Genesis Energy LP

10/30/2025 | Press release | Distributed by Public on 10/30/2025 09:36

Quarterly Report for Quarter Ending September 30, 2025 (Form 10-Q)

Management's Discussion and Analysis of Financial Condition and Results of Operations
The following information should be read in conjunction with our Unaudited Condensed Consolidated Financial Statements and accompanying notes included in this Quarterly Report on Form 10-Q. The following information and such Unaudited Condensed Consolidated Financial Statements should also be read in conjunction with the audited financial statements and related notes, together with our discussion and analysis of financial position and results of operations, included in our Annual Report.
Included in Management's Discussion and Analysis of Financial Condition and Results of Operations are the following sections:
•Overview
•Results of Operations
•Liquidity and Capital Resources
•Guarantor Summarized Financial Information
•Non-GAAP Financial Measures
•Forward Looking Statements
Overview
We reported Net Income from Continuing Operations of $22.8 million during the three months ended September 30, 2025 (the "2025 Quarter") compared to Net Loss from Continuing Operations of $4.6 million during the three months ended September 30, 2024 (the "2024 Quarter").
Net Income from Continuing Operations in the 2025 Quarter was impacted by an increase in operating income from our operating segments, primarily from our offshore pipeline transportation operating segment (see "Results of Operations" below for additional details). This increase in operating income was partially offset by an increase in depreciation and amortization of $1.5 million during the 2025 Quarter (see "Results of Operations" below for additional details).
We reported Net Loss from Discontinued Operations, net of tax of $4.7 million during the 2024 Quarter associated with the Alkali Business that was sold on February 28, 2025.
Cash flow from operating activities was $70.3 million for the 2025 Quarter compared to $87.3 million for the 2024 Quarter. The decrease in cash flow from operating activities is primarily attributable to negative changes in working capital in the 2025 Quarter compared to the 2024 Quarter. In addition, cash flows provided by operating activities for the 2025 Quarter did not include activity from the Alkali Business, as it was sold on February 28, 2025, whereas the 2024 Quarter included a full quarter of activity from the Alkali Business. Partially offsetting these decreases in cash flow from operating activities was an increase in segment margin in the 2025 Quarter compared to the 2024 Quarter (as discussed further below).
Available Cash before Reserves (as defined below in "Non-GAAP Financial Measures") to our common unitholders was $35.5 million for the 2025 Quarter, an increase of $11.0 million, or 45%, from the 2024 Quarter primarily as a result of: (i) an increase in Segment Margin of $24.6 million, which is discussed in more detail below; and (ii) a decrease in accumulated distributions to our Class A Convertible Preferred unitholders of $7.0 million. Partially offsetting these increases was the exclusion of activity in the 2025 Quarter from the Alkali Business, as it was sold on February 28, 2025, whereas the 2024 Quarter included a full quarter of activity from the Alkali Business.
Segment Margin (as defined below in "Non-GAAP Financial Measures") was $146.6 million for the 2025 Quarter, an increase of $24.6 million, or 20%, from the 2024 Quarter. A more detailed discussion of our segment results and other costs are included below in "Results of Operations." See "Non-GAAP Financial Measures" below for additional information on Segment Margin.
Market Update
Management's estimates are based on numerous assumptions about future operations and market conditions, which we believe to be reasonable, but are inherently uncertain. The uncertainties underlying our assumptions could cause our estimates to differ significantly from actual results, including with respect to the duration and severity of the lasting impacts of international conflicts and the result of any economic recession or depression that has occurred or may occur in the future as a result of or as it relates to changes in governmental policies (including with respect to tariffs or proposed tariffs, taxes, duties and similar matters affecting international trade) aimed at addressing inflation or other conditions or events, which could cause fluctuations in global economic conditions, including capital and credit markets. We will continue to monitor the current market environment and to the extent conditions deteriorate, we may identify triggering events that may require future evaluations of the recoverability of the carrying value of our long-lived assets, intangible assets and goodwill, which could result in impairment charges that could be material to our results of operations.
Although the ultimate impacts of these international conflicts, changes in governmental policies (including with respect to tariffs or proposed tariffs, taxes, duties and similar matters) and fluctuations in global economic conditions, including capital and credit markets, are still unknown at this time, we believe the fundamentals of our core businesses continue to remain strong, and considering the current industry environment and capital market behavior, we have continued our focus on deleveraging our balance sheet as further explained below in "Liquidity and Capital Resources."
Results of Operations
Revenues and Costs and Expenses
Our revenues for the 2025 Quarter increased $16.7 million, or 4%, from the 2024 Quarter and our total costs and expenses decreased $13.3 million , or 4%, between the two periods with an overall net increase to operating income of $30.0 million as presented on the Unaudited Condensed Consolidated Statements of Operations. The increase in our operating income during the 2025 Quarter is primarily due to: (i) our offshore pipeline transportation segment as a result of the contractual minimum volume commitments ("MVC's") on our 100% owned SYNC Pipeline and 64% owned CHOPS Pipeline associated with the Shenandoah deepwater development that began in June 2025 and an increase in volumes on our CHOPS Pipeline (see further discussion below). These were partially offset by: (i) an increase in depreciation and amortization of $1.5 million during the 2025 Quarter (see further discussion below); and (ii) an increase in general and administrative expenses of $0.5 million during the 2025 Quarter (see further discussion below).
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 price for West Texas Intermediate crude oil on the New York Mercantile Exchange ("NYMEX") decreased to $65.78 per barrel in the 2025 Quarter, as compared to $76.43 per barrel in the 2024 Quarter. We expect changes in crude oil prices to continue to proportionately affect our revenues and costs attributable to our purchase and sale of crude oil, resulting in a minimal direct impact on Net income (loss), Segment Margin and Available Cash before Reserves. We have limited our direct commodity price exposure in our crude oil operations through the broad use of fee-based service contracts, back-to-back purchase and sale arrangements and hedges. As a result, changes in the price of crude oil would proportionately impact both our revenues and our costs, with a disproportionately smaller impact on Net income (loss), Segment Margin and Available Cash before Reserves. However, we do have some indirect exposure to certain changes in prices for crude oil, particularly if they are significant and extended. We tend to experience more demand for certain of our services when prices increase significantly over extended periods of time, and we tend to experience less demand for certain of our services when prices decrease significantly over extended periods of time. For additional information regarding certain of our indirect exposure to commodity prices, see our segment-by-segment analysis below and the section of our Annual Report entitled " Risks Related to Our Business."
We also have revenues and costs associated with our other refinery-centric operations including our sulfur services business, which we believe is one of the largest producers and marketers of NaHS in North and South America, and from our other logistical assets including pipelines, trucks, terminals, and rail unloading facilities.
We conduct our offshore crude oil and natural gas pipeline transportation and handling operations in the Gulf of America through our offshore pipeline transportation segment, which focuses on providing a suite of services to integrated and large independent energy companies who make intensive capital investments (often in excess of a billion dollars) to develop large-reservoir, long-lived crude oil and natural gas properties located primarily in offshore Texas, Louisiana and Mississippi. We own interests in various offshore crude oil and natural gas pipeline systems, platforms and related infrastructure and generate cash flows from fees to customers to utilize our assets. Our costs are primarily related to expenses incurred for the maintenance of our assets, employee compensation, and other operating costs.
Our marine transportation segment consists of (i) our inland marine fleet, which transports intermediate refined petroleum products, including asphalt, principally serving refineries and storage terminals along the Gulf Coast, Intracoastal Canal and western river systems of the U.S., primarily along the Mississippi River and its tributaries; (ii) our offshore marine fleet, which transports crude oil and refined petroleum products, principally serving refineries and storage terminals along the Gulf Coast, Eastern Seaboard, Great Lakes and Caribbean; and (iii) our modern, double-hulled tanker, M/T American Phoenix. Our revenues are driven by the demand for our barge services and associated utilization of our fleets, as well as the day rates we charge, which can be dependent upon market conditions (including supply and demand in the market), amongst other factors. Our costs are principally related to the costs required to maintain our fleets, employee compensation, and other operating costs.
Refiners are the shippers of a majority of the volumes transported on our onshore crude oil pipelines, and refiners contracted for approximately 90% of the revenues from our marine transportation segment during the 2025Quarter, which are used primarily to transport intermediate refined products (not crude oil) between refining complexes. Given these facts, we do not 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.
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). 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 was as follows:
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
(in thousands) (in thousands)
Offshore pipeline transportation $ 101,343 $ 72,149 $ 265,485 $ 256,086
Marine transportation 25,570 31,068 85,408 93,974
Onshore transportation and services 19,663 18,762 52,947 57,102
Total Segment Margin $ 146,576 $ 121,979 $ 403,840 $ 407,162
A reconciliation of Income (Loss) from continuing operations before income taxes to total Segment Margin for the periods presented is as follows:
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
Income (loss) from continuing operations before income taxes $ 23,029 $ (5,451) $ (3,032) $ 2,735
Net income attributable to noncontrolling interests (13,569) (7,890) (32,755) (22,850)
Corporate general and administrative expenses 15,992 13,469 72,736 48,085
Depreciation, amortization and accretion 59,746 58,348 177,768 164,451
Interest expense, net 66,407 65,662 197,199 192,535
Adjustment to include distributable cash generated by equity investees not included in income and exclude equity in investees net income(1)
5,233 6,855 16,920 18,542
Unrealized losses (gains) on derivative transactions excluding fair value hedges, net of changes in inventory value
136 63 (68) 21
Other non-cash items (3,307) (1,551) (10,258) (6,152)
Loss on debt extinguishment - - 9,779 1,429
Differences in timing of cash receipts for certain contractual arrangements(2)
(7,091) (7,526) (24,449) 8,366
Total Segment Margin $ 146,576 $ 121,979 $ 403,840 $ 407,162
(1)Includes distributions attributable to the quarter and received during or promptly following such quarter.
(2)Includes the difference in timing of cash receipts from or billings to 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.
Offshore Pipeline Transportation Segment
Operating results and volumetric data for our offshore pipeline transportation segment are presented below:
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
(in thousands) (in thousands)
Offshore crude oil pipeline revenue, net to our ownership interest and excluding non-cash revenues $ 100,034 $ 64,103 $ 253,623 $ 226,085
Offshore natural gas pipeline revenue, excluding non-cash revenues 13,181 13,661 39,186 39,498
Offshore pipeline operating costs, net to our ownership interest and excluding non-cash expenses (27,292) (23,463) (78,056) (66,616)
Distributions from equity investments(1)
15,420 17,848 50,732 57,119
Offshore pipeline transportation Segment Margin $ 101,343 $ 72,149 $ 265,485 $ 256,086
Volumetric Data 100% basis:
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS 360,925 304,198 332,987 299,628
Poseidon 251,788 249,210 248,326 273,704
Odyssey 63,583 69,560 66,209 65,837
GOPL(2)
1,395 1,583 1,486 1,801
Total crude oil offshore pipelines 677,691 624,551 649,008 640,970
Natural gas transportation volumes (MMBtus/day) 425,801 393,240 410,511 385,038
Volumetric Data net to our ownership interest(3):
Crude oil pipelines (average Bbls/day unless otherwise noted):
CHOPS 230,992 194,687 213,112 191,762
Poseidon 161,144 159,494 158,929 175,171
Odyssey 18,439 20,172 19,201 19,093
GOPL(2)
1,395 1,583 1,486 1,801
Total crude oil offshore pipelines 411,970 375,936 392,728 387,827
Natural gas transportation volumes (MMBtus/day) 110,234 108,590 106,588 109,192
(1)Offshore pipeline transportation Segment Margin includes distributions received from our offshore pipeline joint ventures accounted for under the equity method of accounting for the three and nine months ended September 30, 2025 and 2024.
(2)One of our wholly-owned subsidiaries (GEL Offshore Pipeline, LLC, or "GOPL") owns our undivided interest in the Eugene Island pipeline system.
(3)Volumes are the product of our effective ownership interest throughout the period multiplied by the relevant throughput over the given period.
Three Months Ended September 30, 2025 Compared with Three Months Ended September 30, 2024
Offshore pipeline transportation Segment Margin for the 2025 Quarter increased $29.2 million, or 40%, from the 2024 Quarter 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 contributed to our reported Segment Margin; (ii) an increase to other MVCs on our 64% owned CHOPS Pipeline during the 2025 Quarter, including those related to the Warrior and Winterfell projects; and (iii) an increase in volumes in the 2025 Quarter as a result of the remediation of certain wells that previously encountered sub-sea operational and technical issues during the 2024 Quarter. Production volumes from the Shenandoah floating production system ("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, but we were able to recognize the contractual MVC's for the entire 2025 Quarter in Segment Margin. We have seen a ramp up in volumes from the Shenandoah FPS to approximately 90,000 barrels of oil per day as we exited the 2025 Quarter and expect the Shenandoah FPS to ramp up to its design capacity over the remainder of the year as the operator brings additional wells on-line.
Activity in and around our Gulf of America asset base continues to be robust, including incremental in-field drilling at existing fields that tie into our infrastructure, and first oil from the Salamanca development, which occurred near the end of the 2025 Quarter. While contribution from the Salamanca development was minimal to our Segment Margin in the 2025 Quarter, we expect higher contribution in future periods as the volumes from the Salamanca development are life-of-lease dedicated to our 100% owned SEKCO lateral pipeline and further downstream to our 64% owned Poseidon Pipeline.
Nine Months Ended September 30, 2025 Compared with Nine Months Ended September 30, 2024
Offshore pipeline transportation Segment Margin for the first nine months of 2025 increased $9.4 million, or 4%, from the first nine months of 2024 primarily due to: (i) the contractual MVC's on our 100% owned SYNC Pipeline and 64% owned CHOPS Pipeline associated with the deepwater Shenandoah development that began in June 2025 and contributed to our reported Segment Margin; and (ii) an increase to other MVCs on our 64% owned CHOPS Pipeline during the first nine months of 2025 including those related to the Warrior and Winterfell projects.
These increases to Segment Margin in the first nine months of 2025 compared to the first nine months of 2024 were partially offset by: (i) an economic step-down in the rate on a certain existing life-of-lease transportation dedication; (ii) producer underperformance at several of the major fields attached to our pipeline infrastructure; and (iii) an increase in our operating costs. At the beginning of the 2024 Quarter, we reached the 10-year anniversary of a certain existing life-of-lease transportation dedication, which resulted in the contractual economic step-down of the associated transportation rate. In addition, there was an increase in producer downtime in the first nine months of 2025 relative to the first nine months of 2024 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. Based on discussions with the producers from these impacted fields, the remediation work has been completed on a majority of the impacted wells during the 2025 Quarter, while intervention work is ongoing on the remaining shut-in wells in an attempt to return total production to previously experienced levels.
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:
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
Revenues (in thousands):
Inland freight revenues $ 30,929 $ 36,632 $ 98,391 $ 110,127
Offshore freight revenues 29,891 26,925 91,667 80,275
Other rebill revenues(1)
16,238 14,939 47,261 53,539
Total segment revenues $ 77,058 $ 78,496 $ 237,319 $ 243,941
Operating costs, excluding non-cash expenses (in thousands) (51,488) (47,428) (151,911) (149,967)
Segment Margin (in thousands) $ 25,570 $ 31,068 $ 85,408 $ 93,974
Fleet Utilization:(2)
Inland Barge Utilization 91.2 % 99.4 % 94.3 % 99.5 %
Offshore Barge Utilization 89.7 % 97.4 % 94.3 % 97.1 %
(1)Under certain of our marine contracts, we "rebill" our customers for a portion of our operating costs.
(2)Utilization rates are based on a 365-day year, as adjusted for planned downtime and dry-docking.
Three Months Ended September 30, 2025 Compared with Three Months Ended September 30, 2024
Marine transportation Segment Margin for the 2025 Quarter decreased $5.5 million, or 18%, from the 2024 Quarter. We experienced slightly lower utilization rates during the 2025 Quarter in our inland business primarily due to a decline in Midwest refinery demand for black oil equipment as a result of changing crude slates to lighter oil. In addition, we experienced a slight decline in utilization rates during the 2025 Quarter in our offshore business as certain third-party vessels were relocated to the East and Gulf coasts from the West Coast markets near the beginning of the 2025 Quarter, which caused disruption in the spot market. This decrease in Segment Margin was partially offset by fewer dry-docking days in our offshore fleet during the 2025 Quarter compared to the 2024 Quarter. While we did see some transitory market challenges in the period, we exited the 2025 Quarter with an uptick in demand for our inland fleet as we began to see a decrease in the lighter crude slates. In addition, we were able to secure term contracts on a majority of our offshore fleet, limiting any potential exposure to the currently volatile spot market.
Nine Months Ended September 30, 2025 Compared with Nine Months Ended September 30, 2024
Marine transportation Segment Margin for the first nine months of 2025 decreased $8.6 million, or 9% from the first nine months of 2024. We experienced slightly lower utilization rates during the first nine months of 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 2025 Quarter. In addition, our offshore business experienced a slight decline in utilization rates during the first nine months of 2025 as certain third-party vessels were relocated to the East and Gulf coasts from the West Coast markets near the beginning of the 2025 Quarter, which caused disruption in the spot market. This decrease in Segment Margin was partially offset by fewer dry-docking days in our offshore fleet and a contractual rate increase on our M/T American Phoenix during the first nine months of 2025 compared to the first nine months of 2024.
Onshore Transportation and Services Segment
Our onshore transportation and services segment includes terminaling, blending, storing, marketing, and transporting of crude oil and petroleum 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, sodium hydrosulfide (or "NaHS," commonly pronounced "nash"). Our onshore transportation and services segment utilizes an integrated set of pipelines, terminals, facilities, trucks and barges to facilitate the movement of crude oil, refined products, and other commodity 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 September 30, 2025:
•facilitating the transportation of crude oil 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 both crude oil and petroleum products.
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.
Operating results from our onshore transportation and services segment were as follows:
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
(in thousands) (in thousands)
Gathering, marketing and logistics revenue $ 136,189 $ 158,035 $ 392,424 $ 510,644
Crude oil pipeline tariffs and revenues 6,978 5,398 18,468 19,165
Sulfur services revenues, excluding non-cash revenues 33,262 36,012 106,700 121,902
Crude oil and products costs, excluding unrealized gains and losses from derivative transactions (114,701) (137,378) (335,075) (456,962)
Operating costs, excluding non-cash expenses (43,386) (45,072) (131,446) (143,138)
Other 1,321 1,767 1,876 5,491
Segment Margin $ 19,663 $ 18,762 $ 52,947 $ 57,102
Volumetric Data:
Onshore crude oil pipelines (average Bbls/day):
Texas 88,989 57,726 83,279 69,149
Jay 7,595 4,295 5,332 5,026
Mississippi 1,093 2,194 1,113 2,597
Louisiana(1)
60,551 60,255 49,050 63,084
Onshore crude oil pipelines total 158,228 124,470 138,774 139,856
Crude oil product sales (average Bbls/day) 18,327 18,978 17,881 21,364
Rail unload volumes (average Bbls/day) 25,695 17,757 23,741 12,954
NaHS volumes (Dry short tons "DST") 20,620 23,398 69,749 82,091
NaOH (caustic soda) volumes (DST sold) 9,598 10,014 26,821 30,965
(1)Total daily volumes for the three months ended September 30, 2025 and September 30, 2024 include 23,532 and 22,959 Bbls/day, respectively, of intermediate refined petroleum products and 36,414 and 37,296 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines. Total daily volumes for the nine months ended September 30, 2025 and September 30, 2024 include 19,533 and 24,159 Bbls/day, respectively, of intermediate refined petroleum products and 29,313 and 38,467 Bbls/day, respectively, of crude oil associated with our Port of Baton Rouge Terminal pipelines.
Three Months Ended September 30, 2025 Compared with Three Months Ended September 30, 2024
Onshore transportation and services Segment Margin for the 2025 Quarter increased $0.9 million, or 5%, from the 2024 Quarter primarily due to an increase in 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. This increase was partially offset by a decrease in Segment Margin from our crude oil marketing business and lower NaHS and caustic soda sales volumes.
Nine Months Ended September 30, 2025 Compared with Nine Months Ended September 30, 2024
Onshore transportation and services Segment Margin for the first nine months of 2025 decreased $4.2 million, or 7%, from the first nine months of 2024 primarily due to a decrease in Segment Margin from our crude oil marketing business and decrease in NaHS and caustic soda sales volumes. These decreases were partially offset by an increase in rail unload volumes at our Scenic Station facility.
Other Costs, Interest and Income Taxes
General and administrative expenses
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
(in thousands) (in thousands)
General and administrative expenses not separately identified below:
Corporate $ 11,423 $ 14,850 $ 33,448 $ 41,126
Segment 705 681 2,074 2,039
Long-term incentive compensation expense 2,831 (737) 9,305 4,568
Third party costs related to business development activities and growth projects
329 - 25,847 60
Total general and administrative expenses $ 15,288 $ 14,794 $ 70,674 $ 47,793
Three Months Ended September 30, 2025 Compared with Three Months Ended September 30, 2024
Total general and administrative expenses for the 2025 Quarter increased by $0.5 million from the 2024 Quarter primarily due to an increase in expenses related to our long-term incentive compensation plan as a result of the assumptions used to value the outstanding awards under our long-term incentive compensation plan. This increase was partially offset by a decrease in corporate general and administrative costs as the 2024 Quarter experiencing higher corporate general and administrative costs as a result of us conforming our short-term cash incentive programs to industry standards at that time.
Nine Months Ended September 30, 2025 Compared with Nine Months Ended September 30, 2024
Total general and administrative expenses for the first nine months of 2025 increased by $22.9 million from the first nine months of 2024. This increase is primarily due to the increase in third party costs related to business development activities and growth projects in the first quarter of 2025 as a result of the transaction costs incurred associated with the sale of the Alkali Business on February 28, 2025. This increase was partially offset due to the first nine months of 2024 experiencing higher corporate general and administrative costs as a result of us conforming our short-term cash incentive programs to industry standards at that time.
Depreciation and amortization expense
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
(in thousands) (in thousands)
Depreciation expense $ 54,486 $ 52,643 $ 161,433 $ 148,290
Amortization expense 2,582 2,932 7,711 7,843
Total depreciation and amortization expense $ 57,068 $ 55,575 $ 169,144 $ 156,133
Three Months Ended September 30, 2025 Compared with Three Months Ended September 30, 2024
Total depreciation and amortization expense for the 2025 Quarter increased by $1.5 million from the 2024 Quarter. 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 September 30, 2024.
Nine Months Ended September 30, 2025 Compared with Nine Months Ended September 30, 2024
Total depreciation and amortization expense for the first nine months of 2025 increased by $13.0 million from the first nine months of 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 September 30, 2024.
Interest expense, net
Three Months Ended
September 30, 		Nine Months Ended
September 30,
2025 2024 2025 2024
(in thousands) (in thousands)
Interest expense, senior secured credit facility (including commitment fees), net $ 3,102 $ 6,032 $ 9,990 $ 21,033
Interest expense, senior unsecured notes 62,413 69,979 196,903 199,607
Amortization of debt issuance costs, premium and discount 2,748 2,747 7,004 8,294
Capitalized interest (1,856) (13,096) (16,698) (36,399)
Interest expense, net $ 66,407 $ 65,662 $ 197,199 $ 192,535
Three Months Ended September 30, 2025 Compared with Three Months Ended September 30, 2024
Interest expense, net for the 2025 Quarter increased by $0.7 million from the 2024 Quarter primarily due to a decrease in capitalized interest in the 2025 Quarter, which is primarily attributable to the completion of the CHOPS expansion project and the SYNC Pipeline subsequent to the 2024 Quarter.
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, net 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 the 2025 Quarter was primarily a result of a reduction in the average borrowings outstanding during the period.
Nine Months Ended September 30, 2025 Compared with Nine Months Ended September 30, 2024
Interest expense, net for the first nine months of 2025 increased by $4.7 million from the first nine months of 2024 primarily due to a decrease in capitalized interest in the first nine months of 2025 primarily attributable to the completion of the CHOPS expansion project and SYNC Pipeline subsequent to September 30, 2024.
This increase in interest expense, net was partially offset by lower interest expense, net on our senior secured credit facility during the first nine months of 2025 as a result of a reduction in the average borrowings outstanding during the period primarily as a result of the proceeds received from the sale of the Alkali Business on February 28, 2025 and the immediate pay-down of the outstanding borrowings on our senior secured credit facility at that time.
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.
Liquidity and Capital Resources
General
On July 19, 2024, we entered into the Seventh Amended and Restated Credit Agreement (the "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.
On December 11, 2024 we entered into the First Amendment to the 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 for the remainder of the term.
On December 19, 2024, we issued $600.0 million in aggregate principal amount of our 8.000% senior unsecured notes due May 15, 2033 (the "2033 Notes"). The issuance of our 2033 Notes generated net proceeds of approximately $589 million, net of issuance costs incurred. We used the net proceeds to repurchase $575 million in principal of our 2027 Notes and pay a portion of the accrued interest and 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 payment of transaction costs and expenses and the assumption of our then outstanding Alkali senior secured notes by an indirect affiliate of WE Soda Ltd. We used 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 ratio calculation if our senior secured 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. 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 an ample amount of available borrowing capacity 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% 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 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 September 30, 2025, the principal amount of long-term debt outstanding totaled approximately $3.1 billion, consisting of $58.6 million borrowed under our senior secured credit facility and $3.1 billion related to our senior unsecured notes. Our senior unsecured notes balance is comprised of $679.4 million of our 2028 Notes, $600.0 million of our 8.250% senior unsecured notes due January 15, 2029 (the "2029 Notes"), $500.0 million of our 8.875% senior unsecured notes due April 15, 2030 (the "2030 Notes"), $700.0 million of our 2032 Notes and $600.0 million of our 2033 Notes.
The available borrowing capacity under our senior secured credit facility at September 30, 2025 is $736.9 million, subject to compliance with covenants. Our inventory financing sublimit as of September 30, 2025 was $28.0 million of the maximum allowed of $200.0 million. Our credit agreement does not include a "borrowing base" limitation except with respect to our inventory loans.
Shelf Registration Statement
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 and petroleum products can have a material impact on our cash flows from operating activities. In the month we pay for the stored crude oil or petroleum products, we borrow under our senior secured credit facility (or use cash on hand) to pay for the crude oil or petroleum products, 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 or petroleum products. 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.
See Note 15in our Unaudited Condensed Consolidated Financial Statements for information regarding changes in components of operating assets and liabilities during the first nine months of 2025 and the first nine months of 2024.
Net cash flows provided by our operating activities for the nine months ended September 30, 2025 were $142.0 million compared to $318.0 million for the nine months ended September 30, 2024. The decrease in cash flows from operating activities is primarily attributable to negative changes in working capital in the first nine months of 2025 relative to the first nine months of 2024. In addition, cash flows provided by operating activities for the first nine months of 2025 only included activity from the Alkali Business prior to the sale on February 28, 2025, whereas the first nine months of 2024 included a full period of activity from the Alkali Business.
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.
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:
Nine Months Ended
September 30,
2025 2024
(in thousands)
Capital expenditures for fixed and intangible assets:
Maintenance capital expenditures:
Offshore pipeline transportation assets $ 8,788 $ 5,866
Marine transportation assets 38,978 58,369
Onshore transportation and services assets 5,135 7,061
Information technology systems and corporate assets 990 2,431
Total maintenance capital expenditures 53,891 73,727
Growth capital expenditures:
Offshore pipeline transportation assets(1)
66,544 187,724
Marine transportation assets 1,415 13,897
Onshore transportation and services assets 521 8,880
Information technology systems and corporate assets - 8,230
Total growth capital expenditures 68,480 218,731
Total capital expenditures for fixed and intangible assets 122,371 292,458
Capital expenditures related to equity investees
- 285
Total capital expenditures(2)
$ 122,371 $ 292,743
(1)Growth capital expenditures in our offshore pipeline transportation segment for 2025 and 2024 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 and $66.4 million for the nine months ended September 30, 2025 and 2024, respectively, associated with the Alkali Business that was sold on February 28, 2025.
Growth Capital Expenditures
During 2022, we 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, that have a combined production capacity of approximately 200,000 barrels per day. In conjunction with these agreements, we have incurred growth capital expenditures to expand the current capacity of our CHOPS Pipeline and construct the SYNC Pipeline.
Additionally, in 2023 and 2024, we entered into several additional definitive agreements with existing producers to further commit the volumes transported on our offshore pipeline infrastructure (including our SYNC Pipeline and CHOPS Pipeline). The producer agreements include long-term take-or-pay arrangements and, accordingly, we are able to receive a project completion credit for purposes of calculating the leverage ratio under our credit agreement.
The CHOPS expansion includes a complete overhaul of the GB-72 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. During the fourth quarter of 2024, we completed the overhaul of the GB-72 topside facilities and reconnected the CHOPS Pipeline to the GB-72 platform and during the second quarter of 2025 we completed the installation of the additional pumps at the HI-A5 and GB-72 platforms.
During the 2025 Quarter, the Shenandoah FPS achieved first oil and we began successfully transporting crude oil on our 100% owned SYNC Pipeline. In addition, near the end of the 2025 Quarter, the Salamanca development achieved first oil. With the completion of these significant growth capital projects as of the end of the 2025 Quarter, and no future growth capital projects on the horizon, we expect growth capital expenditures to be minimal for the remainder of the year.
Maintenance Capital Expenditures
Maintenance capital expenditures incurred during the first nine months of 2025 and 2024 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 assets require maintenance capital expenditures to replace, maintain and upgrade equipment at certain of our offshore platforms and pipelines that we operate. See further discussion under "Available Cash before Reserves" for how such maintenance capital utilization is reflected in our calculation of Available Cash before Reserves.
Distributions to Unitholders
In July 2025, we declared our quarterly distribution to our common unitholders of $0.165 per unit related to the second quarter of 2025. With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.9473 per Class A Convertible Preferred Unit (or $3.7892 on an annualized basis) for each Class A Convertible Preferred Unit held of record. These distributions were paid on August 14, 2025 to unitholders of record at the close of business on July 31, 2025.
In October 2025, we declared our quarterly distribution to our common unitholders of $0.165 per unit related to the 2025 Quarter. With respect to our Class A Convertible Preferred Units, we declared a quarterly cash distribution of $0.9473 per Class A Convertible Preferred Unit (or $3.7892 on an annualized basis) for each Class A Convertible Preferred Unit held of record. These distributions will be payable on November 14, 2025 to unitholders of record at the close of business on October 31, 2025.
Guarantor Summarized Financial Information
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 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 10in our Unaudited Condensed Consolidated Financial Statements 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
September 30, 2025
(in thousands)
ASSETS(1):
Current assets $ 616,466
Fixed assets, net 2,186,123
Non-current assets
708,116
LIABILITIES AND CAPITAL:(2)
Current liabilities 660,461
Non-current liabilities 3,463,188
Class A Convertible Preferred Units 552,523
Statement of Operations Genesis Energy, L.P. and Guarantor Subsidiaries
Nine Months Ended
September 30, 2025
(in thousands)
Revenues(3)
$ 1,013,735
Operating costs 936,575
Operating income 77,160
Loss from continuing operations (94,893)
Net loss(2)
(514,434)
Net loss attributable to Genesis Energy, L.P. (514,434)
(1)Excluded from assets in the table above are net intercompany receivables of $57.2 million that are owed to Genesis Energy, L.P. and the Guarantor Subsidiaries from the non-Guarantor Subsidiaries as of September 30, 2025.
(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 $2.0 million of sales from Guarantor Subsidiaries to non-Guarantor Subsidiaries for the nine months ended September 30, 2025.
Non-GAAP Financial Measure Reconciliations
For definitions and discussion of our Non-GAAP financial measures refer to the "Non-GAAP Financial Measures" as later discussed and defined.
Available Cash before Reserves for the periods presented below was as follows:
Three Months Ended
September 30,
2025 2024
(in thousands)
Net income (loss) attributable to Genesis Energy, L.P. $ 9,207 $ (17,177)
Income tax expense (benefit) 253 (879)
Depreciation, amortization and accretion 59,746 58,348
Plus (minus) Select Items, net (3,656) (3,390)
Maintenance capital utilized(1)
(14,900) (18,000)
Cash tax expense (300) (300)
Distributions to preferred unitholders (14,868) (21,894)
Other non-cash items from discontinued operations(2)
- 27,782
Available Cash before Reserves $ 35,482 $ 24,490
(1)For a description of the term "maintenance capital utilized," please see the definition of the term "Available Cash before Reserves" discussed below. Maintenance capital expenditures in the 2025 Quarter and 2024 Quarter were $14.5 million and $29.2 million, respectively, which excludes maintenance capital expenditures of $25.8 million in the 2024 Quarter associated with the Alkali Business that was sold on February 28, 2025.
(2)Includes non-cash items such as depreciation, depletion and amortization and unrealized gains or losses on derivative transactions, amongst other items.
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.
Three Months Ended
September 30,
2025 2024
(in thousands)
I. Applicable to all Non-GAAP Measures
Differences in timing of cash receipts for certain contractual arrangements(1)
$ (7,091) $ (7,526)
Certain non-cash items:
Unrealized gains on derivative transactions excluding fair value hedges, net of changes in inventory value 136 63
Adjustment regarding equity investees(2)
5,233 6,855
Other (3,307) (1,551)
Sub-total Select Items, net (5,029) (2,159)
II. Applicable only to Available Cash before Reserves
Certain transaction costs 329 -
Other 1,044 (1,231)
Total Select Items, net(3)
$ (3,656) $ (3,390)
(1)Includes the difference in timing of cash receipts from or billings to 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)Represents the net effect of adding distributions from equity investees and deducting earnings of equity investees net to us.
(3)Represents Select Items applicable to Adjusted EBITDA and Available Cash before Reserves.
Non-GAAP Financial Measures
General
To help evaluate our business, this Quarterly Report on Form 10-Q includes the non-generally accepted accounting principle ("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 schedules above provide reconciliations of Available Cash before Reserves to its 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 13to our Unaudited Condensed Consolidated Financial Statements, as well as previously in this Item 2. 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 (loss); 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.
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 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 13to our Unaudited Condensed Consolidated Financial Statements, as well as previously in this Item 2.
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.
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 have been and will continue to 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 to 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.
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 initially 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.
Critical Accounting Estimates
There have been no new or material changes to the critical accounting estimates discussed in our Annual Report that are of significance, or potential significance, to the Company.
Forward Looking Statements
The statements in this Quarterly Report on Form 10-Q that are not historical information may be "forward looking statements" as defined under federal law. All statements, other than historical facts, included in this document that address activities, events or developments that we expect or anticipate will or may occur in the future, including things such as plans for growth of the business, future capital expenditures, competitive strengths, goals, references to future goals or intentions, estimated or projected future financial performance, and other such references are forward-looking statements, and historical performance is not necessarily indicative of future performance. These forward-looking statements are identified as any statement that does not relate strictly to historical or current facts. They use words such as "anticipate," "believe," "continue," "estimate," "expect," "forecast," "goal," "intend," "may," "could," "plan," "position," "projection," "strategy," "should" or "will," or the negative of those terms or other variations of them or by comparable terminology. In particular, statements, expressed or implied, concerning future actions, conditions or events (including production rates and other conditions and events), future operating results, the ability to generate sales, income or cash flow, the timing and anticipated benefits of our development projects and the expected performance of our offshore assets and other projects and business segments, the ability to simplify our capital structure and lower our cost of capital, and the availability of borrowing capacity to fund our growth capital expenditures are forward-looking statements. Forward-looking statements are not guarantees of performance. They involve risks, uncertainties and assumptions. Future actions, conditions or events and future results of operations may differ materially from those expressed in these forward-looking statements. Many of the factors that will determine these results are beyond our ability or the ability of our affiliates to control or predict. Specific factors that could cause actual results to differ from those in the forward-looking statements include, among others:
•demand for, the supply of, our assumptions about, changes in forecast data for, and price trends related to crude oil, liquid petroleum, natural gas, NaHS, and caustic soda, all of which may be affected by economic activity, capital expenditures and operational and technical issues experienced by energy producers, weather, alternative energy sources, international conflicts and international events (including the war in Ukraine, the Israel and Hamas war and broader geopolitical tensions in the Middle East and Eastern Europe), global pandemics, inflation, the actions of OPEC and other oil exporting nations, conservation and technological advances;
•our ability to successfully execute our business and financial strategies;
•our ability to continue to realize cost savings from our cost saving measures;
•throughput levels and rates;
•changes in, or challenges to, our tariff rates;
•our ability to successfully identify and close strategic acquisitions on acceptable terms (including obtaining third-party consents and waivers of preferential rights), develop or construct infrastructure assets, make cost saving changes in operations and integrate acquired assets or businesses into our existing operations;
•service interruptions in our pipeline transportation systems or processing operations, including due to adverse weather events;
•shutdowns or cutbacks at refineries, petrochemical plants, utilities, individual plants, or other businesses for which we transport crude oil, petroleum, natural gas or other products or to whom we sell petroleum or other products;
•risks inherent in marine transportation and vessel operation, including accidents and discharge of pollutants;
•changes in laws and regulations to which we are subject, including tax withholding issues, regulations regarding qualifying income, accounting pronouncements, and safety, environmental and employment laws and regulations;
•the effects of production declines resulting from a suspension of drilling in the Gulf of America or otherwise;
•the effects of future laws and regulations, including increased tariffs and proposed tariffs, taxes, duties and similar matters affecting international trade;
•planned capital expenditures and availability of capital resources to fund capital expenditures, and our ability to access the credit and capital markets to obtain financing on terms we deem acceptable;
•our inability to borrow or otherwise access funds needed for operations, expansions or capital expenditures as a result of our credit agreement and the indentures governing our notes, which contain various affirmative and negative covenants;
•loss of key personnel;
•cash from operations that we generate could decrease or fail to meet expectations, either of which could reduce our ability to pay quarterly cash distributions (common and preferred) at the current level or to increase quarterly cash distributions in the future;
•an increase in the competition that our operations encounter;
•cost and availability of insurance;
•hazards and operating risks that may not be covered fully by insurance;
•our financial and commodity hedging arrangements, which may reduce our earnings, profitability and cash flow;
•changes in global economic conditions, including capital and credit markets conditions, inflation and interest rates, including the result of any economic recession or depression that has occurred or may occur in the future;
•the impact of natural disasters, international military conflicts (such as the war in Ukraine, the Israel and Hamas war and broader geopolitical tensions in the Middle East and Eastern Europe), global pandemics, epidemics, accidents or terrorism, and actions taken by governmental authorities and other third parties in response thereto, on our business financial condition and results of operations;
•reduction in demand for our services resulting in impairments of our assets;
•changes in the financial condition of customers or counterparties;
•adverse rulings, judgments, or settlements in litigation or other legal or tax matters;
•the treatment of us as a corporation for federal income tax purposes or if we become subject to entity-level taxation for state tax purposes;
•the potential that our internal controls may not be adequate, weaknesses may be discovered or remediation of any identified weaknesses may not be successful and the impact these could have on our unit price; and
•a cyberattack involving our information systems and related infrastructure, or that of our business associates.
You should not put undue reliance on any forward-looking statements. When considering forward-looking statements, please review the risk factors described under "Risk Factors" discussed in Item 1A of our Annual Report . These risks may also be specifically described in our Quarterly Reports on Form 10-Q, Current Reports on Form 8-K (or any amendments to those reports) and other documents that we may file from time to time with the SEC. New factors that could cause actual results to differ materially from those described in forward-looking statements emerge from time to time, and it is not possible for us to predict all such factors, or the extent to which any such factor or combination of factors may cause actual results to differ from those contained in any forward-looking statement. Except as required by applicable securities laws, we do not intend to update these forward-looking statements and information.
Genesis Energy LP published this content on October 30, 2025, and is solely responsible for the information contained herein. Distributed via Edgar on October 30, 2025 at 15:37 UTC. If you believe the information included in the content is inaccurate or outdated and requires editing or removal, please contact us at [email protected]