GEL US Equity☆

gel-20251231

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2025

OR

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

Commission file number 1-12295

GENESIS ENERGY, L.P.

(Exact name of registrant as specified in its charter)

(Address of principal executive offices) (Zip code)

Registrant’s telephone number, including area code: (713) 860-2500

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class Trading Symbol(s) Name of Each Exchange on Which Registered

Common Units GEL NYSE

Securities registered pursuant to Section 12(g) of the Act:

NONE

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yesx No o

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes oNox

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yesx No o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T(§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yesx No o

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer x Accelerated filer ☐

Non-accelerated filer ☐ Smaller reporting company ☐

Emerging growth company ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2) of the Act). Yes ☐ No x

The aggregate market value of the Class A common units held by non-affiliates of the Registrant on June 30, 2025 (the last business day of Registrant’s most recently completed second fiscal quarter) was approximately $1,855.0 million based on $17.23 per unit, the closing price of the common units as reported on the NYSE. For purposes of this computation, all executive officers and directors are deemed to be affiliates. Such a determination should not be deemed an admission that such executive officers and directors are affiliates. On February 18, 2026, the Registrant had 122,424,321 Class A Common Units and 39,997 Class B Common Units outstanding.

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GENESIS ENERGY, L.P.

2025 FORM 10-K ANNUAL REPORT

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Page

Part I

Item 1 Business 6

Item 1A. Risk Factors 27

Item 1B. Unresolved Staff Comments 45

Item 1C. Cybersecurity 45

Item 2. Properties 46

Item 3. Legal Proceedings 46

Item 4. Mine Safety Disclosures 46

Part II

Item 6. Selected Financial Data 48

Item 7A. Quantitative and Qualitative Disclosures About Market Risk 76

Item 8. Financial Statements and Supplementary Data 77

Item 9A. Controls and Procedures 77

Item 9B. Other Information 79

Part III

Item 10. Directors, Executive Officers and Corporate Governance 79

Item 11. Executive Compensation 85

Item 14. Principal Accountant Fees and Services 97

Part IV

Item 15. Exhibits and Financial Statement Schedules 98

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Definitions

Unless the context otherwise requires, references in this annual report to “Genesis Energy, L.P.,” “Genesis,” “we,” “our,” “us,” “the Company” or like terms refer to Genesis Energy, L.P. and its operating subsidiaries. Unless the context otherwise requires, references made in this annual report to the“Alkali Business” as defined below in Item 1. “Business” relate specifically to the period of our ownership of such business prior to the date of sale, February 28, 2025. As generally used within the energy industry and in this annual report, the identified terms have the following meanings:

Bbl or Barrel: One stock tank barrel, or 42 U.S. gallons liquid volume, used in reference to crude oil or other liquid hydrocarbons.

Bbls/day: Barrels per day.

DST: Dry short tons (2,000 pounds), a unit of weight measurement.

FERC: Federal Energy Regulatory Commission.

MBbls: Thousand Bbls.

MBbls/day: Thousand Bbls per day.

Mcf: Thousand cubic feet of gas.

MMBtu: One million British thermal units, an energy measurement.

MMcf: Thousand Mcf.

MMcf/day: Thousand Mcf per day.

NaHS: (commonly pronounced as “nash”) Sodium hydrosulfide.

NaOH or Caustic Soda: Sodium hydroxide.

Natural gas liquid(s) or NGL(s): The combination of ethane, propane, normal butane, isobutane and natural gasolines that, when removed from natural gas, become liquid under various levels of higher pressure and lower temperature.

Sour gas: Natural gas containing more than four parts per million of hydrogen sulfide.

Wellhead: The point at which the hydrocarbons and water exit the ground.

FORWARD-LOOKING INFORMATION

The statements in this Annual Report on Form 10-K that are not historical information may be “forward looking statements” as defined under federal law. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions, estimated or projected future financial performance, and other such references are forward-looking statements, and historical performance is not necessarily indicative of future performance. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as “anticipate,” “believe,” “continue,” “estimate,” “expect,” “forecast,” “goal,” “intend,” “may,” “could,” “plan,” “position,” “projection,” “strategy,” “should” or “will,” or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events (including production rates and other conditions and events), future operating results, the ability to generate sales, income or cash flow, the timing and anticipated benefits of our development projects and the expected performance of our offshore assets and other projects and business segments, the ability to simplify our capital structure and lower our cost of capital, and the availability of borrowing capacity to fund our growth capital expenditures are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:

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•demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas, NaHS, and caustic soda, all of which may be affected by economic activity, capital expenditures and operational and technical issues experienced by energy producers, weather, alternative energy sources, international conflicts and international events (including the war in Ukraine, the Israel and Hamas war and broader geopolitical tensions in South America, the Caribbean, the Middle East and Europe), global pandemics, inflation, the actions of OPEC and other oil exporting nations, conservation and technological advances;

•our ability to successfully execute our business and financial strategies;

•our ability to continue to realize cost savings from our cost saving measures;

•throughput levels and rates;

•changes in, or challenges to, our tariff rates;

•our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;

•service interruptions in our pipeline transportation systems, or processing operations, including due to adverse weather events;

•shutdowns or cutbacks at refineries, petrochemical plants, utilities, individual plants or other businesses for which we transport crude oil, petroleum, natural gas or other products or to whom we sell petroleum or other products;

•risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;

•changes in laws and regulations to which we are subject, including tax withholding issues, regulations regarding qualifying income, accounting pronouncements, and safety, environmental and employment laws and regulations;

•the effects of production declines resulting from a suspension of drilling in the Gulf of America or otherwise;

•the effects of future laws and regulations, including increased tariffs and proposed tariffs, taxes, duties and similar matters affecting international trade;

•planned capital expenditures and availability of capital resources to fund capital expenditures, and our ability to access the credit and capital markets to obtain financing on terms we deem acceptable;

•our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indentures governing our notes, which contain various affirmative and negative covenants;

•loss of key personnel;

•cash from operations that we generate could decrease or fail to meet expectations, either of which could reduce our ability to pay quarterly cash distributions (common and preferred) at the current level or to increase quarterly cash distributions in the future;

•an increase in the competition that our operations encounter;

•cost and availability of insurance;

•hazards and operating risks that may not be covered fully by insurance;

•our financial and commodity hedging arrangements, which may reduce our earnings, profitability and cash flow;

•changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates, including the result of any economic recession or depression that has occurred or may occur in the future;

•the impact of natural disasters, international military conflicts (such as the war in Ukraine, the Israel and Hamas war and broader geopolitical tensions in South America, the Caribbean, the Middle East and Europe), global pandemics, epidemics, accidents or terrorism, and actions taken by governmental authorities and other third parties in response thereto, on our business financial condition and results of operations;

•reduction in demand for our services resulting in impairments of our assets;

•changes in the financial condition of customers or counterparties;

•adverse rulings, judgments, or settlements in litigation or other legal or tax matters;

•the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes;

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•the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price; and

•a cyberattack involving our information systems and related infrastructure, or that of our business associates.

You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under “Risk Factors” discussed in Item 1A. These risks may also be specifically described in our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K (or any amendments to those reports) and other documents that we may file from time to time with the SEC. New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.

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PART I

Item 1. Business

General

We are a growth-oriented master limited partnership (“MLP”) formed in Delaware in 1996 focused on the midstream segment of the crude oil and natural gas industry. Our common units are traded on the New York Stock Exchange (“NYSE”), under the ticker symbol “GEL.” We provide an integrated suite of services (including transportation, storage, sulfur removal, blending, terminaling and processing) to crude oil and natural gas producers, refiners, and industrial and commercial enterprises. Our operations are primarily located in the Gulf of America and in the Gulf Coast region of the United States. We have a diverse portfolio of assets, including pipelines, offshore hub and junction platforms, refinery-related plants, storage tanks, terminals, railcars, rail unloading facilities, barges and other vessels, and trucks. Prior to February 28, 2025, our business also included the trona and trona-based exploring, mining, processing, producing, marketing, logistics and selling business based in Wyoming (the “Alkali Business”).

In the first quarter of 2025, we sold the Alkali Business and, as a result, re-organized our operating segments to represent how our chief operating decision maker, who is our Chief Executive Officer (our “CODM”), evaluates the performance of operations, develops strategy and allocates resources, including capital. Our sulfur services business, formerly reported under our soda and sulfur services reporting segment along with our Alkali Business, is now reported under our onshore transportation and services reporting segment along with those businesses that were included within our previously reported onshore facilities and transportation segment. As a result of this change, we now manage our businesses through the following three divisions that constitute our reportable segments:

•Offshore pipeline transportation, which includes the transportation and processing of crude oil and natural gas in the Gulf of America;

•Marine transportation, which provides waterborne transportation of petroleum products (primarily fuel oil, asphalt and other heavy refined products) and crude oil throughout North America; and

•Onshore transportation and services, which includes terminaling, blending, storing, and marketing crude oil, and transporting crude oil and refined products, as well as the processing of high sulfur (or “sour”) gas streams for refineries to remove the sulfur, and selling the related by-product, NaHS.

For additional information regarding our reportable segments, see discussion below entitled “Description of Segments and Related Assets.”

We conduct our operations and own our operating assets through our subsidiaries and joint ventures. Our general partner, Genesis Energy, LLC, a wholly-owned subsidiary that owns a non-economic general partner interest in us, has sole responsibility for conducting our business and managing our operations. Our outstanding common units (including our Class B Common Units), and our outstanding Class A convertible preferred units (our “Class A Convertible Preferred Units”), representing limited partner interests, constitute all of the economic equity interests in us.

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The following chart depicts our organizational structure at December 31, 2025.

Our Objectives and Strategies

Our primary objectives and strategies are to generate and grow stable free cash flows from operations and continue to deleverage our balance sheet, while never wavering from our commitment to safe and responsible operations. We believe the following have been and are critical to meet our objectives:

•The completion of our major growth capital spending program during 2025, which included the construction and connection of our SYNC Pipeline (as defined and discussed further below under “Recent Developments”) and the expansion of our existing Cameron Highway oil pipeline system (“CHOPS Pipeline”) (as discussed further below under “Recent Developments”).

•An increase in volumes from long-term contracted offshore commercial opportunities in the Gulf of America, including volumes from the Shenandoah development, which saw first production in the third quarter of 2025 and ties into our SYNC Pipeline and further downstream to our CHOPS Pipeline, and volumes from the Salamanca Floating Production System (“FPS”), which also saw first production in the third quarter of 2025 and ties into our existing Southeast Keathley Canyon pipeline system (“SEKCO Pipeline”) for further transportation downstream to our Poseidon oil pipeline system (“Poseidon Pipeline”).

•New and incremental volumes from continued in-field and sub-sea tieback opportunities as a result of the continued investment by the offshore producing community. These opportunities require minimal to no additional investment from us as a result of the current production handling capacity on our offshore pipeline transportation assets in the Gulf of America.

•The creation of financial flexibility from the combination of a significant amount of available borrowing capacity under our senior secured credit facility, subject to compliance with covenants, and our increasing cash flows from operations as discussed above, which will allow us to maximize our cash flow and focus on returning value to our capital structure with an emphasis on reducing debt in absolute terms, opportunistically redeeming our Class A Convertible Preferred Units and thoughtfully evaluating increases in our quarterly distributions to common unitholders.

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Business Strategy

Our primary business strategy is to provide an integrated suite of services to crude oil and natural gas producers and refiners and provide NaHS and caustic soda to industrial and commercial enterprises. Successfully executing this strategy should enable us to generate and grow stable cash flows from operations. We intend to execute this strategy by:

•Identifying and exploiting incremental profit opportunities, including cost synergies, across an increasingly integrated footprint;

•Economically expanding our pipeline and terminal operations by utilizing capacity currently available on our existing assets that requires minimal to no additional investment;

•Optimizing our existing assets and creating synergies through additional commercial and operating advancement;

•Leveraging customer relationships across business segments;

•Attracting new customers and expanding our scope of services offered to existing customers;

•Expanding the geographic reach of our businesses;

•Evaluating internal and third party growth opportunities (including asset and business acquisitions) that leverage our core competencies and strengths and further integrate our businesses; and

•Focusing on health, safety and environmental stewardship, and advancement of our sustainability program.

Financial Strategy

We believe that preserving financial flexibility is an important factor in our overall strategy and success. Over the long-term, we intend to:

•Increase the relative contribution of recurring and throughput-based revenues, emphasizing longer-term contractual arrangements;

•Maintain a sound, disciplined capital structure, including our current and forward path to deleveraging;

•Preserve a significant amount of available borrowing capacity under our senior secured credit facility;

•Reduce our overall cost of capital through a combination of reducing debt in absolute terms and opportunistically redeeming our high-cost Class A Convertible Preferred Units;

•Create strategic arrangements and share capital costs and risks through joint ventures and strategic alliances;

•Prudently manage our limited direct commodity price risks; and

•Pursue divestitures that support our deleveraging objective.

Competitive Strengths

We believe we are well positioned to execute our strategies and ultimately achieve our objectives due primarily to the following competitive strengths:

•Certain of our businesses are among the leaders in each of their respective markets, have long commercial lives, and have significant barriers to entry. We operate, among others, diversified businesses, each of which is one of the leaders in its market, has a long commercial life, and has significant barriers to entry. We operate one of the largest pipeline networks (based on throughput capacity) in the Deepwater area of the Gulf of America, an area that produced approximately 14% of the oil produced in the U.S. during 2025. We are one of the largest producers and marketers (based on tons produced) of NaHS in North and South America. We are one of the leading providers of crude oil and petroleum product transportation, storage and other handling services for two large, complex refineries in Baton Rouge, Louisiana and Baytown, Texas, both of which have been operational for over 100 years.

•Our businesses encompass a balanced, diversified portfolio of customers, operations and assets. We operate three business segments composed of a diversified suite of assets that enable us to provide a number of services primarily to crude oil and natural gas producers and refiners, and provide NaHS and caustic soda to industrial and commercial enterprises. Our businesses complement each other by allowing us to offer an integrated suite of services to common customers across our segments.

•We are financially flexible and have significant liquidity. As of December 31, 2025, we had $788.6 million of availability under our $800.0 million senior secured credit facility, subject to compliance with our covenants, including up to $171.9 million available under the $200.0 million petroleum products inventory loan sublimit and $45.0 million available for letters of credit. Our inventory borrowing base was $28.1 million at December 31, 2025.

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•Our businesses provide relatively consistent consolidated financial performance. Our historically consistent financial performance, combined with our goal of a conservative capital structure over the long term, has allowed us to generate relatively stable cash flows from operations.

•We have limited direct commodity price risk exposure in our crude oil marketing business and limited cost exposure in our NaHS business. The volumes of crude oil, refined products or intermediate feedstocks we purchase are either subject to back-to-back sales contracts or are hedged with exchange-traded derivatives to limit our direct exposure to movements in the price of the commodity; however, we cannot completely eliminate commodity price exposure. We have a risk management policy that requires us to monitor the effectiveness of the hedges as well as other limitations on the maximum levels of inventory we may hold that is not hedged. In addition, our service contracts with refiners allow us to adjust the rates we charge for processing to maintain a balance between NaHS supply and demand.

•Our offshore Gulf of America crude oil and natural gas pipeline transportation and handling operations are located in a significant producing region with large-reservoir, long-lived crude oil and natural gas properties. We provide a suite of services, primarily to integrated and large independent energy companies who make intensive capital investments to develop numerous large-reservoir, long-lived crude oil and natural gas properties in one of the largest producing regions in the U.S., the deepwater Gulf of America.

•Our expertise and reputation for high performance standards and quality enable us to provide refiners with economic and proven services. Our extensive understanding of the sulfur removal process and crude oil refining can provide us with an advantage when evaluating new opportunities and/or markets.

•Some of our pipeline transportation and related assets are strategically located. Our pipelines are critical to the ongoing operations of our refiner and producer customers. In addition, a majority of our terminals are located in areas that can be accessed by pipeline, truck, rail or barge.

•Some of our onshore transportation and services assets are operationally flexible. Our portfolio of trucks, barges, pipelines, rail unloading facilities, tanks and terminals affords us flexibility within our existing regional footprint and provides us the capability to enter new markets and expand our customer relationships.

•Our marine transportation assets provide waterborne transportation throughout North America. We own and operate a fleet of barges and boats used to provide transportation services to both inland and offshore customers within a large North American geographic footprint. All of our vessels operate under the U.S. flag and are qualified for U.S. coastwise trade under the Jones Act.

•We have an experienced, knowledgeable and motivated executive management team with a proven track record. Our executive management team has a significant level of experience in the midstream sector. Certain of our executive management team members have worked in leadership roles at a number of large, successful public companies, including other publicly-traded partnerships. Through their equity interest in us and compensation package (including long term incentive awards based on available cash before reserves, leverage, sustainability and safety metrics), our executive management team is incentivized to create value.

Recent Developments

The following is a brief listing of developments since December 31, 2024. Additional information regarding most of these items may be found elsewhere in this report.

Sale of the Alkali Business and Related Transactions

On February 28, 2025, we completed the sale of the Alkali Business to an indirect affiliate of WE Soda Ltd for a gross purchase price of $1.425 billion. The sale generated proceeds of approximately $1.0 billion, which reflects the net proceeds after the assumption of $413.4 million of our then outstanding 5.875% senior secured notes due 2042 (the “Alkali senior secured notes”) by an indirect affiliate of WE Soda Ltd, and other purchase price adjustments. We used the proceeds to pay down the outstanding balance on our senior secured credit facility on February 28, 2025, purchase 7,416,196 Class A Convertible Preferred Units on March 6, 2025 at a purchase price of $35.40, and redeem the remaining $406.2 million of principal outstanding on the 8.000% senior unsecured notes due January 15, 2027 (the “2027 Notes”) on April 3, 2025.

On February 27, 2025, in connection with the sale of the Alkali Business discussed above, we entered into the Second Amendment to the Seventh Amended and Restated Credit Agreement. This amendment primarily provides for: (i) a reduction from $900 million to $800 million of total borrowing capacity under our senior secured credit facility; (ii) unlimited cash netting against our outstanding debt for purposes of our leverage ratio calculation if our credit facility is undrawn at the end of a reporting period, otherwise a maximum netting of $25 million is allowed; and (iii) an increased permitted investment basket under certain circumstances that will allow us to opportunistically purchase existing private or public securities across our capital structure. Our senior secured credit facility matures on September 1, 2028, subject to extension at our request for one additional year on up to two occasions and subject to certain conditions, provided that if more than $150 million of our 7.750%

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senior unsecured notes due February 1, 2028 (the “2028 Notes”) remain outstanding as of November 2, 2027, the senior secured credit facility matures on such date.

Offshore Growth Capital Projects Completion

We previously entered into definitive agreements to provide transportation services for 100% of the crude oil production associated with two separate standalone deepwater developments (Shenandoah and Salamanca). In conjunction with these agreements, we committed to two offshore growth capital projects, which included expanding the current capacity of our 64% owned CHOPS Pipeline (the “CHOPS expansion”) and constructing a new 100% owned, approximately 105-mile, 20” diameter crude oil pipeline (the “SYNC Pipeline”) to connect the Shenandoah deepwater development to our existing asset footprint in the Gulf of America.

The CHOPS expansion included a complete overhaul of the Garden Banks 72 platform (“GB-72”) topside facilities, reconnection of the CHOPS Pipeline to the GB-72 platform, and the addition of pumps at both the High Island A5 (“HI-A5”) and GB-72 platforms to upgrade processing capabilities and increase throughput on the CHOPS Pipeline.

During 2025, we successfully finished the CHOPS expansion and SYNC Pipeline, which completed our major growth capital spending program. During the third quarter of 2025, we saw first production from the Shenandoah and Salamanca deepwater developments, and during the fourth quarter of 2025, Shenandoah throughput was well above the minimum volume commitments (“MVCs”) and volumes from Salamanca continued to ramp toward targeted production levels.

Market Update

Over the past several years, we have seen a heightened level of volatility in global markets and commodity prices driven by various events or circumstances outside of our control including, but not limited to, global pandemics, international military conflicts, geopolitical events and significant changes in economic policies. This volatility could negatively impact future prices for crude oil, natural gas, petroleum products and industrial products.

Management’s estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable, but are inherently uncertain. The uncertainties underlying our assumptions could cause our estimates to differ significantly from actual results, including with respect to the duration and severity of the lasting impacts of international conflicts and the result of any economic recession or depression that has occurred or may occur in the future as a result of or as it relates to changes in governmental policies (including with respect to tariffs or proposed tariffs, taxes, duties and similar matters affecting international trade) aimed at addressing inflation or other conditions or events, which could cause fluctuations in global economic conditions, including capital and credit markets. We will continue to monitor the current market environment and to the extent conditions deteriorate, we may identify triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, intangible assets and goodwill, which could result in impairment charges that could be material to our results of operations.

Although the ultimate impacts of these international conflicts, changes in governmental policies (including with respect to tariffs or proposed tariffs, taxes, duties and similar matters) and fluctuations in global economic conditions, including capital and credit markets, are still unknown at this time, we believe the fundamentals of our core businesses continue to remain strong and, considering the current industry environment and capital market behavior, we have continued our focus on deleveraging our balance sheet as further explained in “Liquidity and Capital Resources.”

Description of Segments and Related Assets

We conduct our businesses through three operating segments: offshore pipeline transportation, marine transportation and onshore transportation and services. These segments are strategic business units that provide a variety of midstream energy-related services. Financial information with respect to each of our operating segments can be found in Note 14 to our Consolidated Financial Statements in Item 8. Below is a more detailed description of our operating segments and their related assets.

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Offshore Pipeline Transportation

We conduct our offshore crude oil and natural gas pipeline transportation and handling operations in the Gulf of America through our offshore pipeline transportation segment, which focuses on providing a suite of services 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 located primarily in offshore Texas, Louisiana and Mississippi. The Gulf of America is one of the most active drilling and development regions in the U.S. representing approximately 14% of the crude oil production in the U.S. during 2025. Because the related pipelines and other infrastructure needed to develop the large-reservoir properties are capital intensive, we believe they are generally much less sensitive to short-term commodity price volatility, particularly once a project has been sanctioned or brought on-line.

We own interests in various offshore crude oil and natural gas pipeline systems, platforms and related infrastructure. Our interests in offshore crude oil pipeline systems that are currently operating (a number of which pipeline systems are substantial and/or strategically located) include approximately 1,536 miles of pipe with an aggregate design capacity of approximately 2,094 MMbls/day. For example, we own a 64% interest in the CHOPS Pipeline and a 64% interest in the Poseidon Pipeline, which are two of the largest crude oil pipelines (in terms of both length and design capacity) located in the Gulf of America. We also own 100% of the SEKCO Pipeline, which is a deepwater pipeline currently servicing the Lucius, Buckskin and Hadrian North fields as well as the Leon and Castille fields (through the Salamanca FPS), in the southern Keathley Canyon area of the Gulf of America and 100% of the SYNC Pipeline, which is a deepwater pipeline currently servicing the Shenandoah production field in the Walker Ridge area of the Gulf of America.

Our interests in operating offshore natural gas pipeline systems and related infrastructure include approximately 759 miles of pipe with an aggregate design capacity of approximately 2,200 MMcf/day. We also own an interest in two offshore hub platforms with an aggregate processing capacity of approximately 495 MMcf/day of natural gas and 123 MBbls/day of crude oil. Additionally, we own an interest in a number of junction and service platforms in the Gulf of America, which are used to (i) interconnect the offshore pipeline network; (ii) provide an efficient means to perform pipeline maintenance; and (iii) increase or direct the flow on our pipelines via pumps and measurement equipment.

We generate cash flows from our offshore pipelines from fees charged to customers or substantially similar arrangements that otherwise limit our direct exposure to changes in commodity prices.

We believe our offshore pipeline transportation segment is well positioned to participate in both the energy transition and lower carbon world as barrels produced from the Gulf of America are some of the least emission intensive barrels, from reservoir to refinery, of any barrel refined by Gulf Coast refineries (including shipping).

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Offshore Crude Oil and Natural Gas Pipelines

The table below reflects our interests in our operating offshore crude oil pipelines:

Main Lines

Lateral Lines(2)

Constitution Crude Oil Pipeline Genesis 67 80,000 100 %

(1)Capacity figures presented represent 100% of the design capacity as of December 31, 2025 and throughput figures represent 100% of the volumes in the period; except for Eugene Island, which represents our net capacity and volumes in the undivided interest (29%) in that system. Ultimate capacities can vary primarily as a result of crude oil quality, pressure requirements, installed pumps, related facilities, utilization of drag reducing agents and the viscosity of the crude oil actually moved.

(2)Represents 100% owned lateral crude oil pipelines which ultimately flow into our other offshore crude oil pipelines (including the CHOPS Pipeline and Poseidon Pipeline) and thus are excluded from main lines above.

•CHOPS Pipeline. CHOPS Pipeline is comprised of 24- to 30-inch diameter pipelines designed to deliver crude oil from fields in the Gulf of America to refining markets along the Texas Gulf Coast via interconnections with refineries and terminals located in Port Arthur and Texas City, Texas. Cameron Highway Oil Pipeline Company, LLC (“CHOPS”) also owns three strategically located multi-purpose offshore platforms. A financial party owns the remaining 36% interest in CHOPS.

•Poseidon Pipeline. The Poseidon Pipeline is comprised of 16- to 24-inch diameter pipelines to deliver crude oil from developments in the central and western offshore Gulf of America to other pipelines and terminals located in onshore and offshore Louisiana. An affiliate of Shell owns the remaining 36% interest in Poseidon Oil Pipeline Company, LLC (“Poseidon”).

•Odyssey Pipeline. The Odyssey pipeline is comprised of 12- to 20-inch diameter pipelines to deliver crude oil from developments in the eastern Gulf of America to other pipelines and terminals onshore in Louisiana. An affiliate of Shell owns the remaining 71% interest in Odyssey Pipeline, LLC (“Odyssey”).

•Eugene Island. The Eugene Island system is comprised of a network of crude oil pipelines, the main pipeline of which is 20 inches in diameter, to deliver crude oil from developments in the central Gulf of America to other pipelines and onshore terminals in Louisiana. Other owners in Eugene Island include affiliates of Exxon Mobil and Shell Oil Company.

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•SEKCO Pipeline. The SEKCO Pipeline is a deepwater pipeline that connects the Lucius platform, which supports the Lucius, Hadrian, and Buckskin production fields, and the Salamanca FPS, which supports the Leon and Castille production fields, located in the southern Keathley Canyon area of the Gulf of America, to our CHOPS Pipeline and Poseidon Pipeline.

•SYNC Pipeline. The SYNC pipeline is a newly constructed 20-inch diameter crude oil pipeline that connects the Shenandoah FPS, supporting the Shenandoah production field located in the Walker Ridge area of the Gulf of America, to our CHOPS Pipeline and Poseidon Pipeline.

•Shenzi Pipeline. The Shenzi Pipeline connects the Shenzi platform, supporting the Shenzi production field, and the King’s Quay FPS, which supports the Khaleesi, Mormont and Samurai production fields, located in the Green Canyon area of the Gulf of America, to our CHOPS Pipeline and Poseidon Pipeline.

•Allegheny Pipeline. The Allegheny Pipeline connects the Allegheny platform, which supports the Allegheny and Pegasus production fields, and the South Timbalier 316 platform, which supports the South Timbalier 316 production field, in the Green Canyon area of the Gulf of America, to our CHOPS Pipeline and Poseidon Pipeline.

•Marco Polo Pipeline. The Marco Polo Pipeline connects the Marco Polo platform, which supports the Shenzi K, K2 and Warrior production fields, to an interconnect with the Allegheny Crude Oil Pipeline in Green Canyon Block 164.

•Constitution Pipeline. The Constitution Pipeline connects the Constitution platform, which supports the Constitution, Constellation and Caesar Tonga production fields located in the Green Canyon area of the Gulf of America, to our CHOPS Pipeline and Poseidon Pipeline.

None of our offshore crude oil pipelines are rate regulated with the exception of Eugene Island, which is regulated by the FERC.

The table below reflects our interests in our operating offshore natural gas pipelines:

High Island Offshore System Genesis 238 500 100 %

Anaconda Gathering System Genesis 183 300 100 %

Manta Ray Offshore Gathering System Enbridge 237 800 25.7 %

(1)Capacity figures presented represent 100% of the design capacity.

•High Island. The High Island Offshore System (“HIOS”) transports natural gas from producing fields located in the Galveston, Garden Banks, West Cameron, High Island and East Breaks areas of the Gulf of America to the Kinetica Energy Express. HIOS includes 152 miles of pipeline and eight pipeline junction and service platforms that are regulated by the FERC. In addition, this system includes the 86-mile East Breaks Gathering System, which connects HIOS to the Hoover-Diana deepwater platform located in Alaminos Canyon Block 25.

•Anaconda. The Anaconda Gathering System gathers natural gas from producing fields located in the Green Canyon area in the Gulf of America, as well as the King’s Quay FPS, which supports the Khaleesi, Mormont and Samurai production fields, for delivery to the Nautilus System.

•Manta Ray. The Manta Ray Offshore Gathering System gathers natural gas from producing fields located in the Green Canyon, Southern Green Canyon, Ship Shoal, South Timbalier and Ewing Bank areas of the Gulf of America for delivery to numerous downstream pipelines, including the Nautilus System. This system includes three pipeline junction platforms.

•Nautilus. The Nautilus System connects the Anaconda Gathering system and Manta Ray Offshore Gathering System to the Neptune natural gas processing plant located in south Louisiana.

Offshore Hub Platforms

Offshore Hub platforms are typically used to: (i) interconnect the offshore pipeline network; (ii) provide an efficient means to perform pipeline maintenance; (iii) locate compression, separation and production handling equipment and similar assets; and (iv) conduct drilling operations during the initial development phase of a crude oil and natural gas property. The results of operations from offshore platform services are primarily dependent upon the level of commodity charges and/or demand-type fees billable to customers. Revenue from commodity charges is based on a fee per unit of volume delivered to the platform (typically per MMcf of natural gas or per barrel of crude oil) multiplied by the total volume of each product delivered.

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Demand-type fees are similar to firm capacity reservation agreements for a pipeline in that they are charged to a customer regardless of the volume the customer actually delivers to the platform. Contracts for platform services often include both demand-type fees and commodity charges, but demand-type fees generally expire after a contractually fixed period of time and in some instances may be subject to cancellation by customers.

The table below reflects our interests in our operating offshore hub platforms:

(1)Capacity figures presented represent 100% of the design capacity.

•Marco Polo. The Marco Polo platform, which is located in Green Canyon Block 608, processes crude oil and natural gas from production fields located in the South Green Canyon area of the Gulf of America.

•East Cameron. The East Cameron 373 platform has the ability to process production from the Garden Banks and East Cameron areas of the Gulf of America.

Customers

Due to the intensive capital requirements of exploring for and developing crude oil properties in the deepwater regions of the Gulf of America, most of our offshore pipeline transportation customers are integrated energy companies and other large independent producers, who desire to have longer-term arrangements ensuring that their production can access the markets.

Usually, our offshore crude oil pipeline customers enter into buy-sell or other transportation arrangements, pursuant to which the pipeline acquires possession (and, sometimes, title) from its customer of the relevant production at a specified location (often a producer’s platform or at another interconnection) and redelivers possession (and title, if applicable) to such customer of an equivalent volume at one or more specified downstream locations (such as a refinery or an interconnection with another pipeline). Most of the production handled by our offshore pipelines is pursuant to life-of-lease commitments that include both firm and interruptible capacity arrangements.

Competition

Our principal competition in our offshore pipeline transportation business includes other crude oil and natural gas pipeline systems as well as producers who may elect to build or utilize their own production handling facilities. We compete for new production on the basis of geographic proximity to the source, cost of connection, available capacity, transportation rates and access to onshore markets. In addition, our access to future reserves will depend on our ability, or the producers’ ability, to fund the significant capital expenditures required to connect to the new sources of oil and natural gas production. In general, most of our offshore pipelines are not subject to regulatory rate-making authority, and the rates we charge for services are dependent on the quality of the service required by the customer and the amount and term of the reserve commitment by that customer.

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Marine Transportation

Our marine transportation segment consists of (i) our inland marine fleet, which transports intermediate refined petroleum products, including asphalt, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the U.S., principally along the Mississippi River and its tributaries; (ii) our offshore marine fleet, which transports crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean; and (iii) our modern, double-hulled tanker, M/T American Phoenix. All of our vessels operate under the U.S. flag and are qualified for domestic trade under the Jones Act. The below table includes operational information relating to our marine transportation fleet:

Inland Offshore American Phoenix

Aggregate Fleet Design Capacity (MBbls) 2,165 884 330

Number of:

Push/Tug Boats 33 10 —

Product Tankers — — 1

(1)Represents capacity per barge ranges on our inland and offshore barge, as well as the capacity of our M/T American Phoenix.

Customers

Our marine customers are primarily refiners as well as large energy companies. In 2025, approximately80% of the revenue we generated stemmed from contracts with refiners. Our M/T American Phoenix is currently operating under a charter with a refining customer along the Gulf Coast and Eastern Seaboard. We are a provider of transportation services for our customers and do not assume ownership of the products we transport. Marine transportation services are conducted under term contracts, some of which have renewal options for customers with whom we have traditionally had long-standing relationships, as well as spot contracts. Most of our customers have been our customers for many years and we generally anticipate continued relationships; however, there is no assurance that any individual contract will be renewed.

Our marine contracts for our inland and offshore fleets are agreements to transport cargo for a specific customer at a set rate (affreightment) or at a daily rate (time charter). The rate may or may not escalate during the term of the contract; however, the base rate generally remains constant and contracts often include escalation provisions to recover changes in specific costs such as fuel. Time charters, which insulate us from revenue fluctuations caused by weather and navigational delays and temporary market declines, represented over 95%of our marine transportation revenues under contracts during 2025. A term contract is an agreement with a customer to move cargo for a specific period of time, and may involve multiple trips to various destinations. A spot contract is an agreement with a customer to move cargo from a specific origin to a designated destination for a rate negotiated at the time the cargo movement takes place. Spot contract rates are at the current “market” rate and are subject to market volatility. During 2025, approximately 77% of our marine transportation revenues were from term contracts and 23% were from spot contracts.

Competition

Our competitors for the marine transportation of crude oil and heavy refined petroleum products are midstream MLPs with marine transportation divisions, refineries and other companies that are in the business of solely marine transportation operations. Competition among common marine carriers is based on a number of factors including proximity to production, refineries and connecting infrastructures, customer service, and transportation pricing.

Our marine transportation segment also competes with other modes of transporting crude oil and heavy refined petroleum products, including pipeline, rail and trucking operations. Each mode of transportation has different advantages and disadvantages, which often are fact and circumstance dependent. For example, without requiring longer-term economic commitments from shippers, marine and truck transportation can offer shippers much more flexibility to access numerous markets in multiple directions (i.e., pipelines tend to flow in a single direction and are geographically limited by their receipt and delivery points with other pipelines and facilities), and our marine transportation offers shippers certain economies of scale as compared to truck transportation. In addition, due to construction costs and timing considerations, marine and truck transportation can provide cost effective and immediate services to a nascent producing region, whereas new pipelines can be very expensive and time consuming to construct and may require shippers to make longer-term economic commitments, such as take-or-pay commitments. On the other hand, in mature developed areas serviced by extensive, multi-directional pipelines, with extensive connections to various markets, pipeline transportation may be preferred by shippers, especially if shippers are

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willing to make longer-term economic commitments, such as take-or-pay commitments. Lastly, all of our inland marine transportation barges are asphalt capable and heated. This allows us to transport intermediate refined products that require heat, which other modes of transportation are not necessarily equipped to handle.

Onshore Transportation and Services

Through our onshore transportation and services segment, we provide various transportation and facilities services for crude oil and refined products as well as sulfur removal services (our sulfur services business).

We provide transportation and facilities services to Gulf Coast crude oil refiners and producers through a combination of purchasing, transporting, storing, blending and marketing of crude oil and refined products. In connection with these services, we utilize our increasingly integrated portfolio of logistical assets consisting of pipelines, trucks, tanks and terminals, barges and rail unloading facilities. The integrated nature of our onshore transportation and services assets is particularly evident in areas such as Louisiana and Texas.

Our crude oil onshore transportation and services operations are concentrated in Texas, Louisiana, Alabama, Florida and Mississippi. We provide services which include the gathering of crude oil from producers at the wellhead, transporting crude oil by gathering line, truck and barge to pipeline injection points, transporting crude oil for our gathering and marketing operations and for other shippers on our pipelines and marketing crude oil to refiners. We also have the ability to transport refined products via pipeline. For certain of these services, we generate fee-based income related to the transportation services provided. In some cases, we also realize a profit equal to the difference between the price at which we sell the crude oil and the price at which we purchase the crude oil, less the associated costs of aggregation and transportation. The most substantial components of the costs we incur while aggregating crude oil and petroleum products are transportation related costs.

These operations help to ensure (among other things) a base supply source for our crude oil pipeline systems, refinery customers and other shippers while providing our producer customers with a market outlet for their production. By utilizing our network of pipelines, trucks, rail unloading facilities, barges, and tanks and terminals, we are able to provide transportation related services to, and in many cases back-to-back gathering and marketing arrangements with, crude oil refiners and producers. Additionally, our crude oil and petroleum product gathering and marketing expertise and knowledge base provide us with the ability to capitalize on opportunities that arise from time to time in our market areas. We gather and market approximately 18,785 Bbls/day (as of December 31, 2025) of crude oil, most of which is produced from large resource basins throughout Texas and the Gulf Coast. Our crude oil pipelines transport many of these barrels, as well as barrels for third party producers and refiners to which we charge fees for our transportation services. Given our network of terminals, we also have the ability to store crude oil during periods of contango (crude oil prices for future deliveries are higher than for current deliveries) for delivery in future months. When we purchase and store crude oil during periods of contango, we attempt to limit direct commodity price risk by simultaneously entering into a contract to sell the inventory in a future period, either with a counterparty or in the crude oil futures market. Unsold volumes are hedged with commodity derivatives to offset the remaining price risk.

Onshore Crude Oil Pipelines

Through our onshore pipeline systems and related assets we own and operate, we transport crude oil for our gathering and marketing operations and for other shippers pursuant to tariff rates regulated by the FERC, Louisiana Public Service Commission (“LPSC”) or the Railroad Commission of Texas (“TXRRC”). Accordingly, we offer transportation services to any shipper of crude oil, if the products tendered for transportation satisfy the conditions and specifications contained in the applicable tariff. Pipeline revenues are a function of the level of throughput and the particular point where the crude oil is injected into the pipeline and the delivery point. We also may earn revenue from pipeline loss allowance volumes. In exchange for bearing the risk of pipeline volumetric losses, we deduct volumetric pipeline loss allowances and crude oil quality deductions. Such allowances and deductions are offset by measurement gains and losses. When our actual volume losses are less than the related allowances and deductions, we recognize the difference as income and inventory available for sale valued at the market price for the crude oil.

The margins from our onshore crude oil pipeline operations are equal to the revenues we generate from regulated published tariffs and pipeline loss allowances less the fixed and variable costs of operating and maintaining our pipelines. Each of our onshore pipeline systems has available capacity to accommodate potential growth in volumes.

The four onshore common carrier crude oil pipeline systems we own and operate are the Texas System, the Louisiana System, the Jay System, and the Mississippi System.

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Texas System Louisiana System Jay System Mississippi System

Rate Regulated FERC/TXRRC FERC/LPSC FERC FERC

•Texas System. Our Texas System takes delivery of crude oil volumes at various receipt points around Texas City (which includes the capability of receiving various Gulf of America pipeline volumes) for delivery to Webster, Texas, which ultimately connects to other crude oil pipelines. Our Texas System also transports crude oil from Hastings Junction (south of Houston, Texas) to several delivery points near Houston, Texas (including our Webster, Texas facility). We earn a tariff for our transportation services, with the tariff rate per barrel of crude oil varying with the distance from injection point to delivery point.

•Louisiana System. Our Louisiana System connects the Anchorage Tank Farm to our Port of Baton Rouge Terminal (which was built to service Exxon Mobil Corporation’s Baton Rouge refinery, which is one of the largest refinery complexes in North America, with more than 500,000 Bbls/day of refining capacity), allowing bidirectional flow of crude oil, intermediates and refined products between the Anchorage Tank Farm and this terminal via a dedicated crude oil pipeline and a dedicated intermediates pipeline. Our Louisiana system also transports crude oil bidirectionally between Port Hudson, our Baton Rouge Scenic Station rail unloading facility and the Anchorage Tank Farm. This pipeline system serves as a key asset in our integrated Baton Rouge area midstream infrastructure.

•Jay System. Our Jay System provides crude oil shippers access to refineries, pipelines and storage near Mobile, Alabama. That system also includes gathering connections, additional crude oil storage capacity of approximately 20,000 barrels in the field, an interconnect with our Walnut Hill rail facility and a delivery connection to a refinery in Alabama.

•Mississippi System. Our Mississippi System provides shippers of crude oil in Mississippi indirect access to refineries, pipelines, storage, terminals and other crude oil infrastructure located in the Eastern Gulf Coast.

Other Onshore Transportation and Services Operations

We own four operational crude oil rail unloading facilities located in Baton Rouge, Louisiana; Raceland, Louisiana; Walnut Hill, Florida; and Natchez, Mississippi which provide synergies to our existing asset footprint. We generally earn a fee for unloading railcars at these facilities. Three of these facilities, our Baton Rouge, Louisiana, Raceland, Louisiana, and Walnut Hill, Florida facilities are directly connected to our existing integrated crude oil pipeline and terminal infrastructure.

Within our onshore transportation and services business segment, we employ many types of logistically flexible assets. These assets include a suite of trucks and trailers, as well as terminals and other tankage with approximately 4.2 million barrels of leased and owned storage capacity in multiple locations along the Gulf Coast, accessible by pipeline, truck, rail or barge, in addition to tankage related to our crude oil pipelines, previously mentioned.

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Sulfur Services

Our sulfur services business primarily (i) provides sulfur removal services whereby it processes high sulfur (or “sour”) gas streams generated from crude oil processing operations to remove sulfur at 11 refining or petrochemical processing facilities located mainly in Texas, Louisiana, Arkansas, Oklahoma, Montana and Utah; (ii) operates storage and transportation assets in relation to those services; and (iii) sells NaHS and NaOH (also known as caustic soda) to large industrial and commercial companies. To provide sulfur removal services, we apply our proprietary technology, which uses large quantities of caustic soda (the primary raw material used in our process) to act as a scrubbing agent under prescribed temperature and pressure to remove sulfur. Sulfur removal in a refinery is a key factor in optimizing the production of refined products such as gasoline, diesel and aviation fuel. Our sulfur removal technology returns a clean (sulfur-free) hydrocarbon stream to the refinery for further processing into refined products, and simultaneously produces NaHS. The resultant, NaHS, constitutes the sole consideration we receive for our sulfur removal services. A majority of the NaHS we receive is sourced from refineries owned and operated by large companies, including Phillips 66, CITGO, HF Sinclair, Calumet and Ergon.

Our 11 sulfur removal services contracts have an average remaining term of approximately two years. The timing upon which these contracts renew vary based upon location and terms specified within each specific contract.

Our sulfur services footprint includes NaHS and caustic soda terminals in the Gulf Coast, the Southwest, Montana, Utah and British Columbia. We sell and deliver (via railcars, ships, barges and trucks) NaHS and caustic soda to over 100 customers. We are one of the largest marketers of NaHS in North and South America. By minimizing our costs through utilization of our own logistical assets and leased storage sites, we believe we have a competitive advantage over other suppliers of NaHS. NaHS is used in the specialty chemicals business (plastic additives, dyes and personal care products), in the pulp and paper business, and in connection with mining operations (separating copper from molybdenum and in the mining of nickel and gold) as well as bauxite refining (aluminum). NaHS has also gained acceptance in environmental applications, including waste treatment programs requiring stabilization and reduction of heavy and toxic metals and flue gas scrubbing. Additionally, NaHS can be used for removing hair from hides at the beginning of the tannery process.

Caustic soda is used in many of the same industries as NaHS. Many applications require both chemicals for use in the same process. For example, caustic soda can increase the yields in bauxite refining, pulp manufacturing and in the recovery of copper, gold and nickel. Caustic soda is also used as a cleaning agent (when combined with water and heated) for process equipment and storage tanks at refineries.

Customers

We provide transportation and facilities services for, as well as gather from and market crude oil and refined products to, numerous refiners and producers.

As part of our sulfur services business, we sell NaHS to customers in a variety of industries, with the largest customers involved in mining of base metals, primarily copper and molybdenum, and the production of pulp and paper. We sell to customers in the copper mining industry in the western U.S., Canada and Mexico. We also export NaHS to South America for sale to mining customers in Peru and Chile. Many of the industries that our NaHS customers are in (such as copper mining and the pulp and paper industry) participate in global markets for their products. As a result, this creates an indirect exposure for NaHS to global demand for the end products of our customers.

We sell caustic soda to many of the same customers who purchase NaHS from us as well as to some of the refineries in which we operate.

Our onshore transportation and services segment is not dependent on any single or small group of customers. The loss of any one customer would not have a material, adverse effect on us.

Competition

Our competitors for the provision of transportation and facilities services include other regional and local midstream service providers and companies who may have significant market share in the respective areas in which they operate. Competition among common carrier pipelines is based primarily on posted tariffs, quality of customer service and proximity to refineries, production and connecting pipelines. We believe that high capital costs, tariff regulation and the cost of acquiring rights-of-way make it unlikely that other competing pipeline systems, comparable in size and scope to our onshore pipelines, will be built in the same geographic areas in the near future. In addition, as the majority of our onshore pipelines directly serve refineries, we believe that these pipelines are not subject to the same competitive pressures as those tied directly to crude oil production.

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Our competitors for the supply of NaHS consist primarily of parties who produce NaHS as a by-product of or an alternative to other sulfur derivative products, including fertilizers, pesticides, other agricultural products, plastic additives and lubricants. Typically our competitors for the supply of NaHS have only one location and they do not have the logistical infrastructure that we have to supply customers. These competitors often reduce NaHS production when demand for their alternative sulfur derivatives is high and increase NaHS production when demand for these alternatives is low. Also, they tend to supply less when prices and demand for elemental sulfur are higher and supply more NaHS when the price of elemental sulfur falls.

Demand for NaHS faces competition from alternative sulfidity management mediums such as sulfidic caustic, emulsified sulfur, salt cake and flake NaHS. Changes in the value, supply and/or demand of these alternative products can impact the volume and/or value of our NaHS sold.

Typically, our competitors for sulfur removal services include refineries themselves through the use of their sulfur removal processes.

Our competitors for sales of caustic soda include manufacturers of caustic soda. These competitors supply caustic soda to our sulfur services operations and support us in our third-party caustic soda sales. By utilizing our storage capabilities and having access to transportation assets, we sell caustic soda to third parties who gain efficiencies from acquiring both NaHS and caustic soda from one source.

Credit Exposure

Our portfolio of accounts receivable is generally comprised in large part of obligations of refiners, integrated and large independent oil and natural gas producers, and mining and other industrial companies that purchase NaHS, most of which have stable payment histories. We believe that any credit risk posed by a concentration of customers in a specific industry is offset by the creditworthiness of our specific customer base in the context of our specific transactions as well as other factors, including the strategic nature of certain of our assets and relationships and our credit procedures. The credit risk related to exchange-traded contracts is limited due to the daily cash settlement procedures and other exchange related requirements.

When we market crude oil, petroleum products, and NaHS and provide transportation and other services, we must determine the amount, if any, of the line of credit we will extend to any given customer. We have established procedures to manage our credit exposure, including initial credit approvals, credit limits, collateral requirements and rights of offset. Letters of credit, prepayments and guarantees are also utilized to limit credit risk to ensure that our established credit criteria are met. We use similar procedures to manage our exposure to our customers in the offshore pipeline transportation and marine transportation segments.

Some of our largest customers include Exxon Mobil Corporation, MV Purchasing, BP, Shell, and Phillips 66.

Human Capital

We believe our employees are our most important asset and the cornerstone of our organization. We take steps to attract and retain talented people to safely operate our assets, foster customer relationships, and achieve our long-term goals. We are committed to employee retention and we encourage our employees to maintain long-term careers with us. Human capital measures and objectives which we focus on in managing our business include safety, employee compensation and benefits, diversity and inclusion, and employee development.

Employees

To carry out our business activities, we employed 1,061 employees at December 31, 2025. We consider our relationship with our employees to be in good standing.

Safety

Safety is one of our guiding principles and it is our intention to create and sustain a workplace free from recognized safety and health hazards. We have implemented safety programs and management practices to promote a culture of safety, which include policies, training, procedures, audits, inspections, incident evaluations, data analysis, reporting and communications. We also established annual safety and health targets for total recordable injury and illness rates, and tied a portion of our management compensation to safety related goals to emphasize the importance of safety at the Company.

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Employee Compensation and Benefits

Our compensation programs are integrated with our overall business strategies and management processes to incentivize performance, maximize returns and build shareholder value. We participate in market surveys as well as work with consultants to benchmark our compensation and benefits programs to help us offer competitive remuneration packages to attract and retain high-performing employees.

Furthermore, to attract and meet the needs of our workforce, we offer a comprehensive and affordable benefits program that includes medical, dental, vision, life insurance, and disability protection, along with a generous retirement savings plan, including up to six percent matching. Our benefits package options may vary depending on the type of employee and date of hire. Additionally, we continuously look for ways to improve employee work-life balance and the well-being of our employees and their families.

Employee Development

Our success as a company is measured by the successful performance of our employees in their respective roles. Thus, it is our policy to properly train and equip each employee to perform his or her job functions safely and in compliance with all laws, regulations and internal procedures.

We develop our employees through performance management processes, regular coaching and supervisory and leadership training while also offering a tuition reimbursement program. Our annual performance management cycle enables managers and employees to collaborate to set performance goals and development objectives that align to business objectives. We also provide in-house health and safety training and emergency response training. Employee attendance at external workshops, conferences and other training events is also encouraged.

Regulation

Pipeline Rate and Access Regulation

The rates and the terms and conditions of service of our interstate common carrier pipeline operations are subject to regulation by FERC under the Interstate Commerce Act, or ICA. Under the ICA, rates must be “just and reasonable,” and must not be unduly discriminatory or confer any undue preference on any shipper. FERC regulations require that oil pipeline rates and terms and conditions of service for regulated pipelines be filed with FERC and posted publicly.

Effective January 1, 1995, FERC promulgated rules simplifying and streamlining the ratemaking process. Previously established rates were “grandfathered,” limiting the challenges that could be made to existing tariff rates. Increases from grandfathered rates of interstate oil pipelines are currently regulated by FERC primarily through an index methodology, whereby a pipeline is allowed to change its rates based on the year-to-year change in an index. Under FERC regulations, we are able to change our rates within prescribed ceiling levels that are tied to the Producer Price Index for Finished Goods (“PPI-FG”). Rate increases made pursuant to the index are presumed to be just and reasonable. They will be subject to protest, but such protests must show that the rate increase resulting from application of the index is substantially in excess of the applicable pipeline’s increase in costs. We may be required to lower our rates if the ceiling level decreases below our existing rates in a given year. The FERC indexing is subject to review and revision every five years.

On December 17, 2020, the FERC issued a final rule setting the index for the five-year period beginning July 1, 2021, and ending on June 30, 2026, at PPI-FG plus 0.78%. On January 20, 2022, the FERC granted a rehearing of certain aspects of the final rule and revised the index level to PPI-FG minus 0.21% effective March 1, 2022 through June 30, 2026. The FERC ordered pipelines with filed rates that exceed their index ceiling levels based on PPI-FG minus 0.21% to file rate reductions effective March 1, 2022. On review, the U.S. Court of Appeals for the D.C. Circuit, in Liquid Energy Pipeline Association v. FERC, 109 F.4th 543 (D.C. Cir. 2024), vacated FERC’s rehearing order that adopted the PPI-FG minus 0.21% and ordered FERC to reinstate its prior order with a PPI-FG plus 0.78%. In September 2024, FERC reinstated the PPI-FG plus 0.78% and subsequently initiated a rulemaking in Docket No. RM25-2, proposing to amend the PPI-FG for the five-year period that began on July 1, 2021, and adopt a revised index level of PPI-FG minus 0.21%. On November 20, 2025, the FERC issued an order terminating the rulemaking proceeding in Docket No. RM25-2 without amending the index level, with the result that the PPI-FG plus 0.78% remains in place for the remainder of the five-year review period ending on June 30, 2026. A petition for review of this FERC order has been filed with the U.S. Court of Appeals for the D.C. Circuit.

FERC also issued a separate order on November 20, 2025, in Docket Nos. RM93-11-003, RM20-14-003 and RM20-24-004, in which it granted pipeline remedial relief for the period from March 1, 2022, the effective date of the PPI-FG minus 0.21%, to September 17, 2024, the date on which FERC reinstated the PPI-FG plus 0.78%. FERC allowed pipelines that charged the maximum rates permitted for shipments made during the period of March 1, 2022 to September 17, 2024 to apply the PP-FG plus 0.78% to those shipments and recover amounts directly from shippers. Requests for rehearing of the FERC’s order have been filed with FERC, and a petition for review of the FERC’s order has been filed with the U.S. Court of Appeals for the D.C. Circuit. A motion for stay of the FERC’s order has also been filed with FERC.

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In addition to the index methodology, FERC allows for rate changes under three other methods—cost-of-service, competitive market showings and agreements between shippers and the oil pipeline company that the rate is acceptable, or Settlement Rates. The pipeline tariff rates on our Mississippi, Jay, Texas and Louisiana systems are either rates that are subject to change under the index methodology or Settlement Rates. None of our tariffs have been subjected to a protest or complaint by any shipper or other interested party.

Our offshore pipelines, with the exception of our Eugene Island pipeline and HIOS, are neither interstate nor common carrier pipelines. However, these pipelines are subject to federal regulation under the Outer Continental Shelf Lands Act, which requires all pipelines operating on or across the outer continental shelf to provide nondiscriminatory transportation service.

Our intrastate common carrier pipeline operations in Texas are subject to regulation by the TXRRC. The applicable Texas statutes require that pipeline rates and practices be reasonable and non-discriminatory and that pipeline rates provide a fair return on the aggregate value of the property of a common carrier, after providing reasonable allowance for depreciation and other factors and for reasonable operating expenses. Although no assurance can be given that the tariffs we charge would ultimately be upheld if challenged, we believe that the tariffs now in effect can be sustained.

Marine Regulations

The operation of towboats, tugboats, barges, vessels and marine equipment create maritime obligations involving property, personnel and cargo and are subject to regulation by the U.S. Coast Guard, or USCG, the Environmental Protection Agency, or EPA, the Department of Homeland Security, or DHS, federal laws, state laws and certain international conventions under General Maritime Law. These obligations can create risks which are varied and include, among other things, the risk of collision and allision, which may precipitate claims for personal injury, cargo, contract, pollution, third-party claims and property damages to vessels and facilities. Routine towage operations can also create risk of personal injury under the Jones Act and General Maritime Law, cargo claims involving the quality of a product and delivery, terminal claims, contractual claims and regulatory issues. Federal regulations also require that all tank barges engaged in the transportation of oil and petroleum in the U.S. be double hulled. All of our barges are double-hulled.

All of our barges are inspected by the USCG and carry certificates of inspection. All of our towboats and tugboats are certificated by the USCG. Most of our vessels are built to American Bureau of Shipping, or ABS, classification standards and in some instances are inspected periodically by ABS to maintain the vessels in class standards. The crews we employ aboard vessels, including captains, pilots, engineers, tankermen and ordinary seamen, are documented by the USCG.

We are required by various governmental agencies to obtain licenses, certificates and permits for our vessels depending upon such factors as the cargo transported, the waters in which the vessels operate and other factors. We are of the opinion that our vessels have obtained and can maintain all required licenses, certificates and permits required by such governmental agencies for the foreseeable future.

Jones Act: The Jones Act is a federal law that restricts maritime transportation between locations in the U.S. to vessels built and registered in the U.S. and owned and manned by U.S. citizens. We are responsible for monitoring the ownership of our subsidiary that engages in maritime transportation and for taking any remedial action necessary to ensure that no violation of the Jones Act ownership restrictions occurs. Jones Act requirements significantly increase operating costs of U.S.-flag vessel operations compared to foreign-flag vessel operations. Further, the USCG and ABS maintain the most stringent regime of vessel inspection in the world, which tends to result in higher regulatory compliance costs for U.S.-flag operators than for owners of vessels registered under foreign flags or flags of convenience. The Jones Act and General Maritime Law also provide damage remedies for crew members injured in the service of the vessel arising from employer negligence or vessel unseaworthiness.

Merchant Marine Act of 1936: The Merchant Marine Act of 1936 is a federal law providing that, upon proclamation by the President of the U.S. of a national emergency or a threat to the national security, the U.S. Secretary of Transportation may requisition or purchase any vessel or other watercraft owned by U.S. citizens (including us, provided that we are considered a U.S. citizen for this purpose). If one of our tow boats or barges were purchased or requisitioned by the U.S. government under this law, we would be entitled to be paid the fair market value of the vessel in the case of a purchase or, in the case of a requisition, the fair market value of charter hire. However, if one of our tow boats is requisitioned or purchased and its associated barge or barges are left idle, we would not be entitled to receive any compensation for the lost revenues resulting from the idled barges. We also would not be entitled to be compensated for any consequential damages we suffer as a result of the requisition or purchase of any of our tow boats or barges.

Security Requirements: The Maritime Transportation Security Act of 2002 requires, among other things, submission to and approval by the USCG of vessel and waterfront facility security plans, or VSP. Our VSP’s have been approved and we are operating in compliance with the plans for all of its vessels and that are subject to the requirements, whether engaged in domestic or foreign trade.

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Railcar Regulation

We operate a number of railcar unloading facilities and lease a significant number of railcars. Our railcar operations are subject to the regulatory jurisdiction of the Federal Railroad Administration of the DOT, the Occupational Safety and Health Administration, or OSHA, as well as other federal and state regulatory agencies. We believe that our railcar operations are in substantial compliance with all existing federal, state and local regulations.

DOT and OSHA have jurisdiction under several federal statutes over a number of safety and health aspects of rail operations, including the transportation of hazardous materials. State agencies regulate some aspects of rail operations with respect to health and safety in areas not otherwise preempted by federal law.

Environmental Regulations

General - We are subject to stringent federal, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. These laws and regulations may (i) require the acquisition of and compliance with permits for regulated activities, (ii) limit or prohibit operations on environmentally sensitive lands such as wetlands or wilderness area, seismically sensitive areas, or areas inhabited by endangered or threatened species, (iii) result in capital expenditures to limit or prevent emissions or discharges, and (iv) place burdensome restrictions on our operations, including the management and disposal of wastes. 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. Changes in environmental laws and regulations occur frequently, typically increasing in stringency through time, and any changes that result in more stringent and costly operating restrictions, emission control, waste handling, disposal, cleanup and other environmental requirements have the potential to have a material adverse effect on our operations. While we believe that we are in substantial compliance with current environmental laws and regulations and that continued compliance with existing requirements will 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.

Hazardous Substances and Waste Handling - The Comprehensive Environmental Response, Compensation, and Liability Act, as amended, or CERCLA, also known as the “Superfund” law, and analogous state laws impose liability, without regard to fault or the legality of the original conduct, on certain classes of persons. These persons include current owners and operators of the site where a release of hazardous substances occurred, prior owners or operators that owned or operated the site at the time of the release of hazardous substances, and companies that disposed or arranged for the disposal of the hazardous substances found at the site. We currently own or lease, and have in the past owned, operated or leased, properties that have been in use for many years with the gathering and transportation of hydrocarbons including crude oil and other activities that could cause an environmental impact. Persons deemed “responsible persons” under CERCLA may be subject to strict and joint and several liability for the costs of removing or remediating previously disposed wastes (including wastes disposed of or released by prior owners or operators) or property contamination (including groundwater contamination), for damages to the environment, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment and to seek to recover the costs they incur from the responsible classes of persons. It is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by hazardous substances or other pollutants released into the environment.

We also may incur liability under the Resource Conservation and Recovery Act, as amended, or RCRA, and analogous state laws which impose requirements and also liability relating to the management and disposal of solid and hazardous wastes. While RCRA regulates both solid and hazardous wastes, it imposes strict requirements on the generation, storage, treatment, transportation and disposal of hazardous wastes. Certain petroleum production wastes are excluded from RCRA’s hazardous waste regulations. However, it is possible that these wastes, which could include wastes currently generated during our operations, will in the future be designated as “hazardous wastes” and, therefore, be subject to more rigorous and costly disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain crude oil and natural gas exploration and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. However, in April 2019, the EPA concluded that revisions to the federal regulations for the management of oil and gas waste are not necessary at this time. Any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

We believe that we are in substantial compliance with the requirements of CERCLA, RCRA and related state and local laws and regulations, and that we hold all necessary and up-to-date permits, registrations and other authorizations required under such laws and regulations. Although we believe that the current costs of managing our wastes as they are presently

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classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Water Discharges - The Federal Water Pollution Control Act, as amended, also known as the “Clean Water Act,” and analogous state laws impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including crude oil, into navigable waters of the U.S., as well as state waters. Permits must be obtained to discharge pollutants into these waters. Spill prevention, control and countermeasure plan requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit.

The scope of waters regulated under the Clean Water Act has fluctuated in recent years. On June 29, 2015, the EPA and the U.S. Army Corps of Engineers, or Corps, jointly promulgated final rules expanding the scope of waters protected under the Clean Water Act. However, on October 22, 2019, the agencies repealed the 2015 rules, and then, on April 21, 2020, the EPA and the Corps published a final rule replacing the 2015 rules, and significantly reducing the waters subject to federal regulation under the Clean Water Act. On August 30, 2021, a federal court struck down the replacement rule and, on January 18, 2023, the EPA and the Corps published a final rule that would restore water protections that were in place prior to 2015. However, on May 25, 2023, the Supreme Court issued an opinion substantially narrowing the scope of “waters of the United States” protected by the Clean Water Act. On September 8, 2023, the EPA and the Corps published a final conforming rule. On November 20, 2025, the U.S. Department of the Army and EPA jointly proposed a revision to the “waters of the United States” definition, following the Supreme Court’s 2023 Sackett v. EPA decision, which would further narrow the scope of activities subject to federal regulation under the Clean Water Act. However, to the extent the EPA and the Corps broadly interpret their jurisdiction and expand the range of properties subject to the Clean Water Act's jurisdiction, including under future administrations, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas.

Also, on June 28, 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. In addition, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. These permits may require us to monitor and sample the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.

The Oil Pollution Act is the primary federal law for oil spill liability. The Oil Pollution Act contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The Oil Pollution Act subjects owners of facilities to strict liability that, in some circumstances, may be joint and several for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.

Noncompliance with the Clean Water Act or the Oil Pollution Act may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with each of these requirements.

Air Emissions - The Federal Clean Air Act, or CAA, as amended, and analogous state and local laws and regulations restrict the emission of air pollutants, and impose permit requirements and other obligations. Regulated emissions occur as a result of our operations, including the handling or storage of crude oil and other petroleum products. Both federal and state laws impose substantial penalties for violation of these applicable requirements. Accordingly, our failure to comply with these requirements could subject us to monetary penalties, injunctions, conditions or restrictions on operations, revocation or suspension of necessary permits and, potentially, criminal enforcement actions.

On August 16, 2012, the EPA published final regulations under the CAA that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rules seek to achieve a 95% reduction in volatile organic compounds emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured wells constructed or refractured after January 1, 2015. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. The EPA received numerous requests for reconsideration of these rules from both industry and the environmental community, and court challenges to the rules were also filed. In response, the EPA has issued, and will likely continue to issue, revised rules responsive to some of the requests for reconsideration. In particular, on May 12, 2016, the EPA amended its regulations to impose new standards for methane and volatile organic compounds emissions for certain new,

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modified, and reconstructed equipment, processes, and activities across the oil and natural gas sector. However, on August 13, 2020, in response to an executive order by President Trump during his first term to review and revise unduly burdensome regulations, the EPA amended the 2012 and 2016 New Source Performance standards to ease regulatory burdens, including rescinding standards applicable to transmission or storage segments and eliminating methane requirements altogether. On June 30, 2021, former President Biden signed into law a joint resolution of Congress disapproving the 2020 amendments (with the exception of some technical changes) thereby reinstating the 2012 and 2016 New Source Performance standards. The EPA expects owners and operators of regulated sources to take “immediate steps” to comply with these standards. Additionally, on December 2, 2023, the EPA announced a final rule that would expand and strengthen emission reduction requirements for both new and existing sources in the oil and natural gas industry by requiring increased monitoring of fugitive emissions, imposing new requirements for pneumatic controllers and tank batteries, and prohibiting venting of natural gas in certain situations. On April 17, 2023, the EPA agreed in a consent decree to issue a proposed rule by December 10, 2024 that either revises its emission standards for hazardous air pollutants from oil and natural gas production activities or determines that no revision is necessary. These laws and regulations, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions. On March 8, 2024, the EPA published a final rule revising the New Source Performance standards regulating GHG and volatile organic compound (VOC) emissions from oil and gas sources.

National Environmental Policy Act - Under the National Environmental Policy Act, or NEPA, a federal agency, commonly in conjunction with a current permittee or applicant, may be required to prepare an environmental assessment or a detailed environmental impact statement before taking any major action, including issuing a permit for a pipeline extension or addition that would affect the quality of the environment. Should an environmental impact statement or environmental assessment be required for any proposed pipeline extensions or additions, NEPA may prevent or delay construction or alter the proposed location, design or method of construction.

Endangered Species Act - The federal Endangered Species Act and analogous state statutes restrict activities that may adversely affect endangered and threatened species or their habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The designation of previously unidentified endangered or threatened species in areas and/or the designation of critical habitats or other protected lands where we operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans.

Climate Change - In December 2009, the EPA published its findings that emissions of carbon dioxide, methane and other greenhouse gases (“GHGs”) present an endangerment to human health and the environment because emissions of such gases are, according to the EPA, contributing to the warming of the earth’s atmosphere and other climatic changes. Accordingly, in recent years, federal, state, and local governments have taken steps to reduce emissions of GHGs. On August 16, 2022, President Biden signed into law the Inflation Reduction Act (“IRA”), which, along with the Investment in Infrastructure and Jobs Act, provides billions of dollars in incentives for the development of renewable energy, clean hydrogen, clean fuels, electric vehicles, investments in advanced biofuels and supporting infrastructure and carbon capture and sequestration. These incentives could accelerate the transition of the economy away from the use of fossil fuels towards lower or zero-carbon emissions alternatives, which could decrease demand for, and in turn the prices of, the oil and natural gas that we store, transport and sell and adversely impact our business. However, certain provisions of the IRA, including clean energy tax credits, were repealed by the One Big Beautiful Bill Act, which was signed into law on July 4, 2025. In August 2025, the EPA published a proposed rule to rescind its “endangerment” finding regarding GHGs.

The EPA has also finalized a series of GHG monitoring, reporting and emission control rules for the oil and natural gas industry, and almost half of the states, either individually or through multi-state regional initiatives, have 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. The net effect of this regulatory regime is to impose increasing costs on the combustion of carbon-based fuels such as crude oil, refined petroleum products and natural gas. Our compliance with any future legislation or regulation of GHGs, if adopted, 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. On April 21, 2021, the United States announced that it was setting an economy-wide target of reducing its GHG 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 GHG emissions, including reducing global methane emissions by at least 30% by 2030 from 2020 levels. More than 150 countries have now signed on to this pledge. The urgency to reduce GHG emissions was

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further emphasized in the 27th Conference of the Parties (COP-27) in Sharm El-Sheikh, Egypt. At the 28th Conference of the Parties (COP-28) in the United Arab Emirates, world leaders agreed to transition away from fossil fuels in a just, orderly and equitable manner and to triple renewables and double energy efficiency globally by 2030. Also at COP-28, 50 companies accounting for 40 percent of global oil production committed to eliminating their methane emissions by 2050 under the Oil and Gas Decarbonization Charter. These companies also committed to ending flaring by 2030. Furthermore, many state and local leaders have stated their intent to intensify efforts to support the international climate commitments. The United States withdrew from the Paris Agreement and any similar commitments under the United Nations Framework Convention on Climate Change on January 20, 2025.

Legislative efforts or related implementation regulations that 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 fees or 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.

Furthermore, there have been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. In addition, claims have been made against certain energy companies alleging that GHG emissions from crude oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages, or other liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could adversely impact our business, financial condition and results of operations.

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.

Safety and Security Regulations

Our crude oil pipelines are subject to construction, installation, operation and safety regulation by the U.S. Department of Transportation (“DOT”) Pipeline and Hazardous Materials Safety Administration, or PHMSA, and various other federal, state and local agencies under various provisions of Title 49 of the United States Code and comparable state statutes. Congress has enacted several pipeline safety acts over the years. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (the “Pipeline Safety Act”) provides for regulation of the nation’s pipelines, penalties for violations of pipeline safety rules, and other DOT matters. The Pipeline Safety Act currently provides for significant financial penalties involving non-compliance with DOT regulations. In addition, the Pipeline Safety Act includes additional safety requirements for newly constructed pipelines. In June 2016, Congress approved new pipeline safety legislation, the “Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016,” or the 2016 PIPES Act, which provides the PHMSA with additional authority to address imminent hazards by imposing emergency restrictions, prohibitions, and safety measures on owners and operators of gas or hazardous liquids pipeline facilities. In December 2020, the “Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020,” or the 2020 PIPES Act, was signed into law. The 2020 PIPES Act extends the PHMSA’s statutory mandate through 2023. It continues the legislative mandates that were established in the 2016 PIPES Act and creates new regulatory mandates, including, among other things: (i) requiring regulations prescribing the applicability of pipeline safety requirements to idled natural gas transmission and hazardous liquids pipelines; (ii) the creation of new leak detection and repair programs that impact certain natural gas gathering, transmission, and distribution lines; and (iii) necessitating updates to gas pipeline and hazardous liquid pipeline facility inspection and maintenance plans.

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The PHMSA administers pipeline safety requirements for natural gas and hazardous liquid pipelines pursuant to detailed regulations set forth in 49 C.F.R. Parts 190 to 199. These regulations, among other things, address pipeline integrity management and pipeline operator qualification rules and specify how companies should assess, evaluate, validate and maintain the integrity of pipeline segments that, in the event of a release, could impact High Consequence Areas, or HCAs, which include populated areas, unusually sensitive areas and commercially navigable waterways. We are subject to the PHMSA Integrity Management, or IM, regulations, which require that we perform baseline assessments of all pipelines that could affect an HCA, and to continually assess all pipelines at specified intervals to periodically evaluate the integrity of each pipeline segment that could affect an HCA. The integrity of these pipelines must be assessed by internal inspection, pressure test, or equivalent alternative new technology. We must also abide by an Integrity Management Plan, or IMP, that details the risk assessment factors, the overall risk rating for each segment of pipe, a schedule for completing the integrity assessment, the methods to assess pipeline integrity, and an explanation of the assessment methods selected. No assurance can be given that the cost of testing and the required rehabilitation identified will not be material costs to us that may not be fully recoverable by tariff increases.

The PHMSA has issued a number of rulemakings in response to the Pipeline Safety Act, the 2016 PIPES Act, and the 2020 PIPES Act, as well as prior statutes, concerning pipeline safety that impact our pipeline facilities. Over the past several years, the PHMSA adopted additional regulations for natural gas and hazardous liquid pipeline safety. In particular, on October 1, 2019, the PHMSA published final rules to expand its IM requirements and impose new pressure testing requirements on regulated pipelines, including certain segments outside HCAs that became effective on July 1, 2020. Among other things, the rules require all hazardous liquid pipelines in or affecting an HCA to be capable of accommodating in-line inspection tools within the next 20 years. In addition, the final rule imposes inspection requirements on pipelines in areas affected by extreme weather events and natural disasters, such as hurricanes, landslides, floods, earthquakes, or other similar events that are likely to damage infrastructure. The rules also extend reporting requirements to certain previously unregulated hazardous liquid gravity and rural gathering lines. Many of the requirements will be phased in over an extended compliance schedule. Also, on November 15, 2021, the PHMSA published a final rule extending reporting requirements to all onshore gas gathering operators and establishing a set of minimum safety requirements for certain gas gathering pipelines with large diameters and high operating pressures. On December 27, 2021, the PHMSA published an Interim Final Rule that designates the Great Lakes, coastal beaches, and marine coastal waters as “Unusually Sensitive Areas,” extending more stringent IMP requirements to hazardous liquid pipelines near such areas. Additional final rules were announced in 2022, including a final rule regarding the installation of rupture-mitigation valves, published on April 8, 2022. Further, on August 24, 2022, the PHMSA published a final rule strengthening integrity management requirements for onshore gas transmission lines, bolstering corrosion control standards and repair criteria, and imposing new requirements for inspections after extreme weather events. On January 17, 2025, PHMSA issued a final rule, to be effective 180 days after the date of publication in the Federal Register, to improve public safety and reduce methane and other flammable toxic or corrosive gases emissions from new and existing offshore gas gathering pipelines, regulated onshore gas pipelines, underground natural gas storage facilities, and liquefied natural gas facilities by modifying the leak detection performance standard to accommodate commercially available advanced technology used for detecting leaks, improving specificity for grading leaks and changing the leak repair timelines and leak survey intervals inside buildings.

Significant expenses could be incurred in the future if additional safety measures are required or if safety standards are raised and exceed the current pipeline control system capabilities.

We have developed a Risk Management Plan required by the PHMSA as part of our IMP. This plan is intended to minimize the offsite consequences of catastrophic spills. As part of this program, we have developed a mapping program. This mapping program identified HCAs and unusually sensitive areas along the pipeline right-of-ways in addition to mapping of shorelines to characterize the potential impact of a spill of crude oil on waterways.

Our crude oil, refined products and soda and sulfur services operations are also subject to the requirements of OSHA and comparable state statutes. Various other federal and state regulations require that we train all operations employees in Hazardous Communication (“HAZCOM”) and disclose information about the hazardous materials used in our operations. Certain information must be reported to employees, government agencies and local citizens upon request.

In most cases, states are responsible for enforcing the federal regulations and more stringent state pipeline regulations and inspection with respect to intrastate hazardous liquids pipelines, including crude oil and natural gas pipelines. In practice, states vary considerably in their authority and capacity to address pipeline safety. The Railroad Commission recently updated its pipeline safety regulations consistent with PHMSA requirements, effective September 13, 2021. We do not anticipate any significant problems in complying with applicable state laws and regulations in those states in which we operate.

Our trucking operations are licensed to perform both intrastate and interstate motor carrier services. As a motor carrier, we are subject to certain safety regulations issued by the DOT. The trucking regulations cover, among other things, driver operations, log book maintenance, truck manifest preparations, safety placard placement on the trucks and trailer vehicles, drug and alcohol testing, operation and equipment safety and many other aspects of truck operations. We are also subject to OSHA with respect to our trucking operations.

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The USCG regulates occupational health standards related to our marine operations. Shore-side operations are subject to the regulations of OSHA and comparable state statutes. The Maritime Transportation Security Act requires, among other things, submission to and approval of the USCG of vessel security plans.

Since the terrorist attacks of September 11, 2001, the U.S. Government has issued numerous warnings that energy assets could be the subject of future terrorist attacks. We have instituted security measures and procedures in conformity with federal guidance. We will institute, as appropriate, additional security measures or procedures indicated by the federal government. None of these measures or procedures should be construed as a guarantee that our assets are protected in the event of a terrorist attack.

On May 27, 2021, the Department of Homeland Security’s Transportation Security Administration (“TSA”) announced Security Directive Pipeline-2021-01 that requires us, as a critical pipeline owner, to report confirmed and potential cybersecurity incidents to the DHS Cybersecurity and Infrastructure Security Agency (“CISA”) and to designate a Cybersecurity Coordinator. It also requires us and the third-party operators of our assets to review current practices as well as to identify any gaps and related remediation measures to address cyber-related risks and report the results to TSA and CISA within 30 days. We designated a Cybersecurity Coordinator, developed a plan to comply with mandatory reporting timeframes and completed the vulnerability assessment required under this directive in 2021. On July 20, 2021, the TSA issued a second Security Directive. Then, on July 27, 2022, a third TSA-issued Security Directive took effect. We have evaluated the impacts of the TSA security directives, including as these directives continue to be updated and renewed, on our pipeline business and have made significant progress in compliance. See “Compliance with and changes in cybersecurity requirements has 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.”

Available Information

We make available free of charge on our internet website (www.genesisenergy.com) our Annual Report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934 as soon as reasonably practicable after we electronically file the material with, or furnish it to, the SEC. These documents are also available at the SEC’s website (www.sec.gov). Additionally, on our internet website we make available our Corporate Governance Guidelines, Code of Business Conduct and Ethics, Audit Committee Charter and Governance, Compensation and Business Development Committee Charter. Information on our website is not incorporated into this Form 10-K or our other securities filings and is not a part of this Form 10-K or our other securities filings.

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 after the establishment of cash reserves and payment of fees and expenses to pay the current level of quarterly distributions.

•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, 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, natural gas, refined petroleum products, NaHS 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.

•The IRA could accelerate the transition to a low carbon economy away from oil and natural gas.

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•Inflationary pressures and associated changes in monetary policy have increased and may further increase our operating costs, which in turn have caused and may continue to cause our capital expenditures and operating costs to rise.

•Non-traditional investment criteria used by many investors may diminish investor interest in us and reduce the value of our common units and our access to capital.

Risks Related to Legal and Regulatory Compliance

•Our operations are subject to federal and state rate regulation and 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.

•Compliance with and changes in cybersecurity requirements have a cost impact on our business.

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.

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.

•We cannot predict the impact of international military conflicts and the related humanitarian crisis or other geopolitical tensions on the global economy, energy markets, geopolitical stability and our business.

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

•Artificial intelligence presents risks and challenges that can impact our business, including by posing security risks to our confidential information, proprietary information and personal data.

•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 growth through the development and acquisition of a wide range of midstream and other infrastructure 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 additional potential joint ventures, stand-alone projects and other transactions that we believe will present opportunities to realize synergies, increase our market position and, ultimately, increase distributions to our unitholders. A number of factors could adversely affect our ability to execute our growth strategy,

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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 after the establishment of cash reserves and payment of fees and expenses to pay the current level of quarterly distributions.

The amount of cash we distribute to our common unitholders 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 NaHS, that we produce and the prices at which we sell NaHS; 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 to our common unitholders will depend on other factors that include: our debt service requirements; distributions we pay to our Class A Convertible Preferred unitholders; the level of capital expenditures and costs associated with asset retirement obligations we may incur, including the cost of acquisitions (if any); 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 senior secured credit facility to pay distributions, and the amount of cash reserves required in the conduct of our business.

Our ability to pay distributions each quarter depends primarily on our cash flow, including cash flow from operations and our cash requirements, which includes capital expenditures amongst other items, and 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, NaHS and caustic soda) volumes, which often depend on actions and commitments by parties beyond our control.

We access commodity volumes through various sources, such as our 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, terminal, marine vessel transportation and railcar unloading operations) or we can acquire the commodity from our customer and resell it to another party.

Our source of volumes depends on successful exploration and development of additional crude oil and natural gas reserves by others; 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 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

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

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 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 many of our onshore pipeline locations, we are dependent on interconnections with other pipelines to provide shippers with a market for their crude oil. 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. Over the last three years, prices for crude oil ranged from a high of over $90 per barrel to a low of less than $60 per barrel, and such volatility, or even more 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

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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, natural gas, refined petroleum products, NaHS and caustic soda could adversely affect our business.

Because we purchase (or otherwise acquire) and sell crude oil, natural gas, refined petroleum products, NaHS, 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 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 reduced (in the event of under-utilization) or non-existent, 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 which requires us to pay the applicable lease rate without regard to utilization. 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, rail or our pipelines. As a result, we may experience declines in our profitability and margin 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 often include a governance structure that consists of a management committee or other governing body composed of members or member-designees, only some of which are appointed by us. In addition, certain of our joint ventures are operated by our “partners” or 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.

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 earnings and cash flow 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.

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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 performance and ability of third parties to satisfy their obligations under joint venture arrangements 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 term 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, 2025, our marine transportation segment received approximately 77% of its revenue from term 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 23% 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 could 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 cash flows from operations.

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 complete inland waterway system is composed of 25,000 miles of commercially navigable waterways and channels, supported by approximately 240 lock chambers and approximately 1,000 coastal, Great Lakes, and inland harbors. The U.S. inland waterway infrastructure is aging as approximately 80% of the lock and dam infrastructure exceeds its 50-year design life, which may cause more frequently scheduled and unscheduled maintenance outages and result in our marine transportation segment experiencing delays and incurring 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. For example, when the Mississippi river floods significantly or if water levels are significantly reduced by severe drought conditions, barges may be unable to traverse the river system and we may be prevented from timely completing our voyages.

Failure to obtain or renew surety bonds on acceptable terms could affect our ability to satisfy long-term obligations.

We are required to obtain surety bonds or post other financial security to secure performance or payment of certain long-term obligations. 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.

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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 potential to incur additional indebtedness. As of December 31, 2025, we had approximately $6.4 million outstanding under our senior secured credit facility and approximately $3.1 billion aggregate principal amount of senior unsecured notes outstanding. We must comply with various affirmative and negative covenants contained in our credit agreement and the indentures or purchase agreement 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, 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. Moreover, the need to dedicate a substantial portion of our cash flows from operations to payments on our indebtedness may similarly prevent us from engaging in certain transactions which might otherwise be considered beneficial to us and could have other important consequences to unitholders.