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 o f 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 o f 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 o f 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 o f 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 ref ining complexes. Given these facts, we do not
Table o f 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)
Offshore pipeline transportation
Marine transportation
Onshore transportation and services
Total Segment Margin
Table o f 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 crude oil pipeline revenue, net to our ownership interest and excluding non-cash revenues
Offshore natural gas pipeline revenue, excluding non-cash revenues
Offshore pipeline operating costs, net to our ownership interest and excluding non-cash expenses (1)
Distributions from equity investments (2)
Offshore pipeline transportation Segment Margin
Volumetric Data 100% basis:
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS
Poseidon
Odyssey
GOPL (3)
Total crude oil offshore pipelines
Natural gas transportation volumes (MMBtus/day)
Volumetric Data net to our ownership interest (4) :
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS
Poseidon
Odyssey
GOPL (3)
Total crude oil offshore pipelines
Natural gas transportation volumes (MMBtus/day)
(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 o f 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):
Inland freight revenues
Offshore freight revenues
Other rebill revenues (1)
Total segment revenues
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses (1)
Segment Margin (in thousands)
Fleet Utilization: (2)
Inland Barge Utilization
Offshore Barge Utilization
(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 o f 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 o f Contents
Operating results for our onshore transportation and services segment were as follows:
Year Ended December 31,
(in thousands)
Gathering, marketing, and logistics revenue
Crude oil pipeline tariffs and revenues
Sulfur services revenues, excluding non-cash revenues
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions
Operating costs, excluding non-cash expenses
Other
Segment Margin
Volumetric Data (average Bbls/day unless otherwise noted):
Onshore crude oil pipelines:
Texas
Jay
Mississippi
Louisiana (1)
Onshore crude oil pipelines total
Crude oil product sales
Rail unload volumes
NaHS volumes (Dry short tons “DST”)
NaOH (caustic soda) volumes (DST sold)
(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 o f 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:
Corporate
Segment
Long-term incentive based compensation plan expense
Third-party costs related to business development activities and growth projects
Total general and administrative expenses
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)
Depreciation expense
Amortization expense
Total depreciation and amortization expense
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)
Interest expense, senior secured credit facility (including commitment fees), net
Interest expense, senior unsecured notes
Amortization of debt issuance costs, premium and discount
Capitalized interest
Interest expense, net
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 o f 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 o f 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 crude oil pipeline revenue, net to our ownership interest and excluding non-cash revenues
Offshore natural gas pipeline revenue, excluding non-cash revenues
Offshore pipeline operating costs, net to our ownership interest and excluding non-cash expenses
Distributions from equity investments (1)
Offshore pipeline transportation Segment Margin
Volumetric Data 100% basis:
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS
Poseidon
Odyssey
GOPL (2)
Total crude oil offshore pipelines
Natural gas transportation volumes (MMBtus/day)
Volumetric Data net to our ownership interest (3) :
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS
Poseidon
Odyssey
GOPL (2)
Total crude oil offshore pipelines
Natural gas transportation volumes (MMBtus/day)
(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 o f Contents
Marine Transportation Segment
Operating results for our marine transportation segment were as follows:
Year Ended December 31,
Revenues (in thousands):
Inland freight revenues
Offshore freight revenues
Other rebill revenues (1)
Total segment revenues
Operating costs, excluding non-cash charges for long-term incentive compensation and other non-cash expenses (1)
Segment Margin (in thousands)
Fleet Utilization: (2)
Inland Barge Utilization
Offshore Barge Utilization
(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 o f 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
Crude oil pipeline tariffs and revenues
Sulfur services revenues, excluding non-cash revenues
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions
Operating costs, excluding non-cash expenses
Other
Segment Margin
Volumetric Data (average Bbls/day unless otherwise noted):
Onshore crude oil pipelines:
Texas
Jay
Mississippi
Louisiana (1)
Onshore crude oil pipelines total
Crude oil product sales
Rail unload volumes
NaHS volumes (Dry short tons “DST”)
NaOH (caustic soda) volumes (DST sold)
(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 o f Contents
Other Costs and Interest
General and administrative expenses
Year Ended December 31,
(in thousands)
General and administrative expenses not separately identified below:
Corporate
Segment
Long-term incentive based compensation plan expense
Third-party costs related to business development activities and growth projects
Total general and administrative expenses
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)
Depreciation expense
Amortization expense
Total depreciation and amortization expense
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
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, 2023.
Interest expense, net
Year Ended December 31,
(in thousands)
Interest expense, senior secured credit facility (including commitment fees), net
Interest expense, senior unsecured notes
Amortization of debt issuance costs, premium and discount
Capitalized interest
Interest expense, net
Table o f 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 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.
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 o f 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 Ended
December 31,
Applicable to all Non-GAAP Measures
(in thousands)
Differences in timing of cash receipts for certain contractual arrangements (1)
Certain non-cash items:
Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value
Loss on debt extinguishment (2)
Adjustment regarding equity investees (3)
Other
Sub-total Select Items, net
Applicable only to Available Cash before Reserves
Certain transaction costs
Other
Total Select Items, net (4)
Table o f 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 o f 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.
Income tax expense
Depreciation, amortization and accretion
Impairment expense
Plus (minus) Select Items, net
Maintenance capital utilized (1)
Cash tax expense
Distributions to preferred unitholders
Loss on disposal of discontinued operations
Other non-cash items from discontinued operations (2)
Available Cash before Reserves
(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 o f 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 o f 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
2028 Notes (2)
February 1, 2028
2029 Notes (2)
January 15, 2029
2030 Notes (2)
April 15, 2030
2032 Notes (2)
May 15, 2032
2033 Notes (2)
May 15, 2033
Total estimated payments
(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 o f 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.
2028 Notes
2029 Notes
2030 Notes
2032 Notes
2033 Notes
Redemption right beginning on
February 1, 2023
January 15, 2026
April 15, 2026
May 15, 2027
May 15, 2028
Redemption of up to 35% of the principal amount of notes with the proceeds of an equity offering permitted prior to
April 15, 2026
May 15, 2027
May 15, 2028
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.
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 derivatives, we may be required
Table o f 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 o f 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:
Offshore pipeline transportation assets
Marine transportation assets
Onshore transportation and services assets
Information technology systems
Total maintenance capital expenditures
Growth capital expenditures:
Offshore pipeline transportation assets (1)
Marine transportation assets
Onshore transportation and services assets
Information technology systems
Total growth capital expenditures
Total capital expenditures for fixed and intangible assets
Capital expenditures related to equity investees
Total capital expenditures (2)
(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 o f 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).
Distribution For
Date Paid
Per Common Unit
Amount
Total
Amount
Per Preferred Unit Amount
Total
Amount
1 st Quarter
May 15, 2023
2 nd Quarter
August 14, 2023
3 rd Quarter
November 14, 2023
4 th Quarter
February 14, 2024
1 st Quarter
May 15, 2024
2 nd Quarter
August 14, 2024
3 rd Quarter
November 14, 2024
4 th Quarter
February 14, 2025
1 st Quarter
May 15, 2025
2 nd Quarter
August 14, 2025
3 rd Quarter
November 14, 2025
4 th Quarter (1)
February 13, 2026
(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 o f 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
December 31, 2025
(in thousands)
ASSETS:
Current assets
Fixed assets, net
Non-current assets (1)
LIABILITIES AND CAPITAL: (2)
Current liabilities
Non-current liabilities
Class A Convertible Preferred Units
Statements of Operations
Genesis Energy, L.P. and Guarantor Subsidiaries
Year Ended December 31, 2025
(in thousands)
Revenues (3)
Operating costs
Operating income
Loss from continuing operations
Net loss (2)
Net loss attributable to Genesis Energy, L.P.
(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 o f 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 o f 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 o f 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.
