely operate our assets. While we believe that we maintain appropriate information security policies and protocols, we face cybersecurity and other security threats to our information technology infrastructure, which could include threats to our operational and safety systems that operate our pipelines, facilities and other assets. We could face unlawful attempts to gain access to our information technology infrastructure, including coordinated attacks from hackers, whether state-sponsored groups, “hacktivists” or private individuals. The age, operating systems or condition of our current information technology infrastructure and software assets and our ability to maintain and upgrade such assets could affect our ability to resist cybersecurity threats.

Our information technology infrastructure is critical to the efficient operation of our business and essential to our ability to perform day-to-day operations. Breaches in our information technology infrastructure or physical facilities, or other disruptions, could result in damage to our assets, loss of intellectual property, impairment of our ability to conduct our operations, disruption of our customers’ operations, loss or damage to our customer data delivery systems, safety incidents, damage to the environment and could have a material adverse effect on our operations, financial position and results of operations. It is also possible that breaches to our systems could go unnoticed for some period of time.

We and our third-party service providers may therefore be vulnerable to security events that are beyond our control, and we may be the target of cyber-attacks, as well as physical attacks, which could result in information security breaches and significant disruption to our business. Such data breaches and cyberattacks could compromise our operational or other capabilities and cause significant damage to our business and our reputation. Our information systems have experienced threats to the security of our digital infrastructure, but none of these have had a significant impact on our business, operations or reputation relating to such attacks. We maintain a 24/7 dedicated security operations center to anticipate, detect and prevent cyberattacks; however, there is no assurance that we will not suffer such losses or breaches in the future. As cyberattacks continue to evolve, we may be required to expend significant additional resources to respond to cyberattacks, to continue to modify or enhance our protective measures or to investigate and remediate any information systems and related infrastructure security vulnerabilities. We may also be subject to regulatory investigations or litigation relating from cybersecurity issues.

Our significant unitholders may sell units or other limited partner interests in the trading market, which could reduce the market price of our common units.

As of December 31, 2021, we have a number of significant unitholders. For example, certain members of the Davison family (including their affiliates) and management owned approximately 18 million, or approximately 14%, of our common units. From time to time, we also may have other unitholders that have large positions in our common units. In the future, any such parties may acquire additional interest or dispose of some or all of their interest. If they dispose of a substantial portion of their interest in the trading markets, such sales could reduce the market price of common units. In connection with certain transactions, we have put in place resale shelf registration statements, which allow unit holders thereunder to sell their common units at any time (subject to certain restrictions) and to include those securities in any equity offering we consummate for our own account.

49

Table of Contents

We may issue additional common units without unitholders’ approval, which would dilute their ownership interests.

We may issue an unlimited number of limited partner interests of any type without the approval of our unitholders. The issuance of additional common units or other equity securities of equal or senior rank will have the following effects: our unitholders’ proportionate ownership interest in us will decrease; the amount of cash available for distribution on each unit may decrease; the relative voting strength of each previously outstanding unit may be diminished; and the market price of our common units may decline.

Item 1B. Unresolved Staff Comments

None.

Item 2. Properties

See Item 1. “Business,” in addition to the Summary Overview of Mining Operations disclosure below. We also have various operating leases for rental of office space, facilities and field equipment and transportation equipment. See “Commitments and Off-Balance Sheet Arrangements” in Management’s Discussion and Analysis of Financial Condition and Results of Operations, and Note 4 to our Consolidated Financial Statements in Item 8 for details on our right of use assets and related lease liabilities. Such information is incorporated herein by reference.

Summary Overview of Mining Operations

Information concerning our mining properties in this Annual Report on Form 10-K has been prepared in accordance with the requirements of subpart 1300 of Regulation S-K, which first became applicable to us for the fiscal year ended December 31, 2021. These requirements differ significantly from the previously applicable disclosure requirements of SEC Industry Guide 7. Among other differences, subpart 1300 of Regulation S-K requires us to disclose our mineral resources, in addition to our mineral reserves, as of the end of our most recently completed fiscal year for our material mining property.

As used in this Annual Report on Form 10-K, the terms “mineral resource,” “measured mineral resource,” “indicated mineral resource,” “inferred mineral resource,” “mineral reserve,” “proven mineral reserve” and “probable mineral reserve” are defined and used in accordance with subpart 1300 of Regulation S-K. Under subpart 1300 of Regulation S-K, mineral resources may not be classified as “mineral reserves” unless the determination has been made by a qualified person that the mineral resources can be the basis of an economically viable project. You are specifically cautioned not to assume that any part or all of the mineral deposits (including any mineral resources) in these categories will ever be converted into mineral reserves, as defined by the SEC.

You are further cautioned that, except for that portion of mineral resources classified as mineral reserves, mineral resources do not have demonstrated economic value. Inferred mineral resources are estimates based on limited geological evidence and sampling and have too high of a degree of uncertainty as to their existence to apply relevant technical and economic factors likely to influence the prospects of economic extraction in a manner useful for evaluation of economic viability. Estimates of inferred mineral resources may not be converted to mineral reserves. A significant amount of exploration must be completed in order to determine whether an inferred mineral resource may be upgraded to a higher category of mineralization and it cannot be assumed that this will occur. Therefore, you are cautioned not to assume that all or any part of an inferred mineral resource exists, that it can be the basis of an economically viable project, or that it will ever be upgraded to a higher category of mineralization. Likewise, you are cautioned not to assume that all or any part of measured or indicated mineral resources will ever be converted to mineral reserves.

The information that follows is derived, in part, from the technical report summary (“TRS”) prepared by Stantec Consulting Services Inc., an external qualified person (“QP”) in compliance with Item 601(b)(96) and subpart 1300 of Regulation S-K. Portions of the following information are based on assumptions, qualifications and procedures that are not fully described herein. Reference should be made to the full text of the TRS, filed as Exhibit 96.1 hereto, incorporated herein by reference and made a part of this Annual Report on Form 10-K.

Overview of Mining Property and Operations

Our Alkali Business is one of the world’s leading producers of natural soda ash. Natural soda ash is processed from trona, a sodium carbonate mineral composed of soda ash (Na2CO3), sodium bicarbonate (NaHCO3) and water with the chemical formula Na2CO3NaHCO3H2O. Approximately 60% of the world’s natural soda ash is produced from trona extracted from underground mines and solution mining in the Green River Basin of southwestern Wyoming. Our trona mining and processing facilities are located in southwestern Wyoming approximately 18 miles west of the city of Green River, Wyoming. The following maps show the location of our mining property, as of December 31, 2021:

50

Table of Contents

Figure 2.1. General Location Map

51

Table of Contents

Figure 2.2. Map of Mining Areas

The Green River trona beds are collectively the largest known deposit of trona and the undisputed largest source of raw material feed for the production of natural soda ash in the world. The trona deposits are the result of very unusual, geological circumstances. Sodium-rich springs are believed to have fed ancient Lake Gosiute, a large, shallow inland lake that reached a maximum extent of over 15,000 square miles around 50 million years ago. In response to repetitive cycles of lake expansion, contraction and evaporation, and changes in temperature and salinity, trona was precipitated in beds of remarkable

52

Table of Contents

purity and extent. In addition to trona, the evaporite sodium mineral assemblage includes variable levels of other sodium carbonate minerals as well as halite (NaCl). At least 25 beds of natural trona in the Wilkins Peak Member of the Eocene Green River Formation exceed at least three feet in thickness and are estimated by the U.S. Geological Survey (“USGS”) to contain a cumulative resource of over 100 billion tons of trona. Individual trona beds are numbered in ascending order and trona beds of significance lie at depths between approximately 400 to 2,000 feet. Our current dry mining and solution mining operations exploit three trona beds, and our reserves are contained in four trona beds.

Genesis has one trona mineral property, located in the Known Sodium Leasing Area in Southwest Wyoming, primarily encompassed by the Westvaco area and the Granger area. Due to differences in geology between these two mine areas, the mineral leases and, ultimately, the trona resources and reserve estimates have been separated into Westvaco contiguous leases, Granger contiguous leases and Granger non-contiguous leases. The table and figures below are summaries of our acreage under each mineral lease type as of December 31, 2021.

Area by lessor (acres)

Contiguous leases Non-contiguous leases

Location Granger Westvaco Granger Remaining

Our trona resources and mining operations are held under leases covering 86,178 acres over portions of 23 townships, primarily in two contiguous units informally known as the “Westvaco” and “Granger” blocks. Mineral and mining rights are secured by leases from the Federal government, the State of Wyoming, and Sweetwater. We lease approximately 24,255 acres from the U.S. Government under the Mineral Leasing Act of 1920 (Title 30 §181) which includes trona under its definition of a “solid leasable mineral.” Federal minerals are administered by the U.S. Bureau of Land Management (“BLM”). We lease 40,320 acres from Sweetwater who acquired the mineral rights from Anadarko Land Corporation, a subsidiary of Occidental following Occidental’s August 2019 acquisition of Anadarko Petroleum Corporation, which acquired the ownership from the Union Pacific Resources Group (“UPRG”) in 2000. The lease includes alternate sections of land for 20 miles on either side of the trans-continental railroad, originally granted to UPRG under the Pacific Railroad Act of 1862 and subsequent railroad land grants. We also lease 21,603 acres from the State of Wyoming. Our mineral leases have varying terms. Our private leases are held indefinitely by production, BLM and State Leases expire and are renewed every 10 years. Royalty payments range from 2% to 8% of the sales value of soda ash products. We believe that all of our leases were entered into at market terms.

BXC owns preferred units in Alkali Holdings, which is an indirect parent entity of our subsidiary that owns all the leases and operates all of our mining properties. See Item 1 “Business—Recent Developments and Status of Certain Growth Initiatives—Granger Production Facility Expansion” for more information.

53

Table of Contents

Figure 2.3. Lease Tenure

54

Table of Contents

The table below shows certain key information for leases in the Westvaco contiguous leases, Granger contiguous leases, and Granger non-contiguous leases that are included in the resource and reserve estimates, including lessor, lease term, size, royalty information and expiration date.

55

Table of Contents

Our Westvaco site is a production stage property that mines trona through both dry mining and solution mining methods.The Westvaco mine has been in uninterrupted, continuous operation since its start in 1947 by Westvaco Chemical Company. We acquired the Westvaco facility in September 2017.

The location of the Westvaco site and contiguous lease boundary can be found in Figure 2.2.It is located in Sweetwater County, Wyoming, 18 miles west of Green River and is accessible from Interstate 80 (I-80), a four-lane divided highway. I-80 exit 72 is approximately seven miles from the processing plant. The Union Pacific Railroad passes just north of the Westvaco facilities with siding to access the mainline. The two main population centers of Green River, Wyoming and Rock Springs, Wyoming are 18 miles and 30 miles to the east, respectively. Evanston, Wyoming is 66 miles to the west. The area population provides a more than adequate base for staffing the Westvaco facilities, with a pool of talent for management.

The Westvaco site has been in continuous operation since 1947. Westvaco Chemical Corporation notified Union Pacific in 1946 of its intention to sink a mine shaft and to construct a trona processing plant. A shaft was sunk in 1947 to the top of Bed 17 bringing the first skipload of trona to the surface in late 1947. In the fall of 1948, Westvaco Chemical Corporation was acquired by the Food Machinery Corporation (later known as “FMC”). In 1952, the Westvaco Division of FMC formed the Intermountain Chemical Company as Wyoming’s first trona mining company. In 1953, Intermountain Chemical Company began producing refined soda ash by a sesquicarbonate process through a plant with a 300,000-ton capacity. The Alkali Chemical Division of FMC, including the trona mining and processing operations in the Green River Basin of Wyoming, was acquired by Tronox Alkali in May 2015. In September 2017, we acquired the Westvaco facility from Tronox Alkali and currently operate the facility through Genesis Alkali Wyoming, LP.

Infrastructure on the Westvaco site is very well developed as the facilities have been in operation for nearly seventy years. The infrastructure consists of sufficient truck and rail loadout facilities, electrical generation and transmission facilities, tailings facilities, product storage facilities, process facilities, natural gas pipelines and distribution facilities and water pipelines, treatment and distribution facilities. The Westvaco site also has ample buildings for offices, labs, change rooms, warehouses and maintenance shops.

Our Granger site is a production stage property that mines trona through solution mining methods.

The location of the Granger site and contiguous lease boundary can be found in Figure 2.2. The Granger site is located in Sweetwater County, Wyoming and can be accessed by traveling eight miles west of Green River, Wyoming on I-80, then turning north on state highway 372 and traveling about 12 miles to county road 11. The Granger site is accessible to the Union Pacific Railroad by a spur line that connects to the mainline near the town of Granger, Wyoming. The two main population centers of Green River, Wyoming and Rock Springs, Wyoming are 18 miles and 30 miles to the east, respectively. Evanston, Wyoming is 66 miles to the west. The area population provides a more than adequate base for staffing the Granger facilities, with a pool of talent for management.

The Granger mine and processing facility operated as an underground mine from 1976 to 2002. FMC acquired the properties in 1999 by acquiring Tg Soda Ash Inc., originally developed as a unit of Texasgulf and then owned by Elf Atochem. FMC converted the mine and mill to solution mining in 2005. The Alkali Chemical Division of FMC, including the trona mining and processing operations in the Green River Basin of Wyoming, was acquired by Tronox Alkali in May 2015. In September 2017, we acquired the Granger facility from Tronox Alkali and currently operate the facility through Genesis Alkali Wyoming, LP.

Infrastructure on the Granger site is very well developed as the facilities have operated for over 35 years. The infrastructure consists of sufficient rail loadout facilities, electrical transmission facilities, tailings facilities, product storage facilities, process facilities, natural gas pipelines and distribution facilities and water pipelines, treatment and distribution facilities. The Granger site also has ample buildings for offices, labs, change rooms, warehouses and maintenance shops.

As both the Westvaco site and Granger site have been operating for many years, all permits necessary for the operation of these facilities are in place. The Westvaco site includes approximately 36,000 permitted acres, of which the processing, support facilities, and tailings and evaporation ponds cover about 2,600 surface acres. The Granger facility includes about 16,000 permitted acres of which the processing, support facilities, and tailings and evaporation ponds cover about 1,800 surface acres. The WDEQ is the primary issuer of the environmental permits relevant to our operations, including air quality permits, mining and reclamation permits, as well as class III and class V underground injection control permits. With respect to each facility, permits, licenses and approvals are obtained as needed in the normal course of business based on our mine plans and federal, state, provincial and local regulatory provisions regarding mine permitting and licensing. There have been no outstanding violations or orders that would prevent continued operation of the plants and mines. This includes air, land, surface and groundwater, drinking water, wildlife, and waste. Approved reclamation plans are in place along with surety in the amounts of approximately $43 million for the Westvaco site and $23 million for the Granger site. Based on our historical permitting experience, we expect to be able to continue to obtain necessary mining permits and approvals to support historical rates of production.

56

Table of Contents

At our Wyoming property, we use both mechanical and solution mining to mine the trona ore:

•Dry Mining of Trona Ore. We extract trona ore from our Westvaco underground mine by mechanized, continuous mining methods. Our current underground dry mine production is from trona bed 17, a near-horizontal bed approximately 10 feet thick at a depth from the surface of 1,500-1,650 feet. Ore is extracted primarily by our single longwall mining machine from an extensive network of parallel drifts and connecting cross-cuts, known as room-and-pillar mining, and from longwall mining. Longwall miners shear off successive panels of ore which drops onto a conveyor belt for delivery to the vertical hoisting shafts. Longwall mining provides higher recovery rates leading to extended mine life compared to other dry mining techniques. Development of the “tunnels” necessary to access and ventilate our longwall is through room-and-pillar mining completed primarily by our fleet of borer miners. The ore is conveyed underground to two hoisting operations where it travels about 1,600 feet vertically to the surface and is either taken directly into our processing facilities or stored on two outdoor stockpiles for future consumption.

•Secondary Recovery Solution Mining. We solution mine trona at both our Westvaco and Granger sites using secondary recovery techniques. Our secondary recovery mining starts with the recovery of water streams from our operations and non-trona solids (“insolubles”) remaining from the processing of dry mined trona. The water and some insolubles are injected through a number of wells into the old dry mine workings at both our Westvaco and Granger sites. The insolubles settle out while the water travels through the old workings, dissolving sodium carbonate and sodium bicarbonate from the trona left behind during previous dry mining. Multiple pumping systems are used to pump the enriched brine to the surface for processing.

Our mineral recovery consists of four processing plants producing soda ash at two surface sites, Westvaco and Granger.

Dry mined and solution mined trona are processed into soda ash at our Westvaco site, located within the boundaries of our Westvaco contiguous lease blocks, involving multiple processing lines, steam generation facilities, evaporation ponds, spare parts warehouses, maintenance shops, and offices for engineering, production, and support staff. Mineral recovery at Westvaco site consists of three plants: the Sesqui plant, the Mono plant and the evaporation, lime, decahydrate crystallization, and monohydrate crystallization (“ELDM”) plant.

Our Sesqui and Mono plants process dry-mined trona into soda ash. Crushing, dissolution in water, filtration, and crystallization techniques are used to produce the desired final products. The Mono plant consists of two separate processing lines to produce soda ash. Mono I began operation in May 1972, while Mono II was started up in January 1976. In the Mono plant, the ore is calcined with heat, prior to dissolution, to process the trona into soda ash by the removal of water and carbon dioxide. A final calcining step using steam produces a dense soda ash product from the Mono process. The Sesqui plant was the first soda ash plant built and operated at the Westvaco site. In our Sesqui plant, the calcination is performed at the end of the process, producing a light density soda ash that is preferred in applications desiring increased absorptivity. The Sesqui process also has the ability to produce refined sodium sesquicarbonate (which we sell under the names S-Carb® and Sesqui®TM) for use as a buffer in animal feed formulations and in cleaning and personal care applications.

Our ELDM plant was constructed in 1995 and started operations in 1996. Our ELDM plant uses the tailings return water as a feed source for soda ash production. Solution mined trona is processed into dense soda ash in our ELDM operation. The steps to produce soda ash are similar to the dry mined processes, except the crushing and dissolving steps are eliminated because the trona is already in a water solution as it leaves the mine.

57

Table of Contents

Figure 2.4 Westvaco Surface Production Facilities

The Westvaco site also has a facility producing food, feed, and pharmaceutical grade sodium bicarbonate from a Sesqui plant intermediate product. Fifty percent caustic is produced on the Westvaco site for commercial sale from a Mono plant intermediate product.

The Westvaco site has successfully mined and processed trona ore at a profit for over 70 years. In this time, capital has been expended as appropriate to sustain the operation at the current production and operating cost level. We plan for capital expenditures necessary to replace equipment and facilities over time in order to sustain production and operating costs. We believe that the Westvaco site and its operating equipment are maintained in good working condition.

Solution mined trona is processed into soda ash at our Granger plant, located within the boundaries of the Granger contiguous lease blocks, and involves multiple processing lines, steam generation facilities, evaporation ponds, spare parts warehouses, maintenance shops, and offices for engineering, production, and support staff. The steps to produce soda ash are similar to the dry mined processes, except the crushing and dissolving steps are eliminated because the trona is already in a water solution as it leaves the mine. The approximately 500,000 short tons of soda ash capacity at our Granger facility was put in cold standby in April 2020 as a result of price and demand erosion driven largely by the Covid-19 pandemic.

58

Table of Contents

Figure 2.5. Granger Surface Production Facilities

The Granger site has successfully mined and processed trona ore at a profit for over 35 years. In this time, capital has been expended as appropriate to sustain the operation at the current production and operating cost level. The Granger Optimization Project is underway with the upgraded operation scheduled to start in the second half of 2023. Capital expenditures are generally for sustaining production and operating costs except for some remaining capital for our Granger Optimization Project. We believe that the Granger site and its operating equipment are maintained in good working condition.

The total book value of the Westvaco and Granger sites as of December 31, 2021 was approximately $1,439 million.

In many cases, market demand drives annual production so that actual production may be less than plant capacities. The table below shows annual production from our trona property and its four plants for the fiscal years ended December 31, 2021, 2020 and 2019.

Year ended December 31,

59

Table of Contents

Summaries of our mineral resources and reserves for the fiscal year ended December 31, 2021 are set forth in the tables below:

Area Resource Category(1) Million short tons (dry weight) Grade (% Trona)(2)

Granger Contiguous Leases Measured 618 84

Measured + Indicated 763 85

Westvaco Contiguous Lease Area Measured 1,072 88

Granger Non-Contiguous Leases Measured 87 85

Measured + Indicated 147 85

Total Measured + Indicated 2,140 86

Total Measured + Indicated + Inferred 2,147 86

(1)Mineral resources are exclusive of mineral reserves, which are summarized in the table below. Mineral resources are not mineral reserves and do not have demonstrated economic viability. There is no certainty that all or any part of the mineral resources will be converted into mineral reserves upon application of modifying factors.

(2)Based on the analysis described in Section 11.3 of the TRS, no economic cutoff grade has been applied to the resource given the long history of uninterrupted trona mining on the property, spatial consistency of the trona content and overall low insoluble and halite content. No elements or compounds from within the beds were identified as having a material impact on the ability to extract trona from the beds via mechanical or solution mining methods.

60

Table of Contents

Westvaco solution mining Proven(2) — —

Granger solution mining Proven(2) — —

Total dry extraction and solution mining Total Reserves 879 87 890 88

(1)Our trona ore reserves are calculated from in-place trona-bearing material that can be economically and legally extracted and processed into commercial products at the time of reserve determination. Our reserves estimates are developed using industry-standard procedures and have been reviewed internally and externally to ensure compliance with subpart 1300 of Regulation S-K.

(2)We use “measured and indicated” resources as the primary basis in determining our proven and probable reserves. We define proven reserves and probable reserves as follows:

a.Proven dry-mining reserves are measured reserves that fall within a 0.5 mile radius from drillhole data points or previously mined areas with a 7.0 feet minimum ore thickness.

b.Probable dry-mining reserves are indicated reserves that fall between 0.5 miles and 1.0 miles from drillhole data points or previously mined areas with a 7.0 feet minimum ore thickness.

c.All solution mining reserves are designated as probable based on the degree of confidence in the reserve estimate related to uncertainties involving solution flow paths, trona ore surface area available for dissolution, and the inaccuracy of depletion verification methods. They consist of both measured resources falling within a 0.5 mile radius from drillhole data points or previously mined areas and indicated resources that fall between 0.5 miles and 1.0 miles from drillhole data points or previously mined areas. Solution mining reserves are not limited to a minimum ore thickness, but rather are subjected to a 50 foot halo limit into large blocks of trona adjacent to areas impacted by previous dry mining and adjacent to areas planned for future dry mining.

(3)Estimated dry mining ore reserves include dilution from un-mineralized material within and marginal to the trona ore bed. We exclude support pillars from dry mining reserves, but a portion of the trona contained in the pillars is recovered by solution mining. We apply a bulk density factor of 133 lb/cu ft for conversion of volumes to mass. Key dry mining parameters include minimum trona ore bed thickness.

(4)Our solution mining ore reserves are reported on an in-place basis, inclusive of dilution from insoluble material that remains in the ground. The solution mining reserves are calculated using recovery parameters developed from our 20-plus years of cumulative secondary recovery solution mining experience. Key factors include the surface area of remaining support pillars and other trona-mineralized surfaces exposed to liquid solutions injected into voids created by dry mining, solubility and alkalinity data, and predicted dissolution rates.

(5)Our ore reserves have a minimum trona grade of 66.2% (occurs in Bed 15). The balance of the ore consists of clays, shales, and other impurities.

Total trona reserves for the fiscal year ended December 31, 2021 decreased 11 million short tons from fiscal year ended December 31, 2020, representing approximately 1.2% of the total reserves.

Our 2020 reserve disclosure was partially based on the assessment of Norwest Corp, an external consulting company, that generated a reserve estimate in 2015 and an updated reserve estimate as of September 1, 2017, meeting SEC 7 guidance. Our year end 2020 reported reserves reflected that September 1, 2017 estimate, reconciled with 2017, 2018, 2019, and 2020

61

Table of Contents

depletion. Our 2021 reserves are partially based on as assessment completed by Stantec Consulting Inc., an external QP, meeting the requirements of subpart 1300 of Regulation S-K.

Dry mining reserves at year end 2021 are 12 million short tons, or 2.7%, lower than year end 2020 reserves as a result of 4.4 million tons of dry mine extraction in 2021 and a more conservative layout used in development of the updated long term mine plan by the external consultant. The new layout leaves additional resource behind underneath areas near surface features such as highways.

Solution mining reserves are essentially the same at year end 2021 as they were at year end 2020 despite 1.4 million tons of solution based extraction in 2021 as a result of some modified assumptions applied by the external consultant in development of the 2021 reserve estimate. The 2021 reserve assessment includes higher ultimate secondary solution mining extraction percentage of the trona left behind by previous dry mining, based on actual secondary recovery that has been achieved in certain areas of the Westvaco mine. The gain in extraction percentage is largely offset by a more conservative assumption that removed certain areas of the Westvaco mine from the solution extractable base. The previous external assessment, which provided the basis for the 2020 year end reserves, assumed those areas were recoverable after the ultimate completion of dry mining at Westvaco.

Our mineral resource and reserve estimates are based on many factors, including the area and volume covered by our mining rights, assumptions regarding our extraction rates (based upon an expectation of operating the mines on a long-term basis) and the quality of in-place reserves. Key assumptions and parameters relating to our mineral resources and reserves at the Westvaco site are discussed in the TRS, and include, among other things, the following:

•The economic analysis of our resources and reserves was prepared based on 2022 dollars with annual inflation at 2.5% which has been applied to revenue, operating costs, and capital spending.

•The production schedule to mine and process the remaining reserves is based on the existing production capacity of the mine and processing plants.

•Bed 15, which lies approximately 35 to 55 feet below bed 17, can be effectively dry mined starting in roughly the year 2071, after the completion of longwall mining in overlying areas of Bed 17.

•Future secondary solution mining recoveries are similar to those that have been demonstrated thus far in certain areas of our Westvaco mine.

•Prices for bulk soda ash are based on the 2020 USGS price, which was escalated to establish the 2022 price while prices for bag and specialty products were consistent with recent history.

•Cash production costs include dry mining, solution mining, processing, royalties and production taxes, insurance, and administrative costs. Administrative costs include mine administration and corporate overhead allocations. Other costs include distribution, sales general and administrative, and research and development costs.

•The operating costs are based on our historical averages. Other costs are based on our five-year estimate. Costs are assumed to be similar in the future with annual inflation similar to pricing inflation. Modeled underground dry mining costs include a step change in approximately 50 years when longwall mining is phased out and replaced by borer and continuous mining in Bed 15 and the remaining areas of Bed 17.

•Capital expenditures are generally for sustaining production and operating costs. Sustaining cap-ex in the future is assumed similar to recent history and short term projections, with inflation similar to product pricing escalation.

•All leases remain valid throughout the time required to mine the reserves

•All permits remain valid throughout the life of the operation, and no new laws are enacted that require any extraordinary compliance which would significantly impact production or cost.

•New permits and approved mine plans will be obtained for mining reserves that lie within existing leases, but outside of our current mining permit areas.

•Tailings storage capacity will be developed as necessary over the life of the mine and processing plants.

•Because our Alkali Business is structured as a pass-through entity for income tax purposes, there is no provision for income taxes in the cash flow analysis.

Internal Control Disclosure

The modeling and analysis of our resources and reserves has been developed by our mine personnel and reviewed by several levels of internal management and external consultants, including the QP. The development of such resources and reserves estimates, including related assumptions, was a collaborative effort between the QP and our management. This section summarizes the internal control considerations for our development of estimations, including assumptions, used in resource and reserve analysis and modeling.

62

Table of Contents

When determining resources and reserves, as well as the differences between resources and reserves, management developed specific criteria, each of which must be met to qualify as a resource or reserve, respectively. These criteria, such as demonstration of economic viability, points of reference and grade, are specific and attainable. The QP and our management agree on the reasonableness of the criteria for the purposes of estimating resources and reserves. Calculations using these criteria are reviewed and validated by the QP.

We base our mineral reserve estimates on detailed geological, geotechnical, mine engineering and mineral processing inputs, and financial models developed and reviewed by management and technical staff of our Alkali Business, who possess years of experience directly related to the resources, mining and processing characteristics or financial performance of our operations. Additionally, our management and technical staff includes senior personnel who have remained closely involved with each of our active mining and mineral processing operations.

In preparing our reserve estimates for our Alkali operations at Green River, Wyoming, we follow accepted mining industry practice and are guided by our long-term experience in extraction of trona ore from underground mining and sodium carbonate from solution mining in the district. Estimates of recoverable reserves for both techniques are routinely reconciled with actual production, and our Alkali ore reserves disclosures comply with subpart 1300 of Regulation S-K.

All estimates require a combination of historical data and key assumptions and parameters. When possible, resources and data from generally accepted industry sources, such as governmental resource agencies, were used to develop these estimations.

Management also assesses risks inherent in mineral resource and reserve estimates, such as the accuracy of geophysical data that is used to support mine planning, identify hazards and inform operations of the presence of mineable deposits. Also, management is aware of risks associated with potential gaps in assessing the completeness of mineral extraction licenses, entitlements or rights, or changes in laws or regulations that could directly impact the ability to assess mineral resources and reserves or impact production levels. Risks inherent in overestimated reserves can impact financial performance when revealed, such as changes in amortizations that are based on life of mine estimates.

Documentation of sample security measures, quality control and assurance (“QAQC”) was not observed by the QP. However, given that there has been successful underground dry mining of Bed 17 and Bed 20 within and nearby the exploration sample sites, it would appear that previous sampling methods, sample security, analysis methods, and internal QAQC measures met the requirements for successful mine planning over the history of the Westvaco site and Granger site mining operations.

Item 3. Legal Proceedings

We are involved from time to time in various claims, lawsuits and administrative proceedings incidental to our business. In our opinion, the ultimate outcome, if any, of such proceedings is not expected to have a material adverse effect on our financial condition, results of operations or cash flows. See Note 21 to our Consolidated Financial Statements in Item 8.

Item 103 of SEC Regulation S-K requires disclosure of certain environmental matters when a governmental authority is a party to the proceedings and such proceedings involve potential monetary sanctions that we reasonably believe will exceed a specified threshold. Pursuant to recent SEC amendments to this item, we will be using a threshold of $1 million for such proceedings. We believe that such threshold is reasonably designed to result in disclosure of environmental proceedings that are material to our business or financial condition. Applying this threshold, there are no environmental matters to disclose for this period.

Item 4. Mine Safety Disclosures

Information regarding mine safety and other regulatory action at our mine in Green River, Wyoming is included in Exhibit 95 to this Form 10-K.

63

Table of Contents

PART II

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

Our Class A common units are listed on the New York Stock Exchange, or NYSE, under the symbol “GEL.”

At February 24, 2022, we had 122,539,221 Class A common units outstanding. As of December 31, 2021, the closing price of our common units was $10.71 and we had approximately 31,000 record holders of our Class A common units, which include holders who own units through their brokers “in street name.” Additionally, we have issued 25,336,778 Class A Convertible Preferred Units for which there is no established public trading market.

Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

•less the amount of cash reserves that our general partner determines in its reasonable discretion is necessary or appropriate to:

•provide for the proper conduct of our business;

•comply with applicable law, any of our debt instruments, or other agreements; or

•provide funds for distributions to our unitholders for any one or more of the next four quarters;

•plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings. Working capital borrowings are generally borrowings that are made under our senior secured credit facility and in all cases are used solely for working capital purposes or to pay distributions to partners.

The full definition of available cash is set forth in our partnership agreement and amendments thereto, which are incorporated by reference as an exhibit to this Form 10-K.

See Item 7. “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Capital Expenditures and Distributions Paid to our Unitholders” and Note 11 to our Consolidated Financial Statements in Item 8 for further information regarding restrictions on our distributions. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters” for information regarding securities authorized for issuance under equity compensation plans.

64

Table of Contents

Item 6. Selected Financial Data

None.

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

Introduction

We are a growth-oriented master limited partnership formed in Delaware in 1996. Our common units are traded on the New York Stock Exchange, or NYSE, under the ticker symbol “GEL.” We are (i) a provider of an integrated suite of midstream services (primarily transportation, storage, sulfur removal, blending, terminaling and processing) for a large area of the Gulf of Mexico and the Gulf Coast region of the crude oil and natural gas industry and (ii) one of the leading producers in the world of natural soda ash.

A core part of our focus is in the midstream sector of the crude oil and natural gas industry in the Gulf of Mexico and the Gulf Coast region of the United States. We provide an integrated suite of services to refiners, crude oil and natural gas producers, and industrial and commercial enterprises and have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks and terminals, railcars, rail unloading facilities, barges and other vessels, and trucks.

Our offshore crude oil and natural gas pipeline transportation and handling operations in the Gulf of Mexico focus on providing a suite of services primarily to integrated and large independent energy companies who make intensive capital investments (often in excess of a billion dollars) to develop large-reservoir, long-lived crude oil and natural gas properties. We provide services to one of the most active drilling and development regions in the U.S. (the Gulf of Mexico), a producing region representing approximately 15% of the crude oil production in the U.S. during 2021. Our onshore-based refinery-centric operations located primarily in the Gulf Coast region of the U.S. focus on providing a suite of services primarily to refiners, which includes our sulfur removal services, transportation, storage, and other handling services. Our onshore-based operations occur upstream of, at, and downstream of refinery complexes. Upstream of refineries, we aggregate, purchase, gather and transport crude oil, which we sell to refiners, as well as perform other handling activities. Within refineries, we provide services to assist in sulfur removal/balancing requirements. Downstream of refineries, we provide transportation services as well as market outlets for finished refined petroleum products and certain refining by-products.

The other core focus of our business is our Alkali Business. Our Alkali Business mines and processes trona from which it produces natural soda ash, also known as sodium carbonate (Na2CO3), a basic building block for a number of ubiquitous products, including flat glass, container glass, dry detergent and a variety of chemicals and other industrial products. Our Alkali Business has a diverse customer base in the United States, Canada, the European Community, the European Free Trade Area and the South African Customs Union with many long-term relationships. It has been operating for over 70 years and has an estimated remaining reserve life (based on 2021 production) of over 100 years.

Included in Management’s Discussion and Analysis are the following sections:

•Overview of 2021 Results

•Recent Developments and Initiatives

•Results of Operations

•Other Consolidated Results

•Financial Measures

•Liquidity and Capital Resources

•Guarantor Summarized Financial Information

•Critical Accounting Estimates

•Recent Accounting Pronouncements

65

Table of Contents

Overview of 2021 Results

We reported Net Loss Attributable to Genesis Energy, L.P. of $165.1 million in 2021 compared to Net Loss Attributable to Genesis Energy, L.P. of $416.7 million in 2020.

Net Loss Attributable to Genesis Energy, L.P. in 2020 was negatively impacted by impairment expense of

$280.8 million primarily associated with the rail logistics assets included within our onshore facilities and transportation segment and a loss on sale of assets of $22.0 million. Net Loss Attributable to Genesis Energy, L.P. in 2021 was impacted, relative to 2020, by higher segment margin of $10.3 million and higher non-cash revenues of approximately $25.4 million primarily within our onshore facilities and transportation and offshore pipeline transportation segments as a result of how we recognize revenue in accordance with GAAP on certain contracts.

These increases were partially offset by the following during 2021: (i) higher interest expense of $23.9 million; (ii) higher depreciation, depletion, and amortization expense of $14.4 million; (iii) higher general and administrative costs of $4.3 million; and (iv) lower equity in earnings of equity investees of $6.1 million primarily due to lower volumes on our Poseidon oil pipeline. See “Other Costs, Interest, and Income Taxes” below for additional discussion regarding the changes to interest expense, depreciation depletion and amortization, and general and administrative costs. Additionally, 2021 includes an unrealized (non-cash) loss from the valuation of the embedded derivative associated with our Class A Convertible Preferred Units of $30.8 million compared to an unrealized (non-cash) loss of $0.9 million in 2020 recorded within “Other expense, net.” “Other expense, net” in 2020 also includes a loss on the extinguishment of our 2022 and 2023 Notes of approximately $32.0 million partially offset by cancellation of debt income of $27.3 million from the repurchase of certain of our senior unsecured notes on the open market throughout the year. Lastly, we allocated net income to our noncontrolling interest holders of $27.0 million during 2021 as compared to $16.4 million during 2020.

Cash flows from operating activities were $338.0 million for the 2021 period compared to $296.7 million for 2020. This increase was primarily attributable to higher segment margin reported during 2021.

Available Cash before Reserves (as defined below in “Financial Measures”) decreased $51.4 million in 2021 to $203.9 million as compared to 2020 Available Cash before Reserves of $255.3 million, primarily due to higher interest expense of $23.9 million, higher maintenance capital utilized of $12.3 million, and 2020 including cancellation of debt income of $27.3 million. These decreases were partially offset by an increase in segment margin of $10.3 million during 2021 further discussed below in “Results from Operations.” See “Financial Measures” below for additional information on Available Cash before Reserves.

Segment Margin was $617.7 million in 2021, an increase of $10.3 million as compared to 2020. We currently manage our businesses through four divisions that constitute our reportable segments - offshore pipeline transportation, sodium minerals and sulfur services, onshore facilities and transportation and marine transportation. A more detailed discussion of our segment results and other costs is included below in “Results of Operations”.

Distributions to Unitholders

On February 14, 2022, we paid a distribution of $0.15 per unit related to the fourth quarter of 2021.