GEL · Read the filing

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

Introduction

We are a growth-oriented MLP formed in Delaware in 1996. Our common units are traded on the NYSE, under the ticker symbol “GEL.” We are a provider of an integrated suite of midstream services (primarily transportation, storage, sulfur removal, blending, terminaling and processing) for a large area of the Gulf of America and the Gulf Coast region of the crude oil and natural gas industry. We provide an integrated suite of services to crude oil and natural gas producers, refiners, and industrial and commercial enterprises and 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 operations also included the Alkali Business. We determined that the exit of the Alkali Business and its operations in Wyoming represented a strategic and geographic shift that met the criteria for discontinued operations. Accordingly, we have separately reported the operations from the Alkali Business in the Consolidated Statements of Operations and the related assets and liabilities of the Alkali Business in the Consolidated Balance Sheets as discontinued operations. These changes have been applied retrospectively to all periods presented.

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

•Overview of 2025 Results

•Recent Developments and Initiatives

•Results of Operations

•Other Consolidated Results

•Financial Measures

•Liquidity and Capital Resources

•Guarantor Summarized Financial Information

•Critical Accounting Estimates

Overview of 2025 Results

We reported Net Income from Continuing Operations of $30.5 million in 2025 compared to Net Loss from Continuing Operations of $50.8 million in 2024.

Net Income from Continuing Operations in 2025 was primarily impacted by an increase in operating income associated with our reportable segments, primarily related to our offshore pipeline transportation segment (see “Results of Operations” below for additional details). In addition, an impairment expense of $43.0 million was reported during 2024, whereas no impairment expense was reported in 2025 (see “Results of Operations” below for additional details). These impacts were partially offset by: (i) an increase in general and administrative expenses of $28.0 million primarily related to an increase in third-party transaction costs incurred associated with the sale of the Alkali Business on February 28, 2025; (see “Results of Operations” below for additional details); (ii) an increase in depreciation and amortization expense of $25.4 million (see “Results of Operations” below for additional details); and (iii) a decrease in equity in earnings of equity investees of $10.7 million.

We reported Net Loss from Discontinued Operations, net of tax of $423.7 million in 2025 and Net Income from Discontinued Operations, net of tax of $17.8 million in 2024 associated with the Alkali Business that was sold on February 28, 2025. Net Loss from Discontinued Operations, net of tax in 2025 was impacted by a loss of $432.2 million associated with the sale of the Alkali Business.

Cash flows from operating activities, which is inclusive of both our continuing and discontinued operations, were $252.8 million for 2025 compared to $391.9 million for 2024. This decrease was primarily attributable to negative changes in our working capital requirements during 2025 compared to 2024. In addition, cash flows provided by operating activities for 2025 only included two months of activity from the Alkali Business, as it was sold on February 28, 2025, whereas 2024 included a full year of activity from the Alkali Business.

Table of Contents

Available Cash before Reserves (as defined below in “Non-GAAP Financial Measures”) to our common unitholders was $149.1 million for 2025, a decrease of $10.3 million, or 6%, from 2024 primarily as a result of 2025 only including two months of activity from the Alkali Business, as it was sold on February 28, 2025, whereas 2024 included a full year of activity from the Alkali Business. Partially offsetting this decrease were primarily the following: (i) an increase in Segment Margin of $48.7 million in 2025 compared to 2024 from our continuing operations (which is further discussed below in “Results from Operations”); and (ii) a decrease in accumulated distributions to our Class A Convertible Preferred unitholders of $23.0 million. See “Financial Measures” below for additional information on Available Cash before Reserves.

Segment Margin was $577.9 million in 2025, an increase of $48.7 million, or 9%, as compared to 2024. We currently manage our businesses through three divisions that constitute our reportable segments - offshore pipeline transportation, marine transportation and onshore transportation and services. A more detailed discussion of our segment results and other costs is included below in “Results of Operations.”

Distributions to Unitholders

On February 13, 2026, we paid a distribution of $0.18 per common unit related to the fourth quarter of 2025. This represents a 9% increase in the quarterly distribution to common unitholders from the previous quarter.

With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.9473 per unit (or $3.7892 on an annualized basis). These distributions were paid on February 13, 2026 to unitholders holders of record at the close of business January 30, 2026.

Recent Developments and Initiatives

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 important 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 and the expansion of our existing CHOPS Pipeline.

•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 FPS, which also saw first production in the third quarter of 2025 and ties into our existing SEKCO Pipeline for further transportation downstream on our 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 a 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.

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 and constructing the SYNC Pipeline, a new 100% owned, approximately 105-mile, 20” diameter crude oil 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 GB-72 platform topside facilities, reconnection of the CHOPS Pipeline to the GB-72 platform, and the addition of pumps at both the 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. During the fourth quarter of 2025, we saw ramp up in volumes from Shenandoah to over 90 MBbls/day, which is in excess of the MVCs, while volumes from Salamanca reached over 30 MBbls/day during the fourth quarter of 2025 and continued to ramp up toward targeted production levels.

Table of Contents

These two new developments represent a significant step change for the future financial performance of our offshore pipeline transportation segment. Longer term, in addition to the production expected from these fields, we are well positioned to benefit from a growing inventory of future opportunities around these production facilities as well as around the remaining excess capacity available on our now expanded pipeline infrastructure. Combined with minimal future growth capital requirements, these new developments will serve as the cornerstone of our ability to generate increasing levels of free cash flow in the future.

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 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. The sale of the Alkali Business has allowed us to deleverage our balance sheet, and provide additional financial flexibility for us to focus on returning value to our capital structure.

Table of Contents

Results of Operations

In the discussions that follow, we will focus on our revenues, costs and expenses, as well as two measures that we use to manage the business and to review the results of our operations - Segment Margin and Available Cash before Reserves. Segment Margin and Available Cash before Reserves are defined in the “Financial Measures” section below.

Revenues, Costs and Expenses

Our revenues for the year ended December 31, 2025 decreased $30.4 million, or 2%, from the year ended December 31, 2024, and our costs and expenses (excluding the impairment expense in 2024) decreased $75.7 million, or 5%, between the two periods, with a net increase to operating income (excluding the impairment expense in 2024) of $45.3 million. The increase in our operating income during 2025 is primarily due to: (i) our offshore pipeline transportation segment as a result of the contractual MVCs on our 100% owned SYNC Pipeline and 64% owned CHOPS Pipeline associated with the Shenandoah deepwater development that began in June 2025; (ii) a subsequent ramp-up in production from the Shenandoah development in excess of the MVCs during the fourth quarter 2025; and (iii) an overall increase in volumes across our offshore pipeline transportation network (see further discussion below). These were partially offset by: (i) an increase in depreciation and amortization of $25.4 million during 2025 (see further discussion below); and (ii) an increase in general and administrative expenses of $28.0 million during 2025 (see further discussion below). See further discussion below under “Segment Margin” regarding the activity in our individual operating segments.

A substantial portion of our revenues and costs are derived from our onshore transportation and services segment, which includes the purchase and sale of crude oil in our crude oil marketing business as well as our other refinery-centric onshore operations. Additionally, our revenues and costs are derived from the operations within our offshore pipeline transportation segment and our marine transportation segment. We describe the impact on revenues and costs for each of our businesses in more detail below.

As it relates to our crude oil marketing business, the average closing prices for West Texas Intermediate crude oil on the New York Mercantile Exchange (“NYMEX”) decreased approximately 15% to $65.39 per barrel in 2025 as compared to $76.63 per barrel in 2024. We expect changes in crude oil prices to continue to proportionately affect our revenues and costs attributable to our purchase and sale of crude oil, resulting in a minimal direct impact on Net income (loss), Segment Margin and Available Cash before Reserves. We have limited our direct commodity price exposure in our crude oil operations through the broad use of fee-based service contracts, back-to-back purchase and sale arrangements and hedges. As a result, changes in the price of crude oil would proportionately impact both our revenues and our costs, with a disproportionately smaller impact on Net income (loss), Segment Margin and Available Cash before Reserves. However, we do have some indirect exposure to certain changes in prices for crude oil, particularly if they are significant and extended. We tend to experience more demand for certain of our services when prices increase significantly over extended periods of time, and we tend to experience less demand for certain of our services when prices decrease significantly over extended periods of time. For additional information regarding certain of our indirect exposure to commodity prices, see our segment-by-segment analysis below and the section of our Annual Report entitled “ Risks Related to Our Business.”

We also have revenues and costs associated with our other refinery-centric operations including our sulfur services business, which we believe is one of the largest producers and marketers of NaHS in North and South America, and from our other logistical assets including pipelines, trucks, terminals, and rail unloading facilities.

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. We own interests in various offshore crude oil and natural gas pipeline systems, platforms and related infrastructure and generate cash flows from fees to customers to utilize our assets. Our costs are primarily related to expenses incurred for the maintenance of our assets, employee compensation, and other operating costs.

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., primarily 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. Our revenues are driven by the demand for our barge services and associated utilization of our fleets, as well as the day rates we charge, which can be dependent upon market conditions (including supply and demand in the market), amongst other factors. Our costs are principally related to the costs required to maintain our fleets, employee compensation, and other operating costs.

Refiners are the shippers of a majority of the volumes transported on our onshore crude oil pipelines. Additionally, refiners contracted for the majority of the revenues from our marine transportation segment during 2025, which are used primarily to transport intermediate refined products (not crude oil) between refining complexes. Given these facts, we do not

Table of Contents

expect changes in commodity prices to impact our Net income (loss), Segment Margin or Available Cash before Reserves derived from our offshore crude oil and natural gas pipeline transportation and handling operations in the same manner in which they impact our revenues and costs derived from the purchase and sale of crude oil.

Additionally, changes in certain of our operating costs between the respective periods, such as those associated with our offshore pipeline transportation and marine transportation segments, are not directly correlated with crude oil prices. We discuss certain of those costs in further detail below in our segment-by-segment analysis.

Included below is additional detailed discussion of the results of our operations focusing on Segment Margin and other costs including general and administrative expenses, depreciation and amortization, impairment expense, interest expense, net, and income taxes.

Segment Margin

We define Segment Margin as revenues less product costs, operating expenses and segment general and administrative expenses (all of which are net of the effects of our noncontrolling interest holders), plus or minus applicable Select Items (defined below in “Non-GAAP Financial Measures”) from continuing operations. Although we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results. See “Non-GAAP Financial Measures” for further discussion surrounding total Segment Margin.

The contribution of each of our segments to total Segment Margin in each of the last three years was as follows:

Year Ended December 31,

(in thousands)

Table of Contents

Year Ended December 31, 2025 Compared with Year Ended December 31, 2024

Offshore Pipeline Transportation Segment

Operating results and volumetric data for our offshore pipeline transportation segment are presented below:

Year Ended December 31,

(in thousands)

Offshore natural gas pipeline revenue, excluding non-cash revenues 52,622 53,342

Offshore pipeline transportation Segment Margin $ 385,694 $ 332,786

Volumetric Data 100% basis:

Crude oil pipelines (average Bbls/day unless otherwise noted):

Natural gas transportation volumes (MMBtus/day) 400,540 385,330

Volumetric Data net to our ownership interest(4):

Crude oil pipelines (average Bbls/day unless otherwise noted):

Natural gas transportation volumes (MMBtus/day) 103,861 108,194

(1)The increase in operating costs are primarily related to an increase in costs associated with accommodating our higher level of volumes in 2025, such as fuel and drag reducing agent costs, which are often rebilled to the associated producers and do not have a significant impact to our Segment Margin.

(2)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2025 and 2024, respectively.

(3)One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or “GOPL”) owns our undivided interest in the Eugene Island pipeline system.

(4)Volumes are the product of our effective ownership interest throughout the year multiplied by the relevant throughput over the given year.

Table of Contents

Offshore pipeline transportation Segment Margin for 2025 increased $52.9 million, or 16%, from 2024, primarily due to: (i) the contractual MVCs on our 100% owned SYNC Pipeline and 64% owned CHOPS Pipeline associated with the deepwater Shenandoah development that began in June 2025 and a subsequent ramp-up in production from the Shenandoah development in excess of the MVCs during the fourth quarter 2025, and (ii) an increase to other MVCs on our 64% owned CHOPS Pipeline during 2025, including those related to the Warrior and Winterfell developments. Production volumes from the Shenandoah FPS are life-of-lease dedicated to our 100% owned SYNC Pipeline and further downstream to our 64% owned CHOPS Pipeline. The Shenandoah FPS achieved first oil production in late July 2025 and we have seen a ramp-up in volumes from the Shenandoah FPS to over 90 MBbls/day during the fourth quarter of 2025. Additionally, production from the Salamanca FPS, which ties into our existing SEKCO Pipeline for further transportation downstream on our Poseidon Pipeline, came on-line at the end of September. Production from the initial three wells has since ramped up to over 30 MBbls/day in December 2025. A fourth well is planned to be drilled and completed in the second quarter of 2026, with the potential for a fifth well to be drilled and completed as early as the fourth quarter of 2026, at which point Salamanca production levels are anticipated to approach 50 to 60 MBbls/day.

Partially offsetting these increases to Segment Margin were decreases primarily due to: (i) an economic step-down in the rate on a certain existing life-of-lease transportation dedication beginning in the third quarter of 2024 as we reached the 10-year anniversary of a certain existing life-of-lease dedication, which resulted in the contractual economic step-down of the associated transportation rate; and (ii) an increase in producer downtime in 2025 compared to 2024 as a result of several wells being shut in due to certain sub-sea operational and technical challenges that began in the second quarter of 2024 and continued to impact our production results for a majority of 2025. As of December 31, 2025, most of these mechanical issues were resolved by our producer customers.

Marine Transportation Segment

Within our marine transportation segment, we own a fleet of 87 barges (78 inland and 9 offshore) with a combined transportation capacity of 3.0 million barrels, 43 push/tow boats (33 inland and 10 offshore), and a 330,000 barrel capacity ocean going tanker, the M/T American Phoenix. Operating results for our marine transportation segment were as follows:

Year Ended December 31,

Revenues (in thousands):

Fleet Utilization:(2)

Inland Barge Utilization 95.2 % 98.8 %

Offshore Barge Utilization 95.4 % 97.7 %

(1) Under certain of our marine contracts, we “rebill” our customers for a portion of our operating costs.

(2) Utilization rates are based on a 365 day year, as adjusted for planned downtime and drydocking.

Marine Transportation Segment Margin for 2025 decreased $9.3 million, or 7%, from 2024. We experienced slightly lower utilization rates during 2025 in our inland business primarily due to a temporary decline in refinery utilization during the first quarter of 2025 and a decline in Midwest refinery demand for black oil equipment as a result of changing crude slates in the third quarter of 2025. This decrease in Segment Margin from our inland marine business was partially offset by an increase in Segment Margin from our offshore marine business primarily as a result of fewer dry-docking days in our offshore fleet. In addition, the M/T American Phoenix, which is under contract through mid-2027, benefited from a contractual rate increase during 2025 compared to 2024.

Table of Contents

Onshore Transportation and Services Segment

Our onshore transportation and services segment includes terminaling, blending, storing, and marketing of crude oil, and transporting of 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. Our onshore transportation and services segment utilizes an integrated set of pipelines, storage tanks, terminals, facilities, trucks and barges to facilitate the movement of crude oil and refined products on behalf of producers, refiners and other customers. This segment includes crude oil and refined products pipelines, terminals, rail unloading facilities, and refinery processing locations operating primarily within the U.S. Gulf Coast market. In addition, we utilize our trucking fleet that supports the purchase and sale of gathered and bulk-purchased crude oil as well as the sale and delivery of NaHS and NaOH (also known as caustic soda) to customers. Through these assets we offer our customers a full suite of services, including the following as of December 31, 2025:

•facilitating the transportation of crude oil and refined products from producers and from our terminals, as well as those owned by third parties, to refineries via pipelines and trucks;

•purchasing/selling and/or transporting, storing, and blending crude oil from the wellhead to markets for ultimate use in refining;

•purchasing products from refiners, transporting those products to one of our terminals and blending those products to a quality that meets the requirements of our customers, storing, and selling those products (primarily fuel oil, asphalt and other heavy refined products) to wholesale markets;

•unloading railcars at our crude-by-rail terminals;

•providing sulfur removal services from crude oil processing operations at refining or petrochemical processing facilities;

•operating storage and transportation assets in relation to our sulfur removal services; and

•selling NaHS and caustic soda to large industrial and commercial companies.

We also may use our terminal facilities to take advantage of contango market conditions for crude oil gathering and marketing and to capitalize on regional opportunities which arise from time to time for crude oil.

Despite crude oil being considered a somewhat homogeneous commodity, many refiners are very particular about the quality of crude oil feedstock they process. Many U.S. refineries have distinct configurations and product slates that require crude oil with specific characteristics, such as gravity, sulfur content and metals content. The refineries evaluate the costs to obtain, transport and process their preferred feedstocks. That particularity provides us with opportunities to help the refineries in our areas of operation identify crude oil sources and transport crude oil meeting their requirements. The imbalances and inefficiencies relative to meeting the refiners’ requirements may also provide opportunities for us to utilize our purchasing and logistical skills to meet their demands. The pricing in the majority of our crude oil purchase contracts contains a market price component and a deduction to cover the cost of transportation and to provide us with a margin. Contracts sometimes contain a grade differential which considers the chemical composition of the crude oil and its appeal to different customers. Typically, the pricing in a contract to sell crude oil will consist of the market price components and the grade differentials. The margin on individual transactions is then dependent on our ability to manage our transportation costs and to capitalize on grade differentials.

Table of Contents

Operating results for our onshore transportation and services segment were as follows:

Year Ended December 31,

(in thousands)

Gathering, marketing, and logistics revenue $ 529,335 $ 669,248

Crude oil pipeline tariffs and revenues 27,677 25,350

Sulfur services revenues, excluding non-cash revenues 142,888 155,977

Operating costs, excluding non-cash expenses (175,327) (186,762)

Volumetric Data (average Bbls/day unless otherwise noted):

Onshore crude oil pipelines:

NaOH (caustic soda) volumes (DST sold) 36,226 40,108

(1)Total daily volumes for the years ended December 31, 2025 and 2024 include 21,348 and 19,298 Bbls/day, respectively, of intermediate refined products and 27,753 and 36,046 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines.

Segment Margin for our onshore transportation and services segment increased $5.1 million, or 7%, in 2025 as compared to 2024. The increase is primarily due to an increase in the rail unload volumes at our Scenic Station facility and an overall increase in volumes on our onshore crude oil pipeline systems principally driven by an increase in volumes on our Texas pipeline system, which is a key destination point for various grades of crude oil produced in the Gulf of America including those transported on our 64% owned CHOPS Pipeline.

In our sulfur services business we experienced a decline in NaHS and NaOH sales volumes in 2025 as compared to 2024. Despite the decrease in sales volumes, we saw a slight increase in Segment Margin in 2025 primarily due to operational and logistical cost improvements as well as an improvement to our NaHS sales mix.

Table of Contents

Other Costs, Interest and Income Taxes

General and administrative expenses

Year Ended December 31,

(in thousands)

General and administrative expenses not separately identified below:

Long-term incentive based compensation plan expense 12,975 2,857

Total general and administrative expenses $ 86,339 $ 58,329

Total general and administrative expenses increased $28.0 million between 2025 and 2024. This increase is primarily due to: (i) the increase in third party costs related to business development activities and growth projects as a result of the transaction costs incurred associated with the sale of the Alkali Business on February 28, 2025; and (ii) how we valued the outstanding long-term incentive compensation awards in each period. This increase was partially offset by a reduction in corporate general and administrative expenses as a result of 2024 experiencing higher costs as a result of us conforming our short-term cash incentive programs to industry standards at that time.

Depreciation and amortization expense

Year Ended December 31,

(in thousands)

Total depreciation and amortization expense $ 232,072 $ 206,686

Total depreciation and amortization expense increased $25.4 million between 2025 and 2024. This increase is primarily attributable to our continued growth and maintenance capital expenditures and placing new assets into service, including assets associated with our CHOPS expansion project and SYNC Pipeline, subsequent to the period ended December 31, 2024.

Impairment expense

In the fourth quarter of 2024, we terminated an on-going project related to the integration of certain of our corporate enterprise resource planning systems and we impaired the costs incurred to date. As a result, we recognized an impairment charge of $43.0 million. We did not record any impairment expense for the year ended December 31, 2025.

Interest expense, net

Year Ended December 31,

(in thousands)

Amortization of debt issuance costs, premium and discount 9,758 11,067

Interest expense, net increased $2.9 million between 2025 and 2024 primarily due to a decrease in capitalized interest in 2025, which is primarily attributable to the completion of the CHOPS expansion project and the SYNC Pipeline subsequent to 2024. This increase in interest expense, net was partially offset by a decrease in interest expense associated with our senior unsecured notes and a decrease in interest expense associated with our senior secured credit facility. The decrease in interest expense associated with our senior unsecured notes was primarily related to the redemption of our 2027 Notes on April 3, 2025. The decrease in interest expense, net associated with our senior secured credit facility during 2025 was primarily a result of a reduction in the average borrowings outstanding during the period compared to 2024.

Table of Contents

Income tax expense

A portion of our operations are owned by wholly-owned corporate subsidiaries that are taxable as corporations. As a result, a substantial portion of the income tax expense we record relates to the operations of those corporations, and will vary from period to period as a percentage of our income before taxes based on the percentage of our income or loss that is derived from those corporations. The balance of the income tax expense we record relates to state taxes imposed on our operations that are treated as income taxes under generally accepted accounting principles and foreign income taxes.

Other Consolidated Results

Net Income from Continuing Operations for the year ended December 31, 2025 included a loss of $9.8 million associated with the following: (i) a net loss of $8.9 million associated with the redemption premium and the write-off of the related unamortized debt issuance costs and premium on the remaining $406.2 million of 2027 Notes that were redeemed in the year; and (ii) a net loss of $0.8 million associated with the write-off of unamortized credit facility issuance costs as a result of the Second Amendment to our credit agreement. These amounts are included within “Other expense” on the Consolidated Statement of Operations.

Net Loss from Continuing Operations for the year ended December 31, 2024 included a net loss of $15.4 million associated with the following: (i) a net loss of $14.0 million associated with the tender fee and write-off of the related unamortized debt issuance costs and premium on the initial $575.0 million of our 2027 Notes that were tendered and redeemed in the year; and (ii) a loss of $1.4 million from the write-off of the unamortized issuance costs associated with the redemption of our 6.250% senior unsecured notes due May 15, 2026 (the “2026 Notes”). These amounts are included within “Other expense” on the Consolidated Statement of Operations.

Table of Contents

Year Ended December 31, 2024 Compared with Year Ended December 31, 2023

Offshore Pipeline Transportation Segment

Operating results and volumetric data for our offshore pipeline transportation segment are presented below:

Year Ended December 31,

(in thousands)

Offshore natural gas pipeline revenue, excluding non-cash revenues 53,342 59,408

Offshore pipeline transportation Segment Margin $ 332,786 $ 406,672

Volumetric Data 100% basis:

Crude oil pipelines (average Bbls/day unless otherwise noted):

Natural gas transportation volumes (MMBtus/day) 385,330 401,976

Volumetric Data net to our ownership interest(3):

Crude oil pipelines (average Bbls/day unless otherwise noted):

Natural gas transportation volumes (MMBtus/day) 108,194 113,848

(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting in 2024 and 2023, respectively.

(2)One of our wholly-owned subsidiaries, GOPL, owns our undivided interest in the Eugene Island pipeline system.

(3)Volumes are the product of our effective ownership interest throughout the year multiplied by the relevant throughput over the given year.

Offshore pipeline transportation Segment Margin for 2024 decreased $73.9 million, or 18%, from 2023, primarily due to: (i) an economic step-down in the rate on a certain existing life-of-lease transportation dedication; (ii) producer underperformance at several of our major host platforms; and (iii) an increase in operating costs. At the beginning of the third quarter of 2024, we reached the 10-year anniversary of a certain existing life-of-lease dedication, which resulted in the contractual economic step-down of the associated transportation rate. Additionally, during the second half of 2024, there was an increase in producer downtime as a result of several wells being shut in due to certain sub-sea operational and technical challenges. The production from these wells impacted our results as they are molecules that we touch multiple times throughout our oil and natural gas pipeline infrastructure.

Table of Contents

Marine Transportation Segment

Operating results for our marine transportation segment were as follows:

Year Ended December 31,

Revenues (in thousands):

Fleet Utilization:(2)

Inland Barge Utilization 98.8 % 100.0 %

Offshore Barge Utilization 97.7 % 98.1 %

(1) Under certain of our marine contracts, we “rebill” our customers for a portion of our operating costs.

(2) Utilization rates are based on a 365 day year, as adjusted for planned downtime and drydocking.

Marine Transportation Segment Margin for 2024 increased $14.6 million, or 13%, from 2023. This increase is primarily attributable to an increase in our overall day rates in our inland and offshore business, including the M/T American Phoenix, during 2024. The increase in day rates more than offset the impact to Segment Margin from the increased number of planned regulatory dry-docking days in our offshore fleet during 2024 as compared to 2023. In addition, we saw strong demand from our barge services to move intermediate and refined products keeping utilization rates high across both

periods. This strong demand from our customers as well as the lack of new supply of similar type vessels and the continued

retirement of older vessels in the market have contributed to the increase in day rates. The M/T American Phoenix started a new three-and-a-half year contract at the beginning of 2024 with a credit-worthy counterparty at the highest day rate we have received since we first purchased the vessel in 2014.

Table of Contents

Onshore Transportation and Services Segment

Operating results for our onshore transportation and services segment were as follows:

Year Ended December 31,

(in thousands)

Gathering, marketing, and logistics revenue $ 669,248 $ 699,482

Crude oil pipeline tariffs and revenues 25,350 26,654

Sulfur services revenues, excluding non-cash revenues 155,977 183,522

Operating costs, excluding non-cash expenses (186,762) (207,556)

Volumetric Data (average Bbls/day unless otherwise noted):

Onshore crude oil pipelines:

Rail unload volumes 13,500 —

NaOH (caustic soda) volumes (DST sold) 40,108 41,855

(1) Total daily volumes for the years ended December 31, 2024 and 2023 include 19,298 and 32,458 Bbls/day, respectively, of intermediate refined products and 36,046 and 33,019 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines.

Segment Margin for our onshore transportation and facilities segment decreased $1.8 million, or 3%, in 2024 as compared to 2023. The decrease is primarily due to lower NaHS sales volumes and pricing and an overall decrease in volumes on our onshore crude oil pipeline systems. In our sulfur services business, we faced challenges on the production side at our largest host refinery as well as continued pressures on demand in South America, including competitive pressures from Chinese flake, which had a negative impact on pricing during 2024. This decrease in Segment Margin was partially offset by an increase in the rail unload volumes at our Scenic Station facility.

Table of Contents

Other Costs and Interest

General and administrative expenses

Year Ended December 31,

(in thousands)

General and administrative expenses not separately identified below:

Long-term incentive based compensation plan expense 2,857 13,405

Total general and administrative expenses $ 58,329 $ 64,552

Total general and administrative expenses decreased $6.2 million, or 10%, between 2024 and 2023. The decrease is primarily due to the assumptions used to value the outstanding awards under our long-term incentive compensation plan during 2024 as compared to 2023. This decrease was partially offset by higher corporate general and administrative expenses as a result of us conforming our short-term cash incentive programs to industry standards during 2024.

Depreciation and amortization expense

Year Ended December 31,

(in thousands)

Total depreciation and amortization expense $ 206,686 $ 199,116

Total depreciation and amortization expense increased $7.6 million, or 4%, between 2024 and 2023. This increase is primarily attributable to our continued growth and maintenance capital expenditures and placing new assets into service. This increase was partially offset by an acceleration of depreciation on our asset retirement obligation assets as a result of updates to the estimated timing and costs associated with certain of our non-core offshore gas assets in 2023.

Impairment expense

Interest expense, net

Year Ended December 31,

(in thousands)

Amortization of debt issuance costs, premium and discount 11,067 8,775

Table of Contents

Interest expense, net increased $42.8 million, or 20%, between 2024 and 2023 primarily due to an increase in interest associated with our senior unsecured notes and senior secured credit facility. The increase in interest expense associated with our senior unsecured notes was primarily related to: (i) the issuance of our 8.250% senior unsecured notes due January 15, 2029, issued on December 7, 2023 in aggregate principal amount of $600.0 million (the “2029 Notes”), which have a higher principal and interest rate as compared to our 6.500% senior unsecured notes due October 1, 2025 (the “2025 Notes”) that were partially tendered in December 2023 and ultimately redeemed in January 2024; and (ii) the issuance of $700.0 million in aggregate principal amount of 7.875% senior unsecured notes due May 15, 2032 (the “2032 Notes”) in May 2024, which have a higher principal and interest rate as compared to our 2026 Notes that were redeemed in June 2024. The increase in interest expense associated with our senior secured credit facility is primarily due to higher average outstanding indebtedness during 2024 and an increase in the SOFR rate, which is one of the main components of our interest rate, compared to 2023.

This increase was partially offset by higher capitalized interest during 2024 as a result of our increased capital expenditures associated with our offshore growth capital construction projects during the year.

Other Consolidated Results

Net Income Continuing Operations for the year ended December 31, 2023 included a loss of $4.6 million associated with the tender and write-off of the unamortized issuance costs associated with the 2024 Notes and 2025 Notes, which is included within “Other expense” on the Consolidated Statement of Operations.

Non- GAAP Financial Measures

General

To help evaluate our business, this Annual Report on Form 10-K includes the non-generally accepted accounting principles (“non-GAAP”) financial measure of Available Cash before Reserves. We also present total Segment Margin as if it were a non-GAAP measure. Our non-GAAP measures may not be comparable to similarly titled measures of other companies because such measures may include or exclude other specified items. The accompanying schedules provide reconciliations of these non-GAAP financial measures to their most directly comparable financial measures calculated in accordance with generally accepted accounting principles in the United States of America (GAAP). A reconciliation of Income (loss) from continuing operations before income taxes to total Segment Margin is included in our segment disclosure in Note 14 to our Consolidated Financial Statements in Item 8. Our non-GAAP financial measures should not be considered (i) as alternatives to GAAP measures of liquidity or financial performance or (ii) as being singularly important in any particular context; they should be considered in a broad context with other quantitative and qualitative information. Our Available Cash before Reserves and total Segment Margin measures are just two of the relevant data points considered from time to time.

When evaluating our performance and making decisions regarding our future direction and actions (including making discretionary payments, such as quarterly distributions) our board of directors and management team have access to a wide range of historical and forecasted qualitative and quantitative information, such as our financial statements; operational information; various non-GAAP measures; internal forecasts; credit metrics; analyst opinions; performance, liquidity and similar measures; income; cash flow expectations for us; and certain information regarding some of our peers. Additionally, our board of directors and management team analyze, and place different weight on, various factors from time to time. We believe that investors benefit from having access to the same financial measures being utilized by management, lenders, analysts and other market participants. We attempt to provide adequate information to allow each individual investor and other external user to reach her/his own conclusions regarding our actions without providing so much information as to overwhelm or confuse such investor or other external user. Our non-GAAP financial measures should not be considered as an alternative to GAAP measures such as net income, operating income, cash flow from operating activities or any other GAAP measure of liquidity or financial performance.

Segment Margin

We define Segment Margin as revenues less product costs, operating expenses, and segment general and administrative expenses (all of which are net of the effects of our noncontrolling interest holders), plus or minus applicable Select Items (defined below) from our continuing operations. Although we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation

Table of Contents

of our core operating results. Our CODM evaluates segment performance based on a variety of measures including Segment Margin, segment volumes, and, where relevant, capital investment.

A reconciliation of Income (loss) from continuing operations before income taxes to total Segment Margin is included in our segment disclosure in Note 14 to our Consolidated Financial Statements in Item 8.

Available Cash before Reserves

Purposes, Uses and Definition

Available Cash before Reserves, often referred to by others as distributable cash flow, is a quantitative standard used throughout the investment community with respect to publicly-traded partnerships and is commonly used as a supplemental financial measure by management and by external users of financial statements such as investors, commercial banks, research analysts and rating agencies, to aid in assessing, among other things:

(1) the financial performance of our assets;

(2) our operating performance;

(3) the viability of potential projects, including our cash and overall return on alternative capital investments as compared to those of other companies in the midstream energy industry;

(4) the ability of our assets to generate cash sufficient to satisfy certain non-discretionary cash requirements, including interest payments and certain maintenance capital requirements; and

(5) our ability to make certain discretionary payments, such as distributions on our preferred and common units, growth capital expenditures, certain maintenance capital expenditures and early payments of indebtedness.

We define Available Cash before Reserves (“Available Cash before Reserves”) as Net income (loss) attributable to Genesis Energy, L.P. before interest, taxes, depreciation, and amortization (including impairment, write-offs, accretion and similar items) after eliminating other non-cash revenues, expenses, gains, losses and charges (including any loss on asset dispositions), plus or minus certain other select items that we view as not indicative of our core operating results (collectively, “Select Items”), as adjusted for certain items, the most significant of which in the relevant reporting periods have been the sum of maintenance capital utilized, interest expense, net, cash tax expense and cash distributions attributable to our Class A Convertible Preferred unitholders. Although we do not necessarily consider all of our Select Items to be non-recurring, infrequent or unusual, we believe that an understanding of these Select Items is important to the evaluation of our core operating results. The most significant Select Items in the relevant reporting periods are set forth below.

Year EndedDecember 31,

I. Applicable to all Non-GAAP Measures (in thousands)

Certain non-cash items:

II. Applicable only to Available Cash before Reserves

Table of Contents

(1)Represents the difference in timing of cash receipts from customers during the period and the revenue we recognize in accordance with GAAP on our related contracts. For purposes of our non-GAAP measures, we add those amounts in the period of payment and deduct them in the period in which GAAP recognizes them.

(2)2025 includes a loss of $8.9 million associated with the redemption premium and the write-off of the related unamortized debt issuance costs and premium on the remaining $406.2 million of 2027 Notes that were redeemed in 2025 and a net loss of $0.8 million associated with the write-off of unamortized credit facility issuance costs as a result of the Second Amendment to the credit agreement. 2024 includes a net loss of $14.0 million associated with the tender fee and write-off of the related unamortized debt issuance costs and premium on the initial $575.0 million of our 2027 Notes that were tendered and redeemed in 2024 and a loss of $1.4 million from the write-off of the unamortized issuance costs associated with our 2026 Notes that were redeemed during the year.

(3)Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.

(4)Represents Select Items applicable to Adjusted EBITDA and Available Cash before Reserves.

Disclosure Format Relating to Maintenance Capital

We use a modified format relating to maintenance capital requirements because our maintenance capital expenditures vary materially in nature (discretionary vs. non-discretionary), timing and amount from time to time. We believe that, without such modified disclosure, such changes in our maintenance capital expenditures could be confusing and potentially misleading to users of our financial information, particularly in the context of the nature and purposes of our Available Cash before Reserves measure. Our modified disclosure format provides those users with information in the form of our maintenance capital utilized measure (which we deduct to arrive at Available Cash before Reserves). Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period.

Maintenance Capital Requirements

Maintenance capital expenditures are capitalized costs that are necessary to maintain the service capability of our existing assets, including the replacement of any system component or equipment which is worn out or obsolete. Maintenance capital expenditures can be discretionary or non-discretionary, depending on the facts and circumstances.

Prior to 2014, substantially all of our maintenance capital expenditures were (a) related to our pipeline assets and similar infrastructure, (b) non-discretionary in nature and (c) immaterial in amount as compared to our Available Cash before Reserves measure. Those historical expenditures were non-discretionary (or mandatory) in nature because we had very little (if any) discretion as to whether or when we incurred them. We had to incur them in order to continue to operate the related pipelines in a safe and reliable manner and consistently with past practices. If we had not made those expenditures, we would not have been able to continue to operate all or portions of those pipelines, which would not have been economically feasible. An example of a non-discretionary (or mandatory) maintenance capital expenditure would be replacing a segment of an old pipeline because one can no longer operate that pipeline safely, legally and/or economically in the absence of such replacement.

Beginning with 2014, we believe a substantial amount of our maintenance capital expenditures from time to time will be (a) related to our assets other than pipelines, such as our marine vessels, trucks and similar assets, (b) discretionary in nature and (c) potentially material in amount as compared to our Available Cash before Reserves measure. Those expenditures will be discretionary (or non-mandatory) in nature because we will have significant discretion as to whether or when we incur them. We will not be forced to incur them in order to continue to operate the related assets in a safe and reliable manner. If we chose not make those expenditures, we would be able to continue to operate those assets economically, although in lieu of maintenance capital expenditures, we would incur increased operating expenses, including maintenance expenses. An example of a discretionary (or non-mandatory) maintenance capital expenditure would be replacing an older marine vessel with a new marine vessel with substantially similar specifications, even though one could continue to economically operate the older vessel in spite of its increasing maintenance and other operating expenses.

In summary, as we continue to expand certain non-pipeline portions of our business, we are experiencing changes in the nature (discretionary vs. non-discretionary), timing and amount of our maintenance capital expenditures that merit a more detailed review and analysis than was required historically. Management’s increasing ability to determine if and when to incur certain maintenance capital expenditures is relevant to the manner in which we analyze aspects of our business relating to discretionary and non-discretionary expenditures. We believe it would be inappropriate to derive our Available Cash before Reserves measure by deducting discretionary maintenance capital expenditures, which we believe are similar in nature in this context to certain other discretionary expenditures, such as growth capital expenditures, distributions/dividends and equity buybacks. Unfortunately, not all maintenance capital expenditures are clearly discretionary or non-discretionary in nature. Therefore, we developed a measure, maintenance capital utilized, that we believe is more useful in the determination of Available Cash before Reserves.

Table of Contents

Maintenance Capital Utilized

We believe our maintenance capital utilized measure is the most useful quarterly maintenance capital requirements measure to use to derive our Available Cash before Reserves measure. We define our maintenance capital utilized measure as that portion of the amount of previously incurred maintenance capital expenditures that we utilize during the relevant quarter, which would be equal to the sum of the maintenance capital expenditures we have incurred for each project/component in prior quarters allocated ratably over the useful lives of those projects/components.

Our maintenance capital utilized measure constitutes a proxy for non-discretionary maintenance capital expenditures and it takes into consideration the relationship among maintenance capital expenditures, operating expenses and depreciation from period to period. Because we did not use our maintenance capital utilized measure before 2014, our maintenance capital utilized calculations will reflect the utilization of solely those maintenance capital expenditures incurred since December 31, 2013.

Available Cash before Reserves for the years ended December 31, 2025 and 2024 was as follows:

Year Ended December 31,

(in thousands)

Net income (loss) attributable to Genesis Energy, L.P. $ (440,403) $ (63,947)

Impairment expense — 43,003

Distributions to preferred unitholders (64,546) (87,576)

Loss on disposal of discontinued operations 432,193 —

Other non-cash items from discontinued operations(2) 15,584 100,116

(1)Maintenance capital expenditures in 2025 and 2024 were $71.5 million and $94.6 million, respectively, which excludes maintenance capital expenditures of $4.6 million and $78.3 million in 2025 and 2024, respectively, associated with the Alkali Business that was sold on February 28, 2025. Our maintenance capital expenditures are principally associated with our marine transportation businesses.

(2)Includes non-cash items such as depreciation, depletion and amortization and unrealized gains or losses on derivative transactions, amongst other items.

Liquidity and Capital Resources

General

On May 9, 2024, we issued $700.0 million in aggregate principal amount of 7.875% senior unsecured notes due May 15, 2032 (the “2032 Notes”). Interest payments are due May 15 and November 15 of each year. The issuance of our 2032 Notes generated net proceeds of approximately $688 million, net of issuance costs incurred. The net proceeds were used to redeem all of our existing 6.25% senior unsecured notes due May 15, 2026 (the “2026 Notes”), $339.3 million in principal amount of which were outstanding, and pay the related accrued interest. The remaining proceeds were used to repay a portion of the borrowings outstanding under our senior secured credit facility and for general partnership purposes.

On July 19, 2024, we entered into the Seventh Amended and Restated Credit Agreement (our “credit agreement”) to replace our Sixth Amended and Restated Credit Agreement. The credit agreement provided for a $900 million senior secured revolving credit facility that 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 2028 Notes remain outstanding as of November 2, 2027, the credit agreement matures on such date.

Table of Contents

On December 11, 2024 we entered into the First Amendment to the Seventh Amended and Restated Credit Agreement, which resulted in several changes to the credit agreement terms including; (i) an increase of the maximum consolidated leverage ratio covenant from 5.50 to 1.00 to 5.75 to 1.00 for the fiscal quarters ending December 31, 2024 through September 30, 2025, returning to 5.50 to 1.00 thereafter; and (ii) changes to the minimum consolidated interest coverage ratio covenant from 2.40 to 1.00 to (A) 2.00 to 1.00 for the fiscal quarters ending December 31, 2024 through December 31, 2025, (B) 2.25 to 1.00 for the fiscal quarters ending March 31, 2026 through December 31, 2026, and (C) 2.50 to 1.00 at any time thereafter.

On December 19, 2024, we issued $600 million in aggregate principal amount of 8.000% senior unsecured notes due May 15, 2033 (the “2033 Notes”). Interest payments are due May 15 and November 15 of each year. The issuance of our 2033 Notes generated net proceeds of approximately $589.3 million, net of issuance costs incurred. We used the net proceeds to purchase $575 million in principal of our 2027 Notes (leaving $406.2 million of principal outstanding as of December 31, 2024 on the 2027 Notes) and pay the accrued interest, tender premium and fees on the notes that were validly tendered.

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. We received cash of approximately $1.0 billion, which reflects the net proceeds after the assumption of our then outstanding Alkali senior secured notes by an indirect affiliate of WE Soda Ltd, amongst other purchase price adjustments. We used a portion of the cash proceeds to pay down the outstanding balance on our senior secured credit facility as of February 28, 2025, repurchase certain of our outstanding Class A Convertible Preferred Units (discussed further below), redeem a portion of our outstanding senior unsecured notes (discussed further below), and for general partnership purposes.

In connection with the sale of the Alkali Business, we also entered into the Second Amendment to the credit agreement. This amendment 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 Consolidated Leverage 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.

On March 6, 2025, we entered into purchase agreements with certain Class A Convertible Preferred unitholders whereby we purchased a total of 7,416,196 Class A Convertible Preferred Units at an average purchase price of $35.40 per unit. In addition, on February 3, 2026, we entered into a purchase agreement with one of our Class A Convertible Preferred unitholders whereby we purchased 741,620 Class A Convertible Preferred Units at a purchase price of $33.71 per unit. The purchase of these Class A Convertible Preferred Units, which carried an annual coupon rate of 11.24%, has allowed us to lower our overall cost of capital.

On April 3, 2025, using a portion of the cash proceeds from the sale of the Alkali Business, we redeemed the remaining $406.2 million of principal outstanding on the 2027 Notes, and paid the related accrued interest and redemption premium on those notes that were redeemed.

The successful completion of the above events, and in particular the sale of the Alkali Business, has kick-started the process of simplifying our capital structure, lowered our overall cost of capital and has resulted in no scheduled maturities of our senior unsecured notes or our senior secured credit facility until 2028. In addition, we have $788.6 million of borrowing capacity available under our senior secured credit facility, subject to compliance with covenants in the credit agreement.

We anticipate that our future internally-generated funds and the funds available under our senior secured credit facility will allow us to meet our ordinary course capital needs. Our primary sources of liquidity have been cash flows from operations, proceeds from the sale of assets, borrowing availability under our senior secured credit facility, the proceeds from issuances of equity (common and preferred) and senior unsecured or secured notes and the creation of strategic arrangements to share capital costs through joint ventures or strategic alliances.

Our primary cash requirements consist of:

•working capital, primarily inventories and trade receivables and payables;

•routine operating expenses;

•growth capital (as discussed in more detail below) and maintenance projects;

•interest payments related to outstanding debt;

•asset retirement obligations;

•quarterly cash distributions to our preferred and common unitholders; and

•acquisitions of assets or businesses.

In addition, in an effort to return capital to our investors, we announced a common equity repurchase program (the “Repurchase Program”) on August 8, 2023. The Repurchase Program authorizes the repurchase from time to time of up to 10%

Table of Contents

of our then outstanding Class A Common Units, or 12,253,922 units, via open market purchases or negotiated transactions conducted in accordance with applicable regulatory requirements. These repurchases may be made pursuant to a repurchase plan or plans that comply with Rule 10b5-1 under the Securities Exchange Act of 1934. The Repurchase Program does not create an obligation for us to acquire a particular number of Class A Common Units and any Class A Common Units repurchased will be canceled. The Repurchase Program will be reviewed again no later than December 31, 2026 and may be suspended or discontinued at any time prior thereto. During 2024 and 2025, we did not repurchase any Class A Common Units, and to date, we have purchased 114,900 Class A Common Units under the Repurchase Program.

Capital Resources

Our ability to satisfy future capital needs will depend on our ability to raise substantial amounts of additional capital from time to time, including through equity and debt offerings (public and private), borrowings under our senior secured credit facility and other financing transactions, and to implement our growth strategy successfully. No assurance can be made that we will be able to raise necessary funds on satisfactory terms.

At December 31, 2025, we had $6.4 million borrowed under our senior secured credit facility, with $28.1 million designated as a loan under the inventory sublimit. Our senior secured credit facility does not include a “borrowing base” limitation except with respect to our inventory loans. Due to the revolving nature of loans under our senior secured credit facility, additional borrowings and periodic repayments and re-borrowings may be made until the maturity date of our senior secured credit facility. The total amount available for borrowings under our senior secured credit facility at December 31, 2025 was $788.6 million, subject to compliance with covenants in the credit agreement.

At December 31, 2025, our long-term debt totaled approximately $3.1 billion, consisting of $6.4 million outstanding under our senior secured credit facility (including $28.1 million borrowed under the inventory sublimit tranche) and $3,079.4 million of senior unsecured notes. Our senior unsecured notes balance is comprised of $679.4 million of our 2028 Notes, $600.0 million of our 2029 Notes, $500.0 million of our 8.875% senior unsecured notes due April 15, 2030, issued on January 25, 2023 (the “2030 Notes”), $700.0 million of our 2032 Notes and $600.0 million of our 2033 Notes.

Future payment obligations related to our senior secured credit facility and senior unsecured notes as of December 31, 2025, including both principal and estimated interest payments, are summarized in the table below:

Interest Rate Maturity Date Principal Estimated Annual Interest Payable

(in thousands)

Senior secured credit facility(1) Varies September 1, 2028 $ 6,400 $ 592

(1)Amounts shown above for estimated interest payments represent the amounts that would be paid on an annual basis if the debt outstanding at December 31, 2025 remained outstanding and interest rates remained constant for the annual period.

(2)Each series of senior unsecured notes is further discussed and defined in Note 11 to our Consolidated Financial Statements in Item 8.

Table of Contents

We have the right to redeem each of our series of senior unsecured notes beginning on specified dates as summarized below, at a premium to the face amount of such notes that varies based on the time remaining to maturity on such notes. Additionally, we may redeem up to 35% of the principal amount of each of our series of senior unsecured notes with the proceeds from an equity offering of our common units during certain periods. A summary of the applicable redemption periods is provided in the table below.

For additional information on our long-term debt and covenants see Note 11 to our Consolidated Financial Statements in Item 8.

Class A Convertible Preferred Units

On September 1, 2017, we sold $750 million of Class A Convertible Preferred Units in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial purchasers. Our general partner executed an amendment to our partnership agreement in connection therewith, which, among other things, authorized and established the rights and preferences of our Class A Convertible Preferred Units. Our Class A Convertible Preferred Units are senior to all of our currently outstanding classes or series of limited partner interests with respect to distribution and/or liquidation rights. Holders of our Class A Convertible Preferred Units vote on an as-converted basis with holders of our common units and have certain class voting rights, including with respect to any amendment to the partnership agreement that would adversely affect the rights, preferences or privileges, or otherwise modify the terms, of those Class A Convertible Preferred Units. The Class A Convertible Preferred Units have an effective distribution rate of 11.24%, yielding a quarterly distribution of $0.9473. As of December 31, 2025, there were 15,695,722 Class A Convertible Preferred Units outstanding.

Shelf Registration Statements

We have the ability to issue additional equity and debt securities in the future to assist us in meeting our future liquidity requirements, particularly those related to opportunistically acquiring assets and businesses and constructing new facilities and refinancing outstanding debt.

We have a universal shelf registration statement (our “2024 Shelf”) on file with the SEC which we filed on April 16, 2024 to replace our existing universal shelf registration statement that expired on April 19, 2024. Our 2024 Shelf allows us to issue an unlimited amount of equity and debt securities in connection with certain types of public offerings. However, the receptiveness of the capital markets to an offering of equity and/or debt securities cannot be assured and may be negatively impacted by, among other things, our long-term business prospects and other factors beyond our control, including market conditions. Our 2024 Shelf is set to expire in April 2027.

Cash Flows from Operations

We generally utilize the cash flows we generate from our operations to fund our common and preferred distributions and working capital needs. Excess funds that are generated are used to repay borrowings under our senior secured credit facility and/or to fund a portion of our capital expenditures. Our operating cash flows can be impacted by changes in items of working capital, primarily variances in the carrying amount of inventory and the timing of payment of accounts payable and accrued liabilities related to capital expenditures and interest charges, and the timing of accounts receivable collections from our customers.

We typically sell our crude oil in the same month in which we purchase it, so we do not need to rely on borrowings under our senior secured credit facility to pay for such crude oil purchases, other than inventory. During such periods, our accounts receivable and accounts payable generally move in tandem as we make payments and receive payments for the purchase and sale of crude oil.

Table of Contents

to deposit margin funds with the respective exchange when commodity prices increase as the value of the derivatives utilized to hedge the price risk in our inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our senior secured credit facility or use cash on hand to fund the deposits.

Through the date of February 28, 2025, in the Alkali Business, we extracted trona from our mining facilities, processed it into soda ash and other alkali products, and delivered and sold it to our customers domestically and internationally. The cash requirements for these activities were impacted by the differences in timing between the extraction and ultimate delivery of the product to a customer (as well as any time differences when we stored the alkali products).

The storage of our inventory of crude oil can have a material impact on our cash flows from operating activities. In the month we pay for the stored crude oil, we borrow under our senior secured credit facility (or use cash on hand) to pay for the crude oil, utilizing a portion of our operating cash flows. Conversely, cash flow from operating activities increases during the period in which we collect the cash from the sale of the stored crude oil. Additionally, for our exchange-traded derivatives, we may be required to deposit margin funds with the respective exchange when commodity prices increase as the value of the derivatives utilized to hedge the price risk in our inventory fluctuates. These deposits also impact our operating cash flows as we borrow under our senior secured credit facility or use cash on hand to fund the deposits.

Net cash flows provided by our operating activities were $252.8 million and $391.9 million for 2025 and 2024, respectively. The decrease in operating cash flow for 2025 compared to 2024 was primarily to attributable to negative changes in our working capital requirements during 2025 compared to 2024. In addition, cash flows provided by operating activities for 2025 only included two months of activity from the Alkali Business, as it was sold on February 28, 2025, whereas 2024 included a full year of activity from the Alkali Business.

See Note 16 in our Consolidated Financial Statements in Item 8 for information regarding changes in components of operating assets and liabilities during the years ended December 31, 2025, 2024 and 2023.

Capital Expenditures and Distributions Paid to Our Unitholders

We use cash primarily for our operating expenses, working capital needs, debt service, acquisition activities, internal growth projects and distributions we pay to our common and preferred unitholders. We finance maintenance capital expenditures and smaller internal growth projects and distributions primarily with cash generated by our operations. We have historically funded material growth capital projects (including acquisitions and internal growth projects) with borrowings under our senior secured credit facility, equity issuances (common and preferred units), the issuance of senior unsecured or secured notes, and/or the creation of strategic arrangements to share capital costs through joint ventures or strategic alliances.

Table of Contents

Capital Expenditures for Fixed and Intangible Assets and Equity Investees

The following table summarizes our expenditures for fixed and intangible assets and equity investees in the periods indicated:

Years Ended December 31,

(in thousands)

Capital expenditures for fixed and intangible assets:

Maintenance capital expenditures:

Growth capital expenditures:

Capital expenditures related to equity investees 892 285 4,489

(1)Growth capital expenditures in our offshore pipeline transportation segment for 2025, 2024 and 2023 represent 100% of the costs incurred, including those funded by our noncontrolling interest holder (see further discussion below in “Growth Capital Expenditures”).

(2)Excluded from the table above were total capital expenditures of $6.4 million, $94.6 million and $218.1 million for 2025, 2024 and 2023, respectively, associated with the Alkali Business that was sold on February 28, 2025.

Expenditures for capital assets to grow the partnership distribution will depend on our access to debt and equity capital. We will look for opportunities to acquire assets from other parties that meet our criteria for stable cash flows. We continue to pursue a long term growth strategy that may require significant capital.

Growth Capital Expenditures

As noted above in “Recent Developments and Initiatives”, we recently completed our two offshore growth capital projects, which included the CHOPS expansion and the SYNC Pipeline projects. With the completion of these significant growth capital projects in 2025, and no significant future growth capital projects on the horizon, we do not expect significant growth capital expenditures in 2026.

While we are committed to maintaining sufficient financial flexibility and liquidity, we will continue to evaluate any accretive incremental growth opportunities should they opportunistically emerge.

Maintenance Capital Expenditures

Maintenance capital expenditures incurred during 2025, 2024 and 2023 from our continuing operations primarily related to expenditures in our marine transportation segment to replace and upgrade certain equipment associated with our barge and fleet vessels during our dry-docks. Additionally, our offshore transportation segment assets incur maintenance capital expenditures to replace, maintain and upgrade equipment at certain of our offshore platforms and pipelines that we operate. We expect future expenditures to be within a reasonable range of 2025’s expenditures dependent upon the timing of when we incur certain costs, especially the timing of our dry-docks in our marine transportation segment, and the increase in certain costs we incur. See previous discussion under “Available Cash before Reserves” for how such maintenance capital utilization is reflected in our calculation of Available Cash before Reserves.

Table of Contents

Distributions to Unitholders

Our partnership agreement requires us to distribute 100% of our available cash (as defined therein) within 45 days after the end of each quarter to unitholders of record. Available cash generally means, for each fiscal quarter, all cash on hand at the end of the quarter:

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

•provide for the proper conduct of our business;

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

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

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

On February 13, 2026, we paid a distribution of $0.18 per common unit related to the fourth quarter of 2025. With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.9473 per unit (or $3.7892 on an annualized basis). These distributions were paid on February 13, 2026 to unitholders holders of record at the close of business January 30, 2026.

Our historical distributions to common unitholders and Class A Convertible Preferred unitholders are shown in the table below (in thousands, except per unit amounts).

(1)This distribution was paid on February 13, 2026 to unitholders of record as of January 30, 2026.

Contractual Obligations and Commitments

In addition to the principal and interest payment commitments associated with our long-term debt discussed above, we have other contractual obligations and commitments as of December 31, 2025, which are summarized below.

•We have estimated operating lease payment obligations, as of December 31, 2025, totaling $154.1 million, of which $10.7 million is expected to be paid in 2026 (see Note 5 to our Consolidated Financial Statements in Item 8 for details on our lease obligations).

•We have current estimated asset retirement obligations of approximately $24.3 million. These requirements are expected to be funded primarily with free cash flow generated from our operations and availability under our senior secured credit facility.

Table of Contents

Guarantor Summarized Financial Information

As of December 31, 2025, our $3.1 billion aggregate principal amount of senior unsecured notes co-issued by Genesis Energy, L.P. and Genesis Energy Finance Corporation are fully and unconditionally guaranteed jointly and severally by all of Genesis Energy, L.P.’s current and future 100% owned domestic subsidiaries (the “Guarantor Subsidiaries”), except for certain immaterial subsidiaries. The immaterial non-Guarantor Subsidiaries are indirectly owned by Genesis Crude Oil, L.P., a Guarantor Subsidiary. The Guarantor Subsidiaries largely own the assets that we use to operate our business. See Note 11 to our Consolidated Financial Statements in Item 8 for additional information regarding our consolidated debt obligations.

The guarantees are senior unsecured obligations of each Guarantor Subsidiary and rank equally in right of payment with other existing and future senior indebtedness of such Guarantor Subsidiary, and senior in right of payment to all existing and future subordinated indebtedness of such Guarantor Subsidiary. The guarantee of our senior unsecured notes by each Guarantor Subsidiary is subject to certain automatic customary releases, including in connection with the sale, disposition or transfer of all of the capital stock, or of all or substantially all of the assets, of such Guarantor Subsidiary to one or more persons that are not us or a restricted subsidiary, the exercise of legal defeasance or covenant defeasance options, the satisfaction and discharge of the indentures governing our senior unsecured notes, the designation of such Guarantor Subsidiary as a non-Guarantor Subsidiary or as an unrestricted subsidiary in accordance with the indentures governing our senior unsecured notes, the release of such Guarantor Subsidiary from its guarantee under our senior secured credit facility, or liquidation or dissolution of such Guarantor Subsidiary (collectively, the “Releases”). The obligations of each Guarantor Subsidiary under its note guarantee are limited as necessary to prevent such note guarantee from constituting a fraudulent conveyance under applicable law. We are not restricted from making investments in the Guarantor Subsidiaries and there are no significant restrictions on the ability of the Guarantor Subsidiaries to make distributions to Genesis Energy, L.P.

The rights of holders of our senior unsecured notes against the Guarantor Subsidiaries may be limited under the U.S. Bankruptcy Code or state fraudulent transfer or conveyance law.

The following is the summarized financial information for Genesis Energy, L.P. and the Guarantor Subsidiaries on a combined basis after elimination of intercompany transactions among the Guarantor Subsidiaries (which includes related receivable and payable balances) and the investment in and equity earnings from the non-Guarantor Subsidiaries.

Balance Sheets Genesis Energy, L.P. and Guarantor Subsidiaries

(in thousands)

ASSETS:

LIABILITIES AND CAPITAL:(2)

Class A Convertible Preferred Units 552,523

Statements of Operations Genesis Energy, L.P. and Guarantor Subsidiaries

(in thousands)

Loss from continuing operations (100,685)

Net loss attributable to Genesis Energy, L.P. (520,224)

(1)Excluded from non-current assets in the table above are net intercompany receivables of $9.8 million that are owed to Genesis Energy, L.P. and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as of December 31, 2025.

Table of Contents

(2)There are no noncontrolling interests held at the Issuer or Guarantor Subsidiaries for the period presented.

(3)Excluded from revenues in the table above are $3.0 million of sales from Guarantor Subsidiaries to non-Guarantor Subsidiaries for the year ended December 31, 2025.

Critical Accounting Estimates

The preparation of our consolidated financial statements in conformity with U.S. GAAP requires us to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities, if any, at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. We base these estimates and assumptions on historical experience and other information that are believed to be reasonable under the circumstances. Although we believe our estimates to be reasonable, these estimates and assumptions about future events and their effects cannot be determined with certainty, and, accordingly, are evaluated on a regular basis and revised as needed as new events occur or more information is acquired, and as the business environment in which we operate changes. Significant accounting policies that we employ are presented in Note 2 to our Consolidated Financial Statements in Item 8.

We have defined critical accounting estimates as those that: (i) are material due to the levels of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to change; and (ii) the impact to the financial condition or operating performance of the Company is material. Our most critical accounting estimates are discussed below.

Depreciation and Amortization of Long-Lived Assets and Intangibles

In order to calculate depreciation and amortization we must estimate the useful lives of our fixed and intangible assets at the time the assets are placed in service. We compute depreciation and amortization on a straight-line basis using the best estimated useful life at the time the asset is placed into service. The actual period over which we will use the asset may differ from the assumptions we have made about the estimated useful life. Any subsequent events that result in a change in these estimates can impact future depreciation and amortization calculations, and these changes are adjusted as we become aware of such circumstances.At a minimum, we will assess the useful lives and residual values of all long-lived assets on an annual basis to determine if adjustments are required.

Recoverability of Equity Method Investments

We account for non-marketable investments using the equity method of accounting if the investment gives us the ability to exercise significant influence over, but not control of, an investee. Under the equity method of accounting, investments are stated at initial cost and are adjusted for subsequent additional investments and our proportionate share of earnings or losses and distributions.

We evaluate our equity method investments for impairment at least annually or whenever events or changes in circumstances indicate, in management’s judgment, that the carrying value of an investment may have experienced an other-than-temporary decline in value. When evidence of loss in value has occurred, management compares the estimated fair value of the investment to the carrying value of the investment to determine whether an impairment has occurred. If the estimated fair value is less than the carrying value and management considers the decline in value to be other than temporary, the excess of the carrying value over the estimated fair value is recognized in the financial statements as an impairment.

See Note 9 to our consolidated financial statements for our discussion on equity method investments.

Recoverability of Long-Lived Assets

When events or changes in circumstances indicate that the carrying value of our long-lived assets, including fixed assets, finite lived intangible assets, and right of use asset may not be recoverable, we review our assets for impairment. We compare the carrying value of the associated asset to the estimated undiscounted future cash flows expected to be generated from that asset. Estimates of future net cash flows include estimating future volumes and/or contractual commitments, future margins or tariff rates, future operating costs and other estimates and assumptions consistent with our business plans. If we determine that an asset’s carrying value may not be recoverable due to impairment, we may be required to reduce the carrying value and/or the subsequent useful life of the asset.

Any such write-down of the value and unfavorable change in the useful life of a long-lived asset would increase costs and expenses at that time.

During 2024, we terminated an on-going project related to the integration of certain of our corporate enterprise resource planning systems and we impaired the costs incurred to date. As a result, we recognized an impairment charge of $43.0 million associated with intangible construction in progress costs for the year ended December 31, 2024. For the years ended December 31, 2025 and 2023, we did not recognize an impairment expense associated with our long-lived assets.

Table of Contents

Recoverability of Goodwill

Goodwill represents the excess of the purchase prices we paid for certain businesses over their respective fair values. We do not amortize goodwill. Goodwill is tested annually (at the reporting unit level) for possible impairment as of October 1 of each fiscal year, and on an interim basis when indicators of possible impairment exist.

We have the option to first assess qualitative factors to determine whether it is more likely than not that the fair value of a reporting unit is less than its carrying value. Qualitative factors assessed for each of the applicable reporting units include, but are not limited to, changes in macroeconomic conditions, industry and market considerations, cost factors, discount rates, competitive environments and financial performance of the reporting units. If the qualitative assessment indicates that it is more likely than not that the carrying value of a reporting unit exceeds its estimated fair value, a quantitative test is required.

We also have the option to proceed directly to the quantitative test. Under the quantitative impairment test, the estimated fair value of the reporting unit is compared to its carrying value, including goodwill. If the carrying value of the reporting unit including goodwill exceeds its fair value, an impairment charge equal to the excess would be recognized, up to a maximum amount of goodwill allocated to that reporting unit. We can resume the qualitative assessment in any subsequent period for any reporting unit.

We performed a quantitative assessment as of October 1, 2025 for our sulfur services reporting unit, which is the only reporting unit as of our assessment date that has goodwill. As a result of the quantitative assessment, no impairment was recorded during 2025 as the fair value of our sulfur services reporting unit exceeded the carrying value.

The fair value of our sulfur services reporting unit was determined using the income approach and was predicated on our assumptions regarding the future economic prospects of the reporting unit. Such assumptions include (i) discrete financial forecasts for the assets contained within the reporting unit, which rely on management’s estimates of operating margins, (ii) an exit multiple for cash flows beyond the discrete forecast period, and (iii) an appropriate discount rate. These key assumptions have a degree of uncertainty associated with each of them and changes in them could have a significant impact on fair value. If future results are not consistent with our estimates, we could be exposed to future impairment losses that could be material to our results of operations. Additionally, when performing sensitivity analyses to the significant assumptions, a 10% change in these assumptions does not impact our overall conclusion surrounding the valuation of our goodwill.

We also monitor the markets for our products and services, in addition to the overall market, to determine if a triggering event occurs that would indicate that the fair value of a reporting unit is less than its carrying value. One of our other monitoring procedures we performed is the comparison of our market capitalization to our book equity, which did not result in an indicator of impairment.

We performed a quantitative assessment as of October 1, 2024 for our sulfur services reporting unit, and no impairment was recognized during 2024 as the fair value of our sulfur services reporting unit exceeded the carrying value.

We performed a qualitative assessment as of October 1, 2023 for our sulfur services reporting unit. We did not identify any relevant events or circumstances indicating that it is more likely than not that the fair value of the reporting unit is less than the respective carrying value. As such, a quantitative goodwill test was not required, and no goodwill impairment was recognized for the year ended December 31, 2023.

For additional information regarding our goodwill, see Note 10 to our Consolidated Financial Statements in Item 8.

Revenue recognition - Estimation of variable consideration

Our offshore pipeline transportation segment has certain long-term contracts with customers that include variable consideration that must be estimated at contract inception and re-assessed at each reporting period. Total consideration for these arrangements is recognized as revenue over the applicable contract period and is based on our measure of satisfaction of our corresponding performance obligation. Any difference in timing of revenue recognition and billings results in contract assets and liabilities. The estimated performance obligation over the life of a contract includes significant judgments by management including volume and forecasted production information, future price indexing, our ability to transport volumes produced by our customers, and the contract period. Changes in these assumptions or a contract modification could have a material effect on the amount of variable consideration recognized as revenue.

Liability and Contingency Accruals and Asset Retirement Obligations

We accrue reserves for contingent liabilities including environmental remediation and potential legal claims. When our assessment indicates that it is probable that a liability has occurred and the amount of the liability can be reasonably estimated, we make accruals. We base our estimates on all known facts at the time and our assessment of the ultimate outcome, including consultation with external experts and counsel. We revise these estimates as additional information is obtained or resolution is achieved.

Table of Contents

We also make estimates related to future payments for environmental costs to remediate existing conditions attributable to past operations. Environmental costs include costs for studies and testing as well as remediation and restoration. We sometimes make these estimates with the assistance of third parties involved in monitoring the remediation effort.

Significant changes in new information or judgments could have a material impact to our financial results.

At December 31, 2025, we were not aware of any contingencies or environmental liabilities that would have a material effect on our financial position, results of operations or cash flows.

Additionally, certain of our assets have contractual and regulatory obligations to perform dismantlement and removal activities, and in some instances remediation, when the assets are abandoned. Our asset retirement obligations are recorded as a liability at fair value and have significant assumptions and inputs, including the estimated costs and timing of the associated abandonment activities as well as the discount and inflation rates utilized to calculate the present value of the future estimated costs, that could materially impact our financial results. During 2025, we recognized changes in estimates (primarily due to updated estimated costs and the timing of when we expect to spend these costs) associated with certain of our non-core offshore assets of approximately $3 million, and incurred new liabilities of approximately $1 million associated with certain newly constructed offshore assets. We could have impacts to our future earnings based on the actual costs we incur relative to our estimated costs.

Fair Value of Assets and Liabilities Acquired and Identification of Associated Goodwill and Intangible Assets

In conjunction with each acquisition we make, we must allocate the cost of the acquired entity to the assets and liabilities assumed based on their estimated fair values at the date of acquisition. As additional information becomes available, we may adjust the original estimates within one year subsequent to the acquisition. In addition, we are required to recognize intangible assets separately from goodwill. Determining the fair value of assets and liabilities acquired, as well as intangible assets such as customer relationships, contracts, trade names and non-compete agreements involves professional judgment and is ultimately based on acquisition models and management’s assessment of the value of the assets and liabilities acquired, and to the extent available, third-party assessments. Intangible assets with finite lives are amortized over their estimated useful life as determined by management. Goodwill, if any, is not amortized but instead is periodically assessed for impairment, as discussed further below. Uncertainties associated with these estimates include fluctuations in economic obsolescence factors in the area and potential future sources of cash flow.

Item 7a. Quantitative and Qualitative Disclosures About Market Risk

We are exposed to various market risks, including commodity price risk and interest rate risk. We use various derivative instruments primarily to manage commodity price risk. Our risk management policies and procedures are designed to help ensure that our hedging activities address our risks by monitoring our derivative positions, as well as our physical volumes, grades, locations, and delivery schedules. We do not acquire and hold futures contracts or other derivatives for the purpose of speculating on price changes. The following discussion addresses each risk:

•Crude Oil— We utilize crude oil derivatives to hedge commodity price risk, inherent in our onshore transportation and services segment. Our objectives for these derivatives include hedging fixed price purchase and sales, crude inventories, and basis differentials. We manage these exposures with various instruments including futures, options and swap contracts. Our risk management policies are designed to monitor our physical volumes, grades and delivery schedules to ensure our hedging activities address the market risks inherent in our gathering and marketing activities. As of December 31, 2025 we had entered into derivative instruments that will settle between February 2026 and December 2026.

The accounting treatment for our derivatives is discussed further in Note 19 to our Consolidated Financial Statements in Item 8.

Table of Contents

The table below presents information about our open derivative contracts at December 31, 2025. Notional amounts in barrels (“Bbl”) and the weighted average contract price, total contract amount and total fair value amount in U.S. dollars of our open positions are presented below. Fair values were determined by using the notional amount in barrels multiplied by the December 31, 2025 quoted market prices. The table does not include offsetting physical exposures hedged by our derivative contracts.

Futures and Swap Contracts

Sell (Short) Contracts:

Crude Oil Spread Swap Bbl 50 Bbl $ 0.49 $ 25 $ (51) $ (26)

Option Contracts

Written Contracts:

We manage our risks of volatility in NaOH prices by indexing prices for the sale of NaHS to the market price for NaOH in most of our contracts.

Interest Rate Risk

We are also exposed to market risks due to the floating interest rates on our senior secured credit facility.

Obligations under our senior secured credit facility bear interest at the Term SOFR rate or alternate base rate (which approximates the prime rate), at our option, plus the applicable margin. We have not historically hedged our interest rates. On December 31, 2025, we had $6.4 million of debt outstanding under our senior secured credit facility. A 10% change in the Term SOFR rate would have resulted in an immaterial impact to Net Income from Continuing Operations for the year ended December 31, 2025.

Item 8. Financial Statements and Supplementary Data

The information required hereunder is included in this report as set forth in the “Index to Consolidated Financial Statements.”

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

None.

Item 9A. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

We maintain disclosure controls and procedures designed to ensure that information required to be disclosed in the reports that we file or submit under the Securities Exchange Act of 1934, as amended, is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission’s rules and forms, and that such information is accumulated and communicated to our management, including our chief executive officer and chief financial officer to allow timely decisions regarding required disclosures. Our chief executive officer and chief financial officer, with the participation of our management, have evaluated our disclosure controls and procedures as of December 31, 2025 and have concluded that such disclosure controls and procedures are effective to provide reasonable assurance that information is recorded, processed, summarized, and reported within the time periods specified in the Commission’s rules and forms and that such information is accumulated and communicated to management, including our chief executive officer and chief financial officer to allow for timely decisions regarding required disclosures in this Annual Report on Form 10-K.

Changes in Internal Controls over Financial Reporting

There were no changes during the fiscal quarter ended December 31, 2025 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Table of Contents

Management’s Report on Internal Control over Financial Reporting

Management of the partnership is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) under the Securities Exchange Act of 1934, as amended. The partnership’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements in accordance with generally accepted accounting principles.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management assessed the effectiveness of the partnership’s internal control over financial reporting as of December 31, 2025. In making this assessment, management used the criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment as of December 31, 2025, management has concluded the partnership’s internal control over financial reporting is effective based on those criteria.

PricewaterhouseCoopers LLP, the partnership’s independent registered public accounting firm, has issued an attestation report on the effectiveness of the partnership’s internal control over financial reporting as of December 31, 2025, as stated in their report which appears in Item 8. “Financial Statements and Supplementary Data.”

Table of Contents

Item 9B. Other Information

None.

Part III

Item 10. Directors, Executive Officers and Corporate Governance

Management of Genesis Energy, L.P.

We are a Delaware limited partnership. 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. It also employs most of our personnel, including executive officers.

The board of directors of our general partner (which we refer to as “our board of directors”) must approve significant matters (such as material business strategies, mergers, business combinations, acquisitions or dispositions of assets, issuances of common units, incurrences of debt or other financings and the payments of distributions on common and preferred units). The holders of our Class B Common Units are entitled to (i) vote in the election of our board of directors, subject to the Davison family’s rights under its unitholder rights agreement (described below), as well as (ii) vote on substantially all other matters on which our holders of Class A Common Units are entitled to vote. The holders of our Class A Common Units are not entitled to vote in the election of directors, but they are entitled to vote in a very limited number of other circumstances, including our merger with another company. As is common with MLPs, our partnership structure does not grant our unitholders (in such capacity) the right to directly or indirectly participate in our management or operations other than through the exercise of their limited voting rights.

Collectively, members of the Davison family own 8.8% of our Class A Common Units and 76.9% of our Class B Common Units, for a combined ownership percentage of 8.9% of total Common Units. Pursuant to its unitholder rights agreement, the Davison family is entitled to elect up to three of our directors based on its members’ collective ownership percentage of our outstanding common units: (i) with 15% or more ownership, they have the right to appoint three directors, (ii) with less than 15% ownership but more than 10%, they have the right to appoint two directors, and (iii) with less than 10% ownership, they have the right to appoint one director. That unitholder rights agreement also provides that, so long as the Davison family has the right to elect three directors thereunder, our board of directors cannot have more than 11 directors without the Davison family’s consent. In addition to their rights under that unitholder rights agreement, if the members of the Davison family act as a group, they have the ability to elect at least a majority of our directors because they own a majority of our Class B units.

Under our limited partnership agreement, the organizational documents of our general partner and indemnification agreements with our directors, subject to specified limitations, we will indemnify to the fullest extent permitted by Delaware law, from and against all losses, claims, damages or similar events, any director or officer, or while serving as director or officer, any person who is or was serving as a tax matters member or as a director, officer, tax matters member, employee, partner, manager, fiduciary or trustee of our partnership or any of our affiliates. Additionally, we will indemnify to the fullest extent permitted by law, from and against all losses, claims, damages or similar events, any person who is or was an employee (other than an officer) or agent of our general partner.

Our board of directors currently consists of Sharilyn S. Gasaway, James E. Davison, James E. Davison, Jr., Kenneth M. Jastrow II, Conrad P. Albert, Jack T. Taylor and Grant E. Sims. Our board of directors has determined that each of Ms. Gasaway and Messrs. Jastrow, Albert and Taylor is an independent director under the NYSE rules.

Board Leadership Structure and Risk Oversight

Board Leadership Structure

Our board of directors has no policy that requires the positions of the Chairman of the Board and the Chief Executive Officer to be held by the same or different persons or that we designate a lead or presiding independent director. Our board of directors believes it is important to retain the flexibility to make those determinations based on an assessment of the circumstances existing from time to time, including the composition, skills and experience of our board of directors and its members, specific challenges faced by the Company or the industry in which it operates, and governance efficiency.

Table of Contents

Presently, our board of directors believes that, because Mr. Grant E. Sims is the director most familiar with our business and industry and the most capable of leading the discussion of, and executing on, our business strategy, he is best situated to serve as Chairman, regardless of the fact that he is the Chief Executive Officer of our general partner. Our board of directors also believes that the appointment of a lead independent director, who will preside over executive sessions of non-management directors of our board of directors, will facilitate teamwork and communication between the non-management directors and management. Our board of directors appointed Mr. Jastrow as our lead independent director because of his executive experience and service as a director of other companies. Our board of directors believes that the combined role of Chairman and Chief Executive Officer working with the lead independent director is currently in the best interest of unitholders, providing the appropriate balance between developing our strategy and overseeing management.

On September 1, 2017, we sold $750 million of Class A Convertible Preferred Units in a private placement, comprised of 22,249,494 units for a cash purchase price per unit of $33.71 (subject to certain adjustments, the “Issue Price”) to two initial purchasers. In connection with the private placement, we granted each initial purchaser (including its applicable affiliate transferees) certain rights, including (i) the right to appoint an observer, who shall have the right to attend our board meetings for so long as an initial purchaser (including its affiliates) owns at least $200 million of our Class A Convertible Preferred Units and (ii) the right to appoint two directors to our general partner’s board of directors if (and so long as) we fail to pay in full any three quarterly distribution amounts, whether or not consecutive. As of December 31, 2025, we had 15,695,722 Class A Convertible Units outstanding.

We are committed to sound principles of governance. Such principles are critical for us to achieve our performance goals and maintain the trust and confidence of investors, personnel, suppliers, business partners and stakeholders. We believe independent directors are a key element for strong governance, although we have reserved or exercised our right as a limited partnership under the listing standards of the NYSE not to comply with certain requirements of the NYSE. For example, although at least a majority of the members of our board of directors is independent under the NYSE rules, we reserve the right not to comply with Section 303A.01 of the NYSE Listed Company Manual in the future, which would require that our board of directors be comprised of at least a majority of independent directors. In addition, among other things, we have elected not to comply with Sections 303A.04 and 303A.05 of the NYSE Listed Company Manual, which would require our board of directors to maintain a nominating/corporate governance committee and a compensation committee, each consisting entirely of independent directors. Our corporate governance guidelines are available on our website (www.genesisenergy.com) free of charge. For further discussion of director independence, please see Item 13. “Certain Relationships and Related Transactions, and Director Independence—Director Independence.”

Risk Oversight

We face a number of risks, including exposure to matters relating to the environment, regulation, competition, fluctuations in commodity prices and interest rates, pandemics, cybersecurity threats and severe weather. Management is responsible for the day-to-day management of the risks our company faces, although our board of directors, as a whole and through its committees, has responsibility for the oversight of risk management. In fulfilling its risk oversight role, our board of directors must determine whether risk management processes designed and implemented by our management are adequate and functioning as designed. Senior management regularly delivers presentations to our board of directors on strategic matters, operations, risk management and other matters, and are available to address any questions or concerns raised by our board of directors. Board of directors meetings also regularly include discussions with senior management regarding strategies, key challenges and risks and opportunities for our company.

Our board committees assist our board of directors in fulfilling its oversight responsibilities in certain areas of risk. For example, the audit committee assists with risk management oversight in the areas of financial reporting, internal controls, cybersecurity, compliance with legal and regulatory requirements and our risk management policy relating to our hedging program. The governance, compensation and business development committee assists our board of directors with risk management relating to our compensation policies and programs.

Our board of directors believes that it is important to align (when practical) the interests of the members of our board of directors and certain of our officers with the interests of our long-term stakeholders. Our board of directors has adopted certain policies to further promote that alignment of interests. For example, among other things, our policies prohibit our directors and officers from (i) buying, selling or engaging in transactions with respect to our common units while they are aware of material non-public information and (ii) engaging in short sales of our securities. Certain of our directors and/or officers own substantial amounts of our units, some of which are pledged, including being held in broker margin accounts. See Item 12. “Security Ownership of Certain Beneficial Owners and Management and Related Unitholder Matters.”

Table of Contents

Audit Committee

The audit committee of our board of directors generally oversees our accounting policies and financial reporting and the audit of our financial statements. The audit committee assists our board of directors in its oversight of the quality and integrity of our financial statements and our compliance with legal and regulatory requirements. Our independent registered public accounting firm is given unrestricted access to the audit committee. Our board of directors has determined that the members of the audit committee meet the independence and experience standards established by NYSE and the Securities Exchange Act of 1934, as amended. In accordance with the NYSE rules and the Securities Exchange Act of 1934, as amended, our board of directors has named three of its members to serve on the audit committee—Jack T. Taylor, Conrad P. Albert and Sharilyn S. Gasaway. Mr. Taylor is the chairman of the audit committee. Our board of directors believes that Mr. Taylor and Ms. Gasaway qualify as audit committee financial experts as such term is used in the rules and regulations of the SEC. The charter of the audit committee is available on our website (www.genesisenergy.com) free of charge. Each member of the audit committee is an independent director under NYSE rules.

Governance, Compensation and Business Development Committee

The governance, compensation and business development committee (“G&C Committee”) of our board of directors generally (i) monitors compliance with corporate governance guidelines, (ii) reviews and makes recommendations regarding board and committee composition, structure, size, compensation and related matters, and (iii) oversees compensation plans and compensation decisions for our employees. All the members of our board of directors, other than our CEO, serve as members of the G&C Committee. Mr. Jastrow is the chairman. The charter of the G&C Committee is available on our website (www.genesisenergy.com) free of charge.

Conflicts Committee

To the extent requested by our board of directors, a conflicts committee of our board of directors would be appointed to review specific matters in connection with the resolution of conflicts of interest and potential conflicts of interest between any of our affiliates and us. If a specific review is requested by our board of directors, our conflicts committee would be formed by our Board and would be comprised solely of independent directors. See Item 13. “Certain Relationships and Related Transactions, and Director Independence—Review or Special Approval of Material Transactions with Related Persons.”

Executive Sessions of Non-Management Directors

Our board of directors holds executive sessions in which non-management directors meet without any members of management present in connection with regular board meetings. The purpose of these executive sessions is to promote open and candid discussion among the non-management directors. Mr. Jastrow, as the lead independent director, serves as the presiding director at those executive sessions. In accordance with NYSE rules, interested parties can communicate directly with non-management directors by mail in care of the General Counsel and Secretary or in care of the chairman of the audit committee at 811 Louisiana, Suite 1200, Houston, TX 77002. Such communications should specify the intended recipient or recipients. Commercial solicitations or communications will not be forwarded. We have established a toll-free, confidential telephone hotline so that interested parties may communicate with the chairperson of the audit committee or with all the non-management directors as a group. All calls to this hotline are reported to the chairperson of the audit committee who is responsible for communicating any necessary information to the other non-management directors. The number of our confidential hotline is (844) 988-1695.

Table of Contents

Directors and Executive Officers

Set forth below is certain information concerning our directors and executive officers, effective as of February 18, 2026.

Name Age Position

Grant E. Sims 70 Director, Chairman of the Board, and Chief Executive Officer

Conrad P. Albert 79 Director

James E. Davison 88 Director

James E. Davison, Jr. 59 Director

Sharilyn S. Gasaway 57 Director

Kenneth M. Jastrow II 78 Director, Lead Independent Director

Jack T. Taylor 74 Director

Kristen O. Jesulaitis 56 Chief Financial Officer and Chief Legal Officer

Ryan S. Sims 42 President and Chief Commercial Officer

Garland G. Gaspard 71 Senior Vice President, Operations and Engineering

Louie V. Nicol 40 Senior Vice President and Chief Accounting Officer

Richard R. Alexander 50 Vice President and General Manager, Marine

Jeffrey J. Rasmussen 59 Vice President and General Manager, Sulfur Services

Grant E. Sims has served as a director and Chief Executive Officer of our general partner since August 2006 and Chairman of the Board of our general partner since October 2012. Mr. Grant E. Sims was affiliated with Leviathan Gas Pipeline Partners, LP from 1992 to 1999, serving as the Chief Executive Officer and a director beginning in 1993 until he left to pursue personal interests, including investments. Leviathan (subsequently known as El Paso Energy Partners, L.P. and then GulfTerra Energy Partners, L.P.) was an NYSE listed MLP. Mr. Grant E. Sims has an established track record of developing strong companies and has led his companies through a period of substantial growth while increasing geographic and operational diversity. Mr. Grant E. Sims provides leadership skills, executive management experience and significant knowledge of our business environment, which he has gained through his vast experience with other MLPs.

Conrad P. Albert has served as a director of our general partner since July 2013. Mr. Albert is a private investor and was formerly a director of Anadarko Petroleum Corporation from 1986 to 2006. Mr. Albert also served as a director of DeepTech International, Inc. from 1992 to 1998. From 1969 to 1991, Mr. Albert served in various positions with Manufacturers Hanover Trust Company, ultimately serving as Executive Vice President in charge of worldwide energy lending and corporate finance. Mr. Albert’s extensive financial, executive and directorial experience and his service in various roles in the management of other energy-related companies allows him to provide valuable expertise to our board of directors.

James E. Davison has served as a director of our general partner since July 2007. Mr. Davison served as chairman of the board of Davison Transport, Inc. for over 30 years. He also serves as President of Terminal Services, Inc. Mr. Davison has over fifty years of experience in the energy-related transportation and sulfur removal businesses. Mr. Davison brings to our board of directors significant energy-related transportation and sulfur removal experience and industry knowledge.

James E. Davison, Jr. has served as a director of our general partner since July 2007. Mr. Davison is also a director of another public company, Origin Bancorp, Inc., and serves on its finance, risk and insurance committees. Mr. Davison is the son of James E. Davison. Mr. Davison’s executive and leadership experience enable him to make valuable contributions to our board of directors.

Sharilyn S. Gasaway has served as a director of our general partner since March 2010. Ms. Gasaway is a private investor and was Executive Vice President and Chief Financial Officer of Alltel Corporation, a wireless communications company, from 2006 to 2009, and served as Controller of Alltel Corporation from 2002 through 2006. In her role as CFO, Ms. Gasaway was responsible for the company’s finance, financial reporting, and risk management roles, and gained extensive experience in corporate performance and strategic planning. She brings this vast knowledge to the partnership. Ms. Gasaway is a director of one other public company, JB Hunt Transport Services, Inc. Ms. Gasaway provides our board of directors valuable business experience, risk management and financial expertise, including an understanding of the accounting, compliance and financial matters that we address on a regular basis.

Kenneth M. Jastrow II has served as a director of our general partner since March 2010 and serves as our lead independent director and the chairman of the G&C Committee. Mr. Jastrow served as Chairman and Chief Executive Officer of

Table of Contents

Temple-Inland, Inc., a manufacturing company and the former parent of Forestar Group, from 2000 to 2007. Prior to that, Mr. Jastrow served in various roles at Temple-Inland, including President and Chief Operating Officer, Group Vice President and Chief Financial Officer. Mr. Jastrow served as a director of MGIC Investment Corporation and a director and Director Emeritus of KB Home. Mr. Jastrow formerly served as Non-Executive Chairman of Forestar Group, Inc. Mr. Jastrow’s executive experience and service as director of other companies enable him to make valuable contributions to our board of directors and particularly well suited to be the lead independent director.

Jack T. Taylor has served as a director of our general partner since July 2013 and serves as the chairman of the audit committee. Mr. Taylor is currently a director of Sempra Energy and Murphy USA Inc. Additionally, Mr. Taylor currently serves on the audit committee of Sempra Energy and Murphy USA Inc. Mr. Taylor was a partner of KPMG LLP for 29 years, where from 2005 to 2010 he served as KPMG’s Chief Operating Officer-Americas and Executive Vice Chair of U.S. Operations and from 2001 to 2005 he served as the Vice Chairman of U.S. Audit and Risk Advisory Services. Mr. Taylor’s extensive experience with financial and public accounting issues, his various leadership roles at KPMG LLP and his extensive knowledge of the energy industry make him a valuable resource to our board of directors.

Kristen O. Jesulaitis has served as Chief Financial Officer and Chief Legal Officer of our general partner since April 2023. Ms. Jesulaitis leads Genesis’ accounting, finance and legal organizations, including financial reporting, capital markets execution, treasury and cash management. She also oversees all legal matters of Genesis, including those related to acquisitions and commercial transactions, compliance and regulatory affairs, corporate governance, finance, securities and sustainability. Previously, Ms. Jesulaitis served as Chief Legal Officer and Senior Vice President of our general partner from July 2011 until April 2023. Prior to joining Genesis, she was a partner at the law firm Akin Gump Strauss Hauer & Feld LLP, principally engaged in the areas of corporate and securities law, with primary focus in the midstream energy sector.

Ryan S. Sims has served as President and Chief Commercial Officer of our general partner since April 2023. He is responsible for the execution of Genesis’ long-term strategy and the ultimate leadership of our commercial, operational, corporate development, planning, investor relations and financial activities. Mr. Ryan S. Sims joined Genesis in 2011 and most recently served as Senior Vice President, Finance and Corporate Development of our general partner from March 2019 to April 2023, where he was responsible for the corporate development, planning and investor relations functions. Prior to joining Genesis, Mr. Ryan S. Sims spent six years in the investment banking industry. Mr. Ryan S. Sims is the son of Grant E. Sims, our Chairman and Chief Executive Officer.

Garland G. Gaspard has served as Senior Vice President of our general partner since January 2017 and is responsible for the operational aspects of our onshore and offshore pipelines, offshore facilities and assets, rail facilities, terminals, engineering, trucking, and health, safety, security and environmental compliance. Mr. Gaspard joined Genesis in 2015 as a result of our acquisition of the offshore Gulf of America assets from Enterprise Products Partners L.P. and has had responsibility for the operational aspects of our offshore assets since that time. Prior to this acquisition, Mr. Gaspard served in various capacities within Enterprise Products’ operations including underground gas storage, natural gas liquids, natural gas pipelines and offshore operations.

Louie V. Nicol has served as Senior Vice President and Chief Accounting Officer of our general partner since April 2023. He is responsible for Genesis’ accounting and financial reporting organizations. Mr. Nicol joined Genesis in June 2014 in the finance and accounting department and has held oversight roles with increasing levels of responsibility. Prior to Genesis, Mr. Nicol worked in the audit practice at KPMG LLP for approximately six years.

Richard R. Alexander has served as Vice President of our general partner since November 2014. Mr. Alexander is responsible for the commercial aspects of our marine transportation segment. Since 2008, Mr. Alexander has served in various capacities within our marine operations.

William W. Rainsberger has served as Senior Vice President of our general partner since April 2023. He is responsible for the commercial aspects of our offshore pipelines. Mr. Rainsberger joined Genesis in 2010 and has served as Vice President of our general partner since 2019. Previously, Mr. Rainsberger was responsible for the corporate development and planning functions. Prior to joining Genesis, Mr. Rainsberger worked in the investment banking industry.

Jeffrey J. Rasmussen has served as Vice President of our general partner since April 2023 and is responsible for the commercial aspects of our sulfur services business. Mr. Rasmussen joined Genesis in 2017 as a result of our acquisition of the Alkali Business. Prior to joining Genesis, he spent 15 years with FMC Corporation.

Common Unit Ownership by Directors and Executive Officers

We encourage our directors and officers to own our common units, although we do not feel it is necessary to require them to own a minimum number. Certain of our directors and officers own substantial amounts of our securities, although any (or all) of them may sell, pledge or otherwise dispose of all or a portion of those securities at any time, subject to any applicable legal and company policy requirements. See Item 10. “Directors, Executive Officers and Corporate Governance-Board Leadership Structure and Risk Oversight-Risk Oversight.”

Table of Contents

Code of Ethics

We have adopted a Code of Business Conduct and Ethics that is applicable to, among others, the principal financial officer and the principal accounting officer. Our Code of Business Conduct and Ethics is posted at our website (www.genesisenergy.com), where we intend to report any changes or waivers.

Insider Trading Policies and Procedures

Our general partner’s board of directors has adopted insider trading policies and procedures applicable to our directors, officers, and employees, and have implemented processes for us that we believe are reasonably designed to promote compliance with insider trading laws, rules, and regulations, and NYSE listing standards. A copy of our Insider Trading Policy is filed as Exhibit 19.1 to this Form 10-K.

Table of Contents

Item 11. Executive Compensation

The Compensation Discussion and Analysis below discusses our compensation process and our objectives and philosophy with respect to our Named Executive Officers (“NEOs”) for the fiscal year ended December 31, 2025.

Compensation Discussion and Analysis

Named Executive Officers

Our NEOs for 2025 were:

•Grant E. Sims, Chairman and Chief Executive Officer;

•Ryan S. Sims, President and Chief Commercial Officer;

•Kristen O. Jesulaitis, Chief Financial Officer and Chief Legal Officer;

•Garland G. Gaspard, Senior Vice President, Operations and Engineering;

•Richard R. Alexander, Vice President and General Manager, Marine; and

•Edward T. Flynn, former Executive Vice President.

Edward T. Flynn retired from his position as Executive Vice President effective as of June 30, 2025.

Board and Governance, Compensation and Business Development Committee

Our board of directors is responsible for, and effectively determines, compensation programs applicable to our NEOs and to the board itself. Our board of directors has delegated to the G&C Committee, of which a majority of the members are “independent,” according to NYSE listing standards, the authority and responsibility to regularly analyze and evaluate our compensation policies, to determine the annual compensation of our NEOs, and to make recommendations to our board of directors with respect to such matters. As described in more detail below, the G&C Committee engaged Meridian Compensation Partners, LLC (“Meridian”), as its independent compensation consultant for 2025. As the need arises, we also utilize committees comprised solely of certain of our independent directors (i.e., the audit committee or special committees) to review and make recommendations with respect to certain matters. Because the G&C Committee is comprised of all the members of our board of directors, excluding our CEO, determinations and recommendations by the G&C Committee are effectively determinations and recommendations by our board of directors, which has approval authority for all such compensation matters. For a more detailed discussion regarding the purposes and composition of board committees, please see Item 10. “Directors, Executive Officers and Corporate Governance.”

Committee/Board Process

Following the end of each calendar year, our CEO reviews the compensation of all the other NEOs and makes a proposal to the G&C Committee regarding their compensation. The CEO’s proposal is based on (among other things) our financial results for the prior year, the relevant executive’s areas of responsibility, market data provided by our independent compensation consultant, and recommendations from the relevant executive’s supervisor (if other than our CEO). The G&C Committee reviews the compensation of our CEO and the proposal of our CEO regarding the compensation of the other NEOs and makes a final determination (and a recommendation to our board of directors) regarding the compensation of our NEOs. Depending on the nature and quantity of changes made to that proposal, there may be additional G&C Committee meetings and discussions with our CEO in advance of that determination. Our board of directors has final approval authority for all such compensation matters.

Committee/Board Approval

The G&C Committee determines salaries, annual cash incentives and long-term awards for executive officers, taking into consideration the CEO’s recommendation regarding the NEOs. In April, any applicable salary increases, retention and annual bonuses, and long-term incentive awards are typically made or granted.

Role of Compensation Consultant and Peer Group Analysis

The G&C Committee’s charter authorizes it to retain independent compensation consultants from time to time to serve as a resource in support of its efforts to carry out certain duties. In 2025, the G&C Committee engaged Meridian, an independent compensation consultant, to assist the G&C Committee in assessing and structuring competitive compensation packages for the executive officers that are consistent with our compensation philosophy. The G&C Committee assessed the independence of Meridian pursuant to current exchange listing requirements and SEC guidance and concluded that no conflict of interest exists that would prevent Meridian from serving as an independent consultant to the G&C Committee.

Table of Contents

At the request of the G&C Committee, Meridian reviewed and provided input on the compensation of our NEOs, trends in executive compensation, meeting materials circulated to the G&C Committee, and management’s recommendations regarding executive compensation plans. Meridian also developed assessments of market levels of compensation through an analysis of peer data and information disclosed in our peer companies’ public filings, but did not determine or recommend the amount of compensation.

For purposes of reviewing the compensation amounts related to 2025, Meridian performed a market analysis using a peer group that consisted of the following 16 companies in the energy industry: Targa Resources Corp., Plains All American Pipeline, L.P., Western Midstream Partners, LP, Sunoco LP, Equitrans Midstream Corporation, DT Midstream, Inc., Kinetik Holdings Inc., EnLink Midstream, LLC, HF Sinclair Corporation, NuStar Energy L.P., USA Compression Partners, LP, NGL Energy Partners LP, Global Partners LP, Calumet, Inc., Delek US Holdings, Inc., and U.S. Silica Holdings, Inc. Meridian utilized historical data from Equitrans Midstream Corporation, EnLink Midstream, LLC, NuStar Energy L.P., and U.S. Silica Holdings, Inc. for the market analysis as these companies were acquired by EQT Corporation, ONEOK, Inc., Sunoco LP, and, Apollo Global Management, respectively, during 2024 or early 2025. These companies were selected for the compensation peer group for any or all of the following reasons:

1) they reflect our industry competitors for products and services;

2) they operate in similar markets or have comparable geographical reach;

3) they are of similar size and maturity to us; or

4) they are companies that have similar credit profiles to us and/or their growth or capital programs are similar to ours.

The G&C Committee reviews the peer group annually and may, from time to time, add or remove companies in order to assure the composition of the group meets the criteria outlined above.

The information that Meridian compiled included compensation trends for MLPs and levels of compensation for similarly situated executive officers of companies within this peer group. We believe that compensation levels of executive officers in our peer group are relevant to our compensation decisions because we compete with those companies for executive management talent.

Compensation Objectives and Philosophy

The primary objectives of our compensation program are to:

•encourage our executive leaders to build and operate the partnership in a way that is aligned with our common and preferred unitholders’ interests, focusing on visible distribution, high coverage and targeted leverage metrics, all combining to maximize per unit value, while maintaining a focus on the long-term stability of the enterprise and structured so as to not promote inappropriate risk taking;

•offer near-term and long-term compensation opportunities that are competitive with industry norms; and

•provide appropriate levels of retention to the executive team to ensure long-term continuity and stability for the successful execution of key growth initiatives and projects.

We strive to accomplish these objectives by providing all employees, including our NEOs, with a total compensation package that is market competitive and both service and performance-based. In our assessment of the market competitiveness of compensation, we take into consideration the compensation offered by companies in our peer group described above, but we have not identified a specific percentile of peer company pay as a target. Rather, we use market information as one consideration in setting compensation along with individual performance, our financial and operational performance and our safety and sustainability performance.

We pay base salaries at levels that we feel are appropriate for the skills and qualities of the individual NEOs based on their past performance, current scope of responsibilities and future potential. The incentive-based components of each NEO’s compensation include annual cash bonus opportunities and participation in our long-term incentive program. The annual cash bonus rewards incremental operational and financial achievements required to meet investor expectations in the short-term while the long-term component focuses rewards on the long-term stability of the enterprise and intends to assure an alignment between executives and investors in the partnership. Both incentive components are generally linked to base salary and are consistent in general with our understanding of market practice and with our judgment regarding each individual’s role in the organization.

As described in more detail below, we believe that the combination of base salaries, cash bonuses and long-term cash-based incentive awards provide an appropriate balance of short and long-term incentives, and alignment of the incentives for our executives, including our NEOs, with the interests of our unitholders.

Table of Contents

The amount of compensation contingent on performance is a significant percentage of total compensation, therefore ensuring that business decisions and actions lead to the long-term growth and sustainability of the organization. Our bonus plan (including retention bonuses) is short-term in nature and includes awards based on individual and company performance with the goal of retaining key employees and NEOs. Our long-term incentive plan is linked to our generation of Available Cash before Reserves,our sustainabilityand safety record, as well as the partnership’s ConsolidatedLeverage ratio (as defined in our credit agreement).

Elements of Our Compensation Program and Compensation Decisions for 2025

The primary elements of our compensation program are a combination of annual cash and long-term incentive-based compensation. For the year ended December 31, 2025, the elements of our compensation program for the NEOs consisted of an annual base salary, discretionary annual bonus awards, including retention bonus awards and awards under our long-term incentive compensation program.

Additionally, in order to attract qualified executive personnel, we may make one-time new-hire equity awards.

Base Salaries

We believe that base salaries should provide a fixed level of competitive pay that reflects the executive officer’s primary duties and responsibilities and provides a foundation for incentive opportunities and benefit levels. As discussed above, the base salaries of our NEOs are reviewed annually by the G&C Committee, taking into account recommendations from our CEO regarding NEOs other than himself. We pay base salaries at a level that we feel is appropriate for the skills and qualities of the individual NEOs based on their past performance, current scope of responsibilities and future potential. Base salaries may be adjusted to achieve what is determined to be a reasonably competitive level or to reflect promotions, the assignment of additional responsibilities, individual performance or company performance. Salaries are also periodically adjusted based on analysis of peer group practices as described above.

In April 2025, the G&C Committee reviewed the assessments of market levels of compensation developed by Meridian in conjunction with a discussion of individual performance and responsibilities. As a result of this review and taking into account current market conditions and their respective levels of responsibility, the G&C Committee approved increases in the base salaries of Mr. Ryan S. Sims, Ms. Jesulaitis, Mr. Gaspard, and Mr. Alexander, effective as of April 9, 2025. Mr. Ryan S. Sims’ 2025 base salary increased to $600,000, representing an increase of 4%. Ms. Jesulaitis’ 2025 base salary increased to $575,000, representing an increase of 5%. Mr. Gaspard’s 2025 base salary increased to $450,000, representing an increase of 6%. Mr. Alexander’s 2025 base salary increased to $450,000, representing an increase of 13%. Mr. Grant E. Sims’ 2025 base salary remained at $860,000, which was consistent with his 2024 base salary.

Bonuses

Our NEOs typically participate in a retention bonus program in which a number of our key employees, managers and officers are eligible. As designed by the G&C Committee, each NEO is awarded a retention bonus amount established based on the analysis of market practices of the peer group and consideration of the level of salary and targeted long-term incentives for each NEO. These retention bonuses are discretionary and are awarded based on individual and company performance with the goal of retaining key employees.In 2025, Mr. Grant E. Sims was granted a retention bonus of $1,075,000, Mr. Ryan S. Sims was granted a retention bonus of $600,000, Ms. Jesulaitis was granted a retention bonus of $575,000, Mr. Gaspard was granted a retention bonus of $450,000, and Mr. Alexander was granted a retention bonus of $450,000, to be paid in four equal installments on or before the last day of the quarter ended on the following dates: September 30, 2025, December 31, 2025, March 31, 2026 and June 30, 2026, contingent upon continued employment at those dates.

We believe that these retention bonuses are an appropriate mechanism to incentivize key executives to remain with us so that we may benefit from their experience in the industry and other competitive opportunities available to them.

Long-Term Incentive Compensation

We generally provide certain long-term compensation (cash and equity-based) to directors, officers, and certain employees through our long-term incentive compensation plans (“LTIPs”). Our G&C Committee designs these awards to align the interests of plan participants with the interests of our long-term unitholders by promoting a sense of proprietorship and personal involvement in our development, growth, and financial success. Our LTIPs have given us flexibility to grant deferred compensation awards in the form of equity or cash-based compensation that vest outright or upon the satisfaction of one or more conditions that reward measurable service and performance, including the passage of time, continued employment, financial, and operating (including safety and sustainability) metrics and the appreciation in our unit price over time.

In 2018, our G&C Committee adopted our 2018 LTIP. Like our 2010 LTIP, our 2018 LTIP permits awards of equity-based compensation in the form of phantom units and distribution equivalent rights (“DERs”). Phantom units are notional units representing unfunded and unsecured promises to pay to the participant a specified amount of cash based on the

Table of Contents

market value of our common units should specified vesting requirements be met. DERs are tandem rights to receive on a quarterly basis an amount of cash equal to the amount of distributions that would have been paid on outstanding phantom units had they been limited partner units issued by us. In addition, our 2018 LTIP permits the grant of cash-based awards.

Our G&C Committee administers our LTIPs and has broad authority to grant awards under and alter, amend, or terminate our LTIPs. For example, our G&C Committee has the authority to determine (i) who (if anyone) will receive awards from time to time as well as (ii) the size, nature, terms and conditions of such award. Our G&C Committee also has the authority to adopt, alter, and repeal rules, guidelines and practices relating to our LTIPs and interpret our LTIPs. Our board of directors can terminate the LTIPs at any time.

During 2025, 2024and 2023, we granted cash-based awards to certain officers and other employees under our 2018 LTIP, including our NEOs. We established targetgrant values for NEOs based on an analysis of market practices of our compensation peer group and consideration of the level of salary and targeted bonus for each NEO.

For 2025, the G&C Committee established the following long-term incentive cash grant target values for each of our NEOs:

GEL US Equity

GEL · 10-K · period ended 2025-12-31

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

Item 7a. Quantitative and Qualitative Disclosures About Market Risk

Item 8. Financial Statements and Supplementary Data

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

Item 9A. Controls and Procedures

Item 9B. Other Information

Item 10. Directors, Executive Officers and Corporate Governance

Item 11. Executive Compensation

GEL US Equity☆

GEL · 10-K · period ended 2025-12-31

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

Item 7a. Quantitative and Qualitative Disclosures About Market Risk

Item 8. Financial Statements and Supplementary Data

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

Item 9A. Controls and Procedures

Item 9B. Other Information

Item 10. Directors, Executive Officers and Corporate Governance

Item 11. Executive Compensation

GEL US Equity